-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, KVqUa3fMe9G2r1tW1G431u4uudcFtemYUCuhTwPpts45iT/U5py3F44cW/yNPhNc 8n8v/qY9jzIxbjBOxPw03g== 0000071180-94-000006.txt : 19940331 0000071180-94-000006.hdr.sgml : 19940331 ACCESSION NUMBER: 0000071180-94-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEVADA POWER CO CENTRAL INDEX KEY: 0000071180 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 880045330 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-04698 FILM NUMBER: 94518371 BUSINESS ADDRESS: STREET 1: 6226 W SAHARA AVE CITY: LAS VEGAS STATE: NV ZIP: 89102 BUSINESS PHONE: 7023675000 MAIL ADDRESS: STREET 1: P O BOX 230 CITY: LAS VEGAS STATE: NV ZIP: 89151 FORMER COMPANY: FORMER CONFORMED NAME: SOUTHERN NEVADA POWER CO DATE OF NAME CHANGE: 19701113 10-K 1 1993 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For fiscal year ended December 31, 1993 Commission file number 1-4698 NEVADA POWER COMPANY (Exact name of Registrant as Specified in its Charter) Nevada 88-0045330 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 6226 West Sahara Avenue 89102 Las Vegas, Nevada (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (702) 367-5000 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Title of Each Class on which Registered ------------------- --------------------- Common Stock, $1 Par Value New York Stock Exchange Pacific Stock Exchange Stock Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Cumulative Preferred Stock, $20 Par Value, 5.40% Series (Title of Class) Cumulative Preferred Stock, $20 Par Value, 5.20% Series (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- 41,944,428 shares of Common Stock were outstanding as of March 24, 1994. The aggregate market value of Common Stock, which is the only voting stock, held by non-affiliates as of March 24, 1994, was $943,749,630. (Computed by reference to the closing price on March 24, 1994, as reported by the Wall Street Journal as New York Stock Exchange Composite Transactions.) DOCUMENTS INCORPORATED BY REFERENCE (1) Portions of the Registrant's Annual Report to Shareholders for the year ended December 31, 1993 are incorporated by reference into Parts II and IV hereof. (2) Portions of the Registrant's definitive Proxy Statement dated March 14, 1994 for the Company's annual meeting of shareholders on May 6, 1994, are incorporated by reference into Part III hereof. TABLE OF CONTENTS Page PART I ---- Item 1. Business ...................................... 1 Item 2. Properties .................................... 9 Item 3. Legal Proceedings ............................. 10 Item 4. Submission of Matters to a Vote of Security Holders........................................ 11 Supplemental Item. Executive Officers of Registrant ................. 11 PART II Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters ............... 12 Item 6. Selected Financial Data ....................... 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation... 12 Item 8. Financial Statements and Supplementary Data ... 13 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........ 13 PART III Item 10. Directors and Executive Officers of the Registrant .................................... 13 Item 11. Executive Compensation ........................ 14 Item 12. Security Ownership of Certain Beneficial Owners and Management ................................ 14 Item 13. Certain Relationships and Related Transactions. 14 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ........................... 15 SIGNATURES .................................................. 29 PART I ITEM 1. BUSINESS THE COMPANY Nevada Power Company (the Company), incorporated in 1929 under the laws of Nevada, is an operating public utility engaged in the electric utility business in the City of Las Vegas and vicinity in Southern Nevada. Most of the Company's operations are conducted in Clark County, Nevada (with an estimated service area population of 916,000 at December 31, 1993) where the Company furnishes electric service in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas and to Nellis Air Force Base (a permanent military installation northeast of Las Vegas and the USAF Tactical Fighter Weapons Center). Electric service is also supplied to the Department of Energy at Mercury and Jackass Flats in Nye County, where the Nevada Test Site is located. SOURCES OF ELECTRIC ENERGY SUPPLY The electric energy obtained from the Company's own generating facilities will be produced at the following plants: Number Net Capacity Plant of Units (Megawatts) ----- -------- ------------ Coal Fuel: Reid Gardner (Steam).............. 3 330 Reid Gardner Unit No. 4 (Steam)... 1 275(1) Mohave (Steam).................... 2 178(2) Navajo (Steam).................... 3 255(3) Natural Gas and Oil Fuel: Clark (Steam)..................... 3 175 Clark (Gas Turbine).............. 1 50 Clark (Combined Cycle)............ 2 466(4) Sunrise (Steam)................... 1 80 Sunrise (Gas Turbine)............. 1 69 ----- 1,878 _________________ ===== (1) This represents 25 megawatts of base load capacity, 235 megawatts of peaking capacity and 15 megawatts upgrade capacity. Reid Gardner Unit No. 4, placed in service July 25, 1983, is a coal- fired unit which is owned 32.2% by the Company and 67.8% by the Department of Water Resources of the State of California. The Company is entitled to use 100% of the unit's capacity for 1,500 hours each year excepting that from 1993 through 1997, the Company has agreed to reduce its allocation of peaking capacity by 20 MW. The Company is entitled to 9.6% of the first 260 megawatts of capacity and associated energy and is entitled to all the 15 megawatt upgrade accomplished in 1990. Beginning in 1998, the Company has options for the use of increasing amounts of energy from the unit so that the Company may be entitled to use all of the unit's output 15 years from that date. The 1998 option for 10.17 MW was not exercised by the Company and has expired. (2) This represents the Company's 14% undivided interest in the Mohave Generating Station as tenant in common without right of partition with three other non-affiliated utilities. 1 (3) This represents the Company's 11.3% undivided interest in the Navajo Generating Station as tenant in common without right of partition with five other non-affiliated utilities. (4) This includes additional capacity of 87 MW expected to be available in April 1994, due to conversion from simple cycle combustion turbine to combined cycle operation. The Company purchases Hoover Dam power pursuant to a contract with the State of Nevada which became effective June 1, 1987 and will continue through September 30, 2017. The Company's allocation of capacity is 235 MW. The peak electric demand experienced by the Company was 2,681 megawatts on August 2, 1993. This demand plus a reserve margin was served by a combination of Company owned generation, and firm and short-term power purchases. For 1994, the Company has contracts to purchase power from an independent power producer (IPP) and four qualifying facilities (QF), also known as cogenerators, as follows: Contract Term --------------------- Net Capacity From To (Megawatts) -------- -------- ------------ Independent Power Producer: --------------------------- Nevada Sun-Peak Limited Partnership 06/08/91 05/31/16 210 Qualifying Facilities: ---------------------- Saguaro Power Company 10/17/91 04/30/22 90 Nevada Cogeneration Associates #1 06/18/92 04/30/23 85 Nevada Cogeneration Associates #2 02/01/93 04/30/23 85 Las Vegas Cogeneration Limited Partnership 06/01/94(1) 05/31/24 45 --- 515 === (1) Expected operation date. The Company's total generating capacity of 2,628 megawatts, including 235 megawatts of Hoover Dam power, 210 megawatts of IPP power and 305 megawatts of QF power, for the summer of 1994 will not be sufficient to meet the 1994 anticipated peak load demand and reserve margin needs. Accordingly, the Company has agreements with other utilities to purchase 465 megawatts of firm capacity and associated energy and plans to enter into agreements for an estimated additional 100 megawatts of firm capacity and associated energy for the months of June, July and August 1994. FUEL SUPPLIES The fuels used to provide energy for the Company's generating facilities are coal, natural gas and oil. Its other sources of electricity are hydroelectric (Hoover Dam) and purchased power. The Company's primary fuel source for generation is coal. The following table shows the actual sources of fuel for generation for 1993 and anticipated sources of fuel for generation in 1994 and 1995. 1993 1994 1995 ---- ---- ---- Coal........................ 93% 93% 93% Natural Gas................. 7 7 7 --- --- --- 100% 100% 100% === === === 2 The Company's average delivered cost per ton of coal burned was as follows: 1991 - $32.78; 1992 - $34.54; 1993 - $34.43. Coal for both the Mohave and Navajo Stations is obtained from surface mining operations conducted by Peabody Coal Company (Peabody) on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian reservations. The supply contracts with Peabody extend to December 31, 2005 for Mohave and to June 1, 2011 for Navajo, each contract having an option to extend for an additional 15 years. The anticipated full requirements for coal at the Reid Gardner Generating Station are covered by contracts through 1994. Partial requirements for coal are presently under contract through the year 2007. The Company anticipates no major difficulties in purchasing the remainder of its coal requirements based upon current coal market conditions in the Western United States. All coal for Reid Gardner presently comes from underground mines in Utah and Colorado. All of the Company's long-term coal supply contracts contain provisions providing for adjustments in the price of coal to reflect increases or decreases in the costs of mining operations. The Company's natural gas supply is subject to curtailment due to limited pipeline capacity. All the Company's plants using natural gas also have the capability of burning oil on a sustained basis. CONSTRUCTION AND FINANCING PROGRAMS The Company carries on a continuing program to extend and enlarge its facilities to meet current and future loads on its system. Gross plant additions and retirements for the five years ended December 31, 1993 amounted to $880,969,000 and $50,047,000 respectively. The following table sets forth the Company's actual construction expenditures for 1993, and currently estimated construction expenditures, including Allowance for Funds Used During Construction, for 1994 and 1995. 1993 1994 1995 -------- -------- -------- (In Thousands) Generating Facilities............ $ 74,456 $ 65,026 $ 62,769 Transmission Facilities.......... 10,112 28,812 35,724 Distribution Facilities.......... 72,865 71,160 66,017 Other............................ 15,704 9,890 10,000 -------- -------- -------- $173,137 $174,888 $174,510 ======== ======== ======== The Company's construction program and estimated expenditures are subject to continuing review and are revised from time to time due to various factors, including the rate of load growth, escalation of construction costs, availability of fuel types, changes in environmental regulations, adequacy of rate relief and the Company's ability to raise necessary capital. To meet capital expenditure requirements through 1995, the Company will utilize internally generated cash, the proceeds from industrial development revenue bonds, first mortgage bonds, and common stock issues through public offerings and the Stock Purchase and Dividend Reinvestment Plan (SPP). 3 The Company has the option of issuing new shares or using open market purchases of its common stock to meet the requirements of the SPP. The Company issued 1,640,326 shares of its common stock in 1993 under the SPP. At the end of 1993, common equity represented 46.0% of total capitalization. The Company sold 2.7 million shares of common stock for net proceeds of $65.7 million through an underwritten public offering in 1993. The net proceeds were used to reduce short-term debt which was incurred primarily to construct necessary plant facilities. On January 13, 1993, the Company sold $45 million of First Mortgage Bonds, Series Z, through a public offering. The bonds will mature in 2023 and will require interest payments due on January 1 and July 1 at the annual rate of 8.50%. Net proceeds from the sale of the bonds were used for the redemption of the Company's 9.375% Series S on February 15, 1993. The Indenture under which the Company's first mortgage bonds are issued provides that no additional bonds may be issued unless earnings as defined equal at least two and one-half times the interest requirements on all bonds to be outstanding after the new issue. Based on its earnings through December 31, 1993 and assuming an 8 1/2 percent interest rate on new bonds, the Company would be able to issue approximately $379 million of additional first mortgage bonds. The Company's ability to issue additional debt is also limited by the need to maintain a reasonable ratio of debt to equity. The Company's ability to sell additional preferred stock is limited by the necessity to meet required dividend coverages. At December 31, 1993, this test would permit the issuance of $371 million of additional preferred stock at a dividend rate of 8 1/2 percent. RESOURCE PLANNING The Company's rate of customer growth, especially in recent years, has been among the highest in the nation. The annual customer growth rate was 5.4 percent, 4.6 percent, and 5.3 percent in 1993, 1992, and 1991, respectively. The peak demand for electricity by the Company's customers increased from 2,501 megawatts in 1992 to 2,681 megawatts in 1993. The Company's 1993 energy sales reached 11,155,270 megawatthours, an increase of 5.8 percent over 1992. Every three years Nevada law requires the Company to file with the Public Service Commission of Nevada (PSC) a forecast of electricity demands for the next 20 years and the Company's plans to meet those demands. On September 16, 1991, the PSC approved the Company's 1991 Resource Plan, and during 1992 and 1993, the PSC approved the first through fourth amendments to the Resource Plan. The Resource Plan, as amended and approved in 1992 and 1993, includes the following major projects: (1) two 90 megawatt (MW) combined-cycle generating units at the Clark Generating Station, one added in 1993 and one to be added in 1994; 4 (2) the construction of two 70 (MW) combustion turbine generating units at the Harry Allen Project site, one unit in 1995 and one unit in 1996. The 1996 Allen combustion turbine will be subject to a cost comparison of purchased power resources that will be competitively bid with the least expensive resource taken as the Company's supply choice; (3) a total of 305 (MW) in purchased power from four qualifying facilities, with 175 (MW) and 85 (MW) received beginning in 1992 and 1993, respectively, and 45 (MW) expected to be received beginning in 1994; (4) planning costs for a 500 kilovolt (KV) transmission system from the Harry Allen Substation, located north of the Las Vegas Valley, to Marketplace, a future 500 KV switching station located near the McCullough Substation south of the Las Vegas Valley. The Company must present final plans on this system for PSC approval. If PSC approval is received, the transmission system could be operational by 1998; (5) installation of additional emissions reduction equipment at the Navajo Generating Station; (6) firm purchased power of 75 (MW); (7) the construction of a 230 KV transmission line from Arden Substation, located southwest of Las Vegas, to Northwest Substation, located northwest of Las Vegas; and (8) several demand-side pilot projects. On September 29, 1993, a fifth amendment to the Company's 20-year Resource Plan was filed with the PSC. On February 25, 1994, the PSC approved a stipulation among the Company, PSC Staff, Office of the Consumer Advocate and other intervenors granting the Company's request. The amendment calls for three purchase power contracts with Southern California Edison, the City of Glendale and the Salt River Project totaling 160 MWs for the years 1996 to 2000. These purchase power contracts are a result of the Company's 1996 Request for Proposal for supply-side resources. The stipulation also approved a 50 (MW) purchase power contract with Arizona Public Service for the years 1995 to 1997. The Company will file its 1994 Resource Plan on July 1, 1994. As part of the plan, the Company anticipates a portion of the supply-side resources and demand-side programs to be obtained through a Request For Proposal process. REGULATION AND RATES The Company is subject to regulation by the PSC which has regulatory powers with respect to rates, facilities, services, reports, issuance of securities and other matters. 5 Following is a summary of the rate increases or decreases that have been granted the Company during the past three years. Amount in Effective Millions Date Nature of Increase (Decrease) of Dollars ------------- ------------------------------ ---------- Jan. 1, 1991 Energy rate increase 24.4 March 4, 1991 Energy and resource plan rate increase 1.0 Nov. 12, 1991 General rate increase 12.2 Energy rate increase 11.4 July 27, 1992 General rate increase 22.2 Energy and resource plan net rate decrease (26.4) June 28, 1993 Energy and resource plan net rate increase 42.1 All amounts are on an annual basis. In 1985, the Company incurred $15.8 million in increased fuel and purchased power expenses after a ruptured steam line at the jointly owned Mohave Generating Station resulted in a loss of the plant for six months. The PSC allowed the Company to recover one half of the increased expenses subject to refund. Fourth quarter 1990 earnings reflected a $12.9 million charge to record a subsequent proposed order issued by the PSC which stated that the Company shall not recover any of the increased costs. The Company has fully reserved for any negative financial effect related to the proposed order. In 1991, the PSC set aside the proposed order and ordered the parties to participate in joint hearings before the California Public Utilities Commission (CPUC). The CPUC hearings are now concluded, and the PSC will prepare its own opinion based on the record created in the CPUC hearings. In January 1994, the administrative law judge in the CPUC proceeding issued a proposed opinion denying recovery to Southern California Edison (SCE) of its incremental purchased power costs resulting from the accident. SCE has filed comments with the CPUC concerning the proposed decision. On August 12, 1993, the Company filed a request with the PSC to recover additional fuel and purchased power costs of $29.7 million under the state's deferred energy accounting procedures. This request included $9.8 million of deferred energy costs for the period of December 1, 1992, to May 31, 1993, and $19.9 million to adjust the base energy rate. The Company subsequently amended its request to $26.8 million. Hearings in this matter were concluded in December 1993, and the PSC granted an increase in rates of $23.6 million, effective February 1, 1994. The PSC order resulted in fourth quarter 1993 charges of $2 million net of taxes for deferred energy costs. On November 19, 1993, the PSC Staff filed a petition with the PSC alleging that the Company may be overearning as much as $17 million annually because business conditions have changed substantially since the Company received its last general rate case decision in July 1992. On January 10, 1994, the PSC voted to open an investigation into the Company's earnings. Management believes the Company's earnings are within the authorized rate of return granted to the Company in July 1992. Hearings on this proceeding are scheduled to commence in June 1994. On February 28, 1994, the Company filed requests with the PSC to recover additional fuel and purchased power costs of $38.5 million and resource planning costs of $1 million. The energy rate request included 6 $28.7 million of deferred energy costs for the test period ended November 30, 1993, and $9.8 million to adjust the base energy rate. As permitted by state statute, the Company defers differences between the current cost of fuel and purchased power, and base energy costs as defined. Under regulations adopted by the PSC, the balance in the deferred energy account at the end of twelve months should be cleared, over a subsequent period. Recovery of increased costs is permitted to the extent that the Company has not realized its authorized overall rate of return. If the Company has exceeded the authorized rate of return, the portion of deferred energy costs represented in such excess is transferred to the next deferred energy recovery period. The energy costs deferred are included as a current item in determining taxable income for federal income tax purposes. However, for financial statement purposes, the federal income tax effect is deferred and amortized to income as the deferred energy account is cleared. PSC regulations allow the fuel base portion of the Company's general rates to be changed at the time of a hearing to clear the balance in the deferred energy account. This permits the recovery of fuel expenses on a deferred basis, however, recovery will have no effect on the Company's earnings. The Company is allowed to recover on an annual basis the costs of developing its 20-year resource plan. Also, by an order of the PSC in June 1988, the Company is allowed to capitalize certain costs associated with Commission approved conservation programs. ENVIRONMENTAL MATTERS The Company is subject to regulation by federal, state and local authorities with regard to air and water quality control and other environmental matters. Environmental expenditures made by the Company are currently being recovered through customer rates. Management believes environmental expenditures will increase over time and the increased costs will also be recovered as necessary utility expenses. A discussion of pending environmental matters is provided below. The Federal Clean Air Act Amendments of 1990 include provisions which will affect the Company's existing steam generating facilities and all new fossil fuel fired facilities. Title IV of the Amendments provides a national cap on sulfur dioxide emissions by mandating emissions reductions for many electric steam generating facilities. The sulfur dioxide provisions of the Amendments will not adversely affect the Company because the Company's steam units burn low sulfur fuels or have sulfur dioxide control equipment. Title IV of the Amendments also provides for reduction of emissions of oxides of nitrogen by establishing new emission limits for coal-fired generating units. This Title will require the installation of additional pollution-control technology at some of the Reid Gardner Station generating units before 2000 at an estimated cost to the Company of no more than $6 million. Other provisions of the Amendments will require the Company to install or upgrade Continuous Emission Monitoring systems at all steam generating units before 1995, at an expected cost of up to $3.3 million. The United States Congress authorized $2 million for the Environmental Protection Agency (EPA) to study the potential impact the Mohave Generating Station (MGS) may have on visibility in the Grand Canyon. The EPA report is expected to be finalized in late 1995, with a follow-up report from the Grand Canyon Visibility Transport Commission in late 1996. Also, the 7 Nevada Division of Environmental Protection has imposed more stringent stack opacity limits for the MGS. This change may affect the Company's utilization of resources, but, until more experience is gained by operating at the new opacity levels, any effect cannot be determined. As a 14 percent owner of the MGS, the Company will be required to fund any plant improvements that may result from the EPA study and operation at the new opacity levels. The cost of any potential improvements cannot be estimated at this time. In 1991, the U.S. Environmental Protection Agency published an order requiring the Navajo Generating Station (NGS) to install scrubbers to remove 90 percent of sulfur dioxide beginning in 1997. As an 11.3 percent owner of the NGS, the Company will be required to fund an estimated $46.6 million for installation of the scrubbers. In 1992, the Company received resource planning approval from the PSC for its share of the cost of the scrubbers up to $46.6 million. COMPETITION Deregulation of the electric utility industry is accelerating with the enactment of the National Energy Policy Act of 1992 (Act). Deregulation will lead to further competition in the industry as generators of power obtain greater access to transmission facilities linking them to potential new customers. Most observers believe the electric utility beneficiaries of the Act will be twofold; those who can provide low cost generation for sale and those who have strategically located transmission highways that can transmit low cost power from one area to another. Within the region the Company's residential rates are competitive. However, large industrial customer rates may require adjustment to remain competitive in the changing environment. In recognition of the changing regional competitive environment, the Company is focusing on the costs of serving various classes of customers and the appropriate rates to be charged based on those costs of service. The Company will seek through the PSC any rate adjustments necessary to maintain a competitive position. An opportunity exists given the Company's strategic location in the center of a region of price diversity. As generators arrange for sales of electricity to customers in other areas, some of the power may need to be transmitted through the Company's service territory. The Company would have an opportunity to charge the generators for the transmission of energy through its system. The Company is studying the feasibility of constructing additional cost effective transmission facilities to maximize the advantage of its strategic location. In September 1993, as a part of a comprehensive organizational study, the Company offered a voluntary early retirement package to 175 employees who would be at least 55 years of age, and have completed at least 10 years of service by March 31, 1994. A total of 109 employees, or approximately 6 percent of the work force, accepted the package. In October 1993, the Company's Board of Directors unanimously approved a new organization structure that realigns functions to improve operations and customer service. The Company expects that the net result from the change in organizational structure will be a leaner work force that operates more efficiently and makes the Company more competitive in a changing electric energy industry. At December 31, 1993, organizational study, early retirement and severance costs of $6.7 million are included in other deferred charges. EMPLOYEES The Company had 1,741 active employees at December 31, 1993. 8 ITEM 2. PROPERTIES The Company's generating facilities are described under "Item 1. Business, Sources of Electric Energy Supply". The Company shares ownership in a 59-mile, 500 kilovolt line and two 15-mile, 230 kilovolt lines that transmit power from the Mohave Generating Station near Davis Dam on the Colorado River via Eldorado Substation to Mead Substation located near Boulder City, Nevada. The Company has 32 miles of 230 kilovolt line from Mead Substation to Las Vegas. This line, together with two Company-owned 230 kilovolt lines presently connected to the Bureau of Reclamation lines between Mead Substation and Henderson, Nevada, transmit the Mohave Generating Station power to the Las Vegas area. A 25-mile, 230 kilovolt line between the Mead Substation and the Company's Winterwood Substation was energized in 1988. This line brings the additional Hoover energy to the Las Vegas Area and increases the Company's interconnected transmission capabilities. The Company shares ownership in 76 miles of 500 kilovolt transmission line from the Navajo Generating Station to the Moenkopi Switchyard in Coconino County, Arizona (the Southern Transmission System) and 274 miles of 500 kilovolt transmission line from the Navajo Generating Station to the McCullough Substation in Clark County, Nevada (the Western Transmission System). Power is transmitted from the McCullough Substation to the Las Vegas area via three 230 kilovolt lines of 23 miles, 25 miles and 32 miles in length, respectively. The 25-mile line was energized in May 1992. Two 39-mile, 230 kilovolt lines transmit power from the Reid Gardner Station located near Glendale, Nevada to the Pecos Substation near North Las Vegas. A 7 mile, 230 kilovolt line between Westside and Decatur Substations, both located in Las Vegas, was energized in 1991. In addition to the above, the Company has 263 miles of 138 kilovolt and 483 miles of 69 kilovolt transmission lines in service. In 1990 the Company added a new transmission interconnection consisting of a 345 kilovolt line from Harry Allen Substation in Southern Nevada to Red Butte Substation in Southern Utah near the City of St. George and a 230 kilovolt line from Harry Allen Substation to Westside Substation which is located in Las Vegas. The Company owns the 50-mile, 230 kilovolt line and 100 percent of the 69 miles of the 345 kilovolt line from Harry Allen Substation to the Nevada-Utah border; PacifiCorp owns 100 percent of the 345 kilovolt line portion from the Nevada-Utah border to Red Butte Substation. At December 31, 1993, the Company owned 98 transmission and distribution substations with a total installed transformer capacity of 10,186,441 kilovolt-amperes. In addition it co-owns with others the above mentioned Eldorado Substation with installed transformer capacity of 1,000,000 kilovolt-amperes, the McCullough Substation with installed transformer capacity of 1,250,000 kilovolt-amperes and the Reid Gardner Unit No. 4 Substation with installed capacity of 318,000 kilovolt-amperes. At Harry Allen Substation, the Company has a 336,000 kilovolt-ampere transformer and two 336,000 kilovolt-ampere 345 kilovolt phase shifting transformers which are used for necessary voltage transformations and to control flows on the interconnection. As of December 31, 1993, there were approximately 3,029 miles of pole line together with approximately 5,609 cable miles of underground in the Company's distribution system with a total installed distribution transformer capacity of 5,160,941 kilovolt-amperes. 9 ITEM 3. LEGAL PROCEEDINGS SUSPENDED DELIVERIES UNDER MOUNTAIN COAL COMPANY CONTRACT In December 1992, the Company suspended deliveries under a coal contract with Mountain Coal Co. based on a pricing dispute. Mountain Coal Co. filed a lawsuit in the federal district court for the State of Utah seeking a determination that the Company had repudiated the coal supply agreement. In October 1993, the court found in favor of Mountain Coal Co.'s position. The Company appealed the court's order, however, in March 1994, the Company resolved the litigation and bought out the remaining obligation under the contract by issuing a promissory note (bearing interest at 10%) for a total of $25 million. The facility using the coal under this contract is jointly owned; accordingly, the Company's portion of this settlement is $15.25 million. The settlement and buyout have been recorded as of December 31, 1993, with $25 million included in notes payable, $15.25 million included in deferred energy costs and $9.75 million included in other receivables. The settlement and buyout will result in lower fuel costs to the Company's customers over the otherwise remaining life of the contract; accordingly, based on similar past buyouts, management believes that the cost of the buyout will be recovered through Nevada's deferred energy accounting procedures. 10 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report, through the solicitation of proxies or otherwise. SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF REGISTRANT The Company's executive officers are as follows: Age as of Name December 31, 1993 Position ---- ----------------- -------- Charles A. Lenzie 56 Chairman of the Board and Chief Executive Officer James C. Holcombe 48 President and Chief Operating Officer David G. Barneby 48 Vice President, Power Delivery Cynthia K. Gilliam 45 Vice President, Retail Customer Operations Richard L. Hinckley 38 Vice President, Secretary and General Counsel Steven W. Rigazio 39 Vice President, Finance and Planning, Treasurer, Chief Financial Officer Gloria T. Banks Weddle 44 Vice President, Human Resources and Corporate Services Each of the executive officers has been actively engaged in the business of the Company for more than five years. Charles A. Lenzie was elected Chairman of the Board and Chief Executive Officer on May 1, 1989. Prior to that time he was President of the Company. James C. Holcombe joined the Company as Executive Vice President on March 1, 1989 and was elected President and Chief Operating Officer on May 1, 1989. Prior to joining the Company he was Vice President of Resource Development for San Diego Gas and Electric Company. David G. Barneby was elected Vice President, Power Delivery effective October 14, 1993. He joined the Company in 1965 as a Student Engineer and was made a Junior Engineer in 1967. He was promoted to Superintendent of the Reid Gardner Generating Station in 1976; Project Manager - Reid Gardner Unit 4 in 1979 and in 1985 appointed Manager - Generation Engineering and Construction. He was elected Vice President - Generation in 1989. His title was changed to Vice President - Power Supply later that year. Cynthia K. Gilliam was elected Vice President - Retail Customer Operations effective October 14, 1993. She joined the Company in 1974 as a Rate Analyst and was promoted to Rates Administrator in 1979 and to Manager of Financial Planning in 1983. In 1987, she was appointed Manager of Human Resource Planning. She was elected Vice President - Personnel in l988 and her title was changed to Vice President - Human Resources in l989. In 1992, she was elected Vice President - Customer Service. Richard L. Hinckley was elected Vice President, Secretary and General Counsel effective October 14, 1993. He joined the Company as Staff Counsel in l985; was promoted to Assistant Secretary and Chief Counsel in 1989 and elected Vice President, Chief Counsel and secretary in 1991. Prior to 11 joining the Company, he served as Staff Attorney with the Nevada Public Service Commission and as Assistant Attorney General in Utah. Steven W. Rigazio was elected Vice President, Finance and Planning, Treasurer, Chief Financial Officer effective October 14, 1993. He joined the Company in l984 as a Rates Administrator and was promoted to Supervisor of Rates and Regulations in l985, Manager of Rates and Regulatory Affairs in l986, Director of System Planning in l990, Vice President - Planning in 1991 and Vice President and Treasurer, Chief Financial Officer in 1992. Gloria T. Banks Weddle was elected Vice President - Human Resources and Corporate Services effective October 14, 1993. She first joined the Company in 1973, was promoted to Manager of Compensation and Benefits in 1988 and Director of Human Resources in 1991. She was elected Vice President - Human Resources in 1992. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS Information with respect to the principal market for the Company's common stock, securities exchange, shareholders of record, quarterly high and low sales prices and quarterly dividend payments for 1992 and 1991 are hereby incorporated by reference from page 43 of the Company's Annual Report to Shareholders for the year ended December 31, 1993, which is filed herewith as Exhibit 13. ITEM 6. SELECTED FINANCIAL DATA The information required by Item 6 is hereby incorporated by reference from pages 44 to 45 of the Company's Annual Report to Shareholders for the year ended December 31, 1993, which is filed herewith as Exhibit 13. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION The information required by Item 7 is hereby incorporated by reference from pages 16 to 21 of the Company's Annual Report to Shareholders for the year ended December 31, 1993, which are filed herewith as Exhibit 13. 12 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Company's financial statements for the years ended December 31, 1993, 1992 and 1991 together with the auditors' report thereon required by Item 8 are incorporated by reference from the following pages of the Company's Annual Report to Shareholders for the year ended December 31, 1993, which are filed herewith as Exhibit 13. Annual Report Page ------ Statements of Income for the Years Ended December 31, 1993, 1992 and 1991...................... 22 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991................ 23 Balance Sheets - December 31, 1993 and 1992............ 24-25 Schedules of Capitalization - December 31, 1993 and 1992............................ 26-27 Schedules of Long-Term Debt - December 31, 1993 and 1992............................ 28-29 Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991...................... 30 Notes to Financial Statements.......................... 31-41 Independent Auditors' Report........................... 42 Report of Management................................... 42 See Note 10 of Notes to Financial Statements in the Company's Annual Report to Shareholders for the unaudited selected quarterly financial data required to be presented in this Item 8. Financial statements and supplemental schedules of the Company's subsidiaries are omitted since their aggregate total assets, sales and revenues, and income before income taxes are not material in relation to the Company's total assets, sales and revenues, and income before income taxes. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There has been no Report on Form 8-K filed within the twenty-four months prior to the date of the most recent financial statements, December 31, 1993, reporting a change of accountants. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by Item 10 with respect to the Company's executive officers is set forth in Part I, Item 4., under the preceding heading "Supplemental Item. Executive Officers of Registrant". The other information required by Item 10 is hereby incorporated by reference from the Company's definitive Proxy Statement dated March 14, 1994 and heretofore filed with the Securities and Exchange Commission ("SEC"). (See the heading therein "Election of Directors".) 13 ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is hereby incorporated by reference from the Company's definitive Proxy Statement dated March 14, 1994 and heretofore filed with the SEC. (See the heading therein "Executive Compensation".) ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 is hereby incorporated by reference from the Company's definitive Proxy Statement dated March 14, 1994 and heretofore filed with the SEC. (See the heading therein "Security Ownership of Management".) ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Management of the Company has no knowledge of any transaction, relationship or indebtedness which is required to be disclosed by Item 13. 14 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K The Company's financial statements for the years ended December 31, 1993, 1992 and 1991 together with the auditors' report appearing on pages 22 to 42 of Nevada Power Company's 1993 Annual Report to Shareholders are incorporated herein by reference and filed as Exhibit 13. FINANCIAL STATEMENT SCHEDULES FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, and 1991 PAGE - ------------------------------------------------------------------------- Independent Auditors' Consent and Report on Schedules............. 24 Schedule V - Electric Plant....................................... 25-27 Schedule VI - Accumulated Depreciation............................ 25-27 Schedule VIII - Valuation and Qualifying Accounts................. 28 All other schedules and financial statements of subsidiaries not consolidated are omitted because they are not applicable, not required, or because the information is included in the financial statements or notes thereto. EXHIBITS FILED DESCRIPTION - -------------- ----------- 13 Pages 16 to 45 of Nevada Power Company's Annual Report to Shareholders for the Year Ended December 31, 1993 (incorporated by reference in Parts II and IV hereof). 10.69 Long-Term Incentive Plan dated as of January 1, 1993. 10.70 Contract for Long-Term Power Purchases from Qualifying Facilities dated May 27, 1992 between Las Vegas Co-generation, Inc. and Nevada Power Company, Replaces Exhibit 10.50. 10.71 Settlement Agreement and Promissory Note between Mountain Coal Company and Atlantic Richfield Company and Nevada Power Company dated March 9, 1994. 15 In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12B-32 and Regulation #201.24 by reference to the filings set forth below: EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 3.1 Bylaws, as amended February 9, 1984 3 to Form 10-K 1-4698 Year 1983 3.2 Restated Bylaws, as amended May 13, 1988 4.8 to Form S-3 33-33545 January 10, 1991 3.2 to Form 10-K 1-4698 Year 1990 3.3 Restated Articles of Incorporation, 2.2 to Form S-7 2-65097 filed November 7, 1978 3.4 Amendment to Restated Articles of 2.3 to Form S-16 2-67853 Incorporation, filed May 19, 1980 3.5 Amendment to Restated Articles of 3.4 to Form 10-K 1-4698 Incorporation filed May 31, 1983 Year 1983 3.6 Amendment to Restated Articles of 4.4 to Form S-3 33-4567 Incorporation, filed May 12, 1986 3.7 Amendment to Restated Articles of 4.6 to Form S-3 33-15554 Incorporation, filed May 12, 1987 3.8 Amendment to Restated Articles of 3.7 to Form 10-K 1-4698 Incorporation filed June 10, 1988 Year 1988 3.9 Restated Articles of Incorporation 3.8 to Form 10-K 1-4698 filed June 10, 1988 Year 1988 3.10 Amendment to Restated Articles of 4.7 to Form S-8 33-32372 Incorporation filed May 23, 1989. 3.11 Amendment to Restated Articles of 4.8 to Form S-3 33-55698 Incorporation filed June 8, 1992. 4.1 Certificate of Designation of Cumulative Preferred Stock as follows: 5.40% Series 2.1 to Form S-1 2-16968 5.20% Series 2.1 to Form S-1 2-20618 4.70% Series 3.2 to Form 8-K 1-4698 July 1965 8% Series 2.1 to Form S-7 2-44513 8.70% Series 2.1 to Form S-7 2-49622 11.50% Series 2.1 to Form S-7 2-52238 9.75% Series 2.1 to Form S-7 2-56788 Auction Series A 4.6 to Form S-3 33-15554 Auction Series A as amended November 14, 1991 4.9 to Form S-3 33-44460 Auction Series A as amended December 12, 1991 4.1 to Form 10-K 1-4698 Year 1992 9.90% Series 4.1 to Form 10-K 1-4698 Year 1992 4.2 Indenture of Mortgage and Deed of 4.2 to Form S-1 2-10932 Trust Providing for First Mortgage Bonds, dated October 1, 1953 and Nineteen Supplemental Indentures as follows: First Supplemental Indenture, 4.2 to Form S-1 2-11440 dated August 1, 1954 Second Supplemental Indenture, 4.9 to Form S-1 2-12566 dated September 1, 1956 Third Supplemental Indenture, 4.13 to Form S-1 2-14949 dated May 1, 1959 16 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- Fourth Supplemental Indenture, 4.5 to Form S-1 2-16968 dated October 1, 1960 Fifth Supplemental Indenture, 4.6 to Form S-16 2-74929 dated December 1, 1961 Sixth Supplemental Indenture, 4.6A to Form S-1 2-21689 dated October 1, 1963 Seventh Supplemental Indenture, 4.6B to Form S-1 2-22560 dated August 1, 1964 Eighth Supplemental Indenture, 4.6C to Form S-9 2-28348 dated April 1, 1968 Ninth Supplemental Indenture, 4.6D to Form S-1 2-34588 dated October 1, 1969 Tenth Supplemental Indenture, 4.6E to Form S-7 2-38314 dated October 1, 1970 Eleventh Supplemental Indenture, 2.12 to Form S-7 2-45728 dated November 1, 1972 Twelfth Supplemental Indenture, 2.13 to Form S-7 2-52350 dated December 1, 1974 Thirteenth Supplemental 4.14 to Form S-16 2-74929 Indenture, dated October 1, 1976 Fourteenth Supplemental 4.15 to Form S-16 2-74929 Indenture, dated May 1, 1977 Fifteenth Supplemental 4.16 to Form S-16 2-74929 Indenture dated September 1, 1978 Sixteenth Supplemental Indenture, 4.17 to Form S-16 2-74929 dated December 1, 1981 Seventeenth Supplemental 4.2 to Form 10-K 1-4698 Indenture, dated August 1, 1982 Year 1982 Eighteenth Supplemental Indenture, 4.6 to Form S-3 33-9537 dated November 1, 1986 Nineteenth Supplemental Indenture, 4.2 to Form 10-K 1-4698 dated October 1, 1989 Year 1989 Twentieth Supplemental Indenture, 4.21 to Form S-3 33-53034 dated May 1, 1992 Twenty-First Supplemental 4.22 to Form S-3 33-53034 Indenture, dated June 1, 1992 Twenty-Second Supplemental 4.23 to Form S-3 33-53034 Indenture, dated June 1, 1992 Twenty-Third Supplemental 4.23 to Form S-3 33-53034 Indenture, dated October 1, 1992 Twenty-Fourth Supplemental 4.23 to Form S-3 33-53034 Indenture, dated October 1, 1992 Twenty-Fifth Supplemental 4.23 to Form S-3 33-53034 Indenture, dated January 1, 1993 4.3 Instrument of Further Assurance 4.8 to Form S-1 2-12566 dated April 1, 1956 to Indenture of Mortgage and Deed of Trust dated October 1, 1953 4.4 Rights Agreement dated October 15, 4.1 to Form 8-A 1-4698 1990 between Manufacturers Hanover Year 1990 Trust Company and Nevada Power Company 17 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.1 Contract for Sale of Electrical 13.9A to Form S-1 2-10932 Energy between State of Nevada and the Company, dated October 10, 1941 10.2 Amendment dated June 30, 1953 to 13.9A to Form S-1 2-10932 Exhibit 10.1 10.3 Contract for Sale of Electrical 13.10 to Form S-1 2-10932 Energy between State of Nevada and the Company, dated June 1, 1951 10.4 Agreement dated November 10, 1948 13.18 to Form S-1 2-12697 between the Company and Lincoln County Power District No. 1 and Overton Power District No. 5 10.5 Agreement dated October 21, 1949 13.19 to Form S-9 2-12697 between the Company and Lincoln County Power District No. 1 and Overton Power District No. 5 10.6 Mohave Project Plant Site 13.27 to Form S-9 2-28348 Conveyance and Co-tenancy Agreement dated May 29, 1967 between the Company and Salt River Project Agricultural Improvement and Power District Southern California Edison Company 10.7 Eldorado System Conveyance and 13.30 to Form S-9 2-28348 Co-tenancy Agreement dated December 20, 1967 between the Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company 10.8 Mohave Operating Agreement dated 13.26F to Form S-1 2-38314 July 6, 1970 between the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Department of Water and Power of the City of Los Angeles 10.9 Navajo Project Participation 13.27A to Form S-1 2-38314 Agreement dated September 30, 1969 between the Company, the United States of America, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and Tucson Gas & Electric Company 18 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.10 Navajo Project Coal Supply 13.27B to Form S-1 2-38314 Agreement dated June 1, 1970 between the Company, the United States of America, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural District, Tucson Gas & Electric Company and the Peabody Coal Company 10.11 Contract dated January 1, 1968 13.32 to Form S-1 2-34588 between the Company and United States Bureau of Reclamation for interconnections at Mead Station 10.12 Note Agreement dated December 11, 5.35 to Form S-7 2-49622 1973 relating to $25,000,000 8-1/2% Promissory Notes due 1998 10.13 Reclaimed Wastewater Purchase 5.36 to Form S-7 2-52238 Agreement dated June 21, 1974 among City of Las Vegas, Nevada, Clark County Sanitation District No. 1, County of Clark, Nevada and Nevada Power Company 10.14 Equipment Lease dated as of 5.37 to Form 8-K 1-4698 March 1, 1974 between Nevada Power April 1974 Company, Lessor, and Clark County, Nevada, Lessee 10.15 Sublease Agreement dated as of 5.38 to Form 8-K 1-4698 March 1, 1974 between Clark April 1974 County, Nevada, Sublessor, and Nevada Power Company, Sublessee 10.16 Guaranty Agreement dated as of 5.39 to Form 8-K 1-4698 March 1, 1974 between Nevada April 1974 Power Company and Commerce Union Bank as Trustee 10.17 Navajo Project Co-tenancy 5.31 to Form 8-K 1-4698 Agreement dated March 23, 1976 April 1974 between the Company, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the United States of America 10.18 Amended Mohave Project Coal Supply 5.35 to Form S-7 2-56356 Agreement dated May 26, 1976 between the Company and Southern California Edison Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and the Peabody Coal Company 19 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.19 Amended Mohave Project Coal Slurry 5.36 to Form S-7 2-56356 Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) 10.20 Coal Supply Agreement dated October 5.38 to Form S-7 2-56356 15, 1975 between the Company and United States Fuel Company 10.21 Amendment dated November 19, 1976 5.30 to Form S-7 2-62105 to Exhibit 10.20 10.22 Participation Agreement Reid 5.34 to Form S-7 2-65097 Gardner Unit No. 4 dated July 11, 1979 between the Company and California Department of Water Resources 10.23 Coal Supply Agreement dated 5.37 to Form S-7 2-62509 March 1, 1980 between the Company and Beaver Creek Coal Company 10.24 Coal Supply Agreement dated 5.38 to Form S-7 2-62509 March 1, 1980 between the Company and Trail Mountain Coal Company 10.25 Coal Supply Agreement dated 10.26 to Form 10-K 1-4698 December 8, 1980 between the Year 1981 Company and Plateau Mining Company 10.26 Coal Supply Agreement dated 10.26 to Form 10-K 1-4698 August 31, 1982 between Year 1982 the Company and CO-OP Mining Company 10.27 Coal Supply Agreement dated 10.27 to Form 10-K 1-4698 September 8, 1982 between the Year 1982 Company and Getty Mining Company 10.28 Coal Supply Agreement dated 10.28 to Form 10-K 1-4698 September 8, 1982 between the Year 1982 Company and Tower Resources, Inc. 10.29 Coal Supply Agreement dated 10.29 to Form 10-K 1-4698 September 22, 1982 between the Year 1982 Company and Beaver Creek Coal Company 10.30 Memorandum of Understanding 10.30 to Form 10-K 1-4698 Concerning Interconnection Year 1983 between Utah Power & Light Company and Nevada Power Company dated February 2, 1984 10.31 Sublease Agreement between Powveg 10.31 to Form 10-K 1-4698 Leasing Corp., as Lessor and Year 1983 Nevada Power Company as Lessee, dated January 11, 1984 for lease of administrative headquarters 20 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.32 Participation Agreement between 10.32 to Form 10-K 1-4698 Utah Power & Light Company and Year 1985 the Company dated December 19, 1985 10.33 Sale and Purchase Agreement dated 10.33 to Form 10-K 1-4698 as of December 23, 1985 by and Year 1985 between Nevada Power Company and CP National Corporation 10.34 Restated Coal Sales Agreement as 10.34 to Form 10-K 1-4698 of July 1, 1985 by and between Year 1985 Nevada Power Company and Trail Mountain Coal Company 10.35 Summary of Supplemental Executive 10.35 to Form 10-K 1-4698 Retirement Plan as approved Year 1985 November 14, 1985 10.36 Financing Agreement dated as of 10.36 to Form 10-K 1-4698 February 1, 1983 between Clark Year 1985 County, Nevada and Nevada Power Company 10.37 Financing Agreement between Clark 10.37 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1985 Company dated as of December 1, 1985 10.38 Reimbursement Agreement dated 10.38 to Form 10-K 1-4698 as of December 1, 1985 between Year 1986 The Fuji Bank, Limited and Nevada Power Company 10.39 Contract for Sale of Electrical 10.39 to Form 10-K 1-4698 Energy between the State of Year 1987 Nevada and the Company, dated July 8, 1987 10.40 Power Sales Agreement between 10.40 to Form 10-K 1-4698 Utah Power & Light Company and Year 1987 the Company, dated August 17, 1987 10.41 Transmission Facilities Agreement 10.41 to Form 10-K 1-4698 between Utah Power & Light Year 1987 Company and the Company, dated August 17, 1987 10.42 Financing Agreement between Clark 10.42 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1988 Company dated as of November 1, 1988 10.43 Reimbursement Agreement dated 10.43 to Form 10-K 1-4698 as of November 1, 1988 between Year 1988 The Fuji Bank, Limited and Nevada Power Company 10.44 401(k) Savings Plan 28.1 to Form S-8 33-32372 10.45 Power Purchase Contract dated 10.45 to Form 10-K 1-4698 February 15, 1990 between Year 1989 Mission Energy Company and Nevada Power Company 21 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.46 Contact for Long-Term Power 10.46 to Form 10-K 1-4698 Purchases from Qualifying Year 1989 Facilities dated May 1, 1989 between Oxford Energy of Nevada and Nevada Power Company 10.47 Contract A for Long-Term Power 10.47 to Form 10-K 1-4698 Purchases from Qualifying Year 1989 Facilities dated May 2, 1989 between Bonneville Nevada Corporation and Nevada Power Company 10.48 Contract for Long-Term Power 10.48 to Form 10-K 1-4698 Purchases from Qualifying Year 1989 Facilities dated April 10, 1989 between Magna Energy Systems, Eastern Sierra Energy Company and Nevada Power Company 10.49 Contract B for Long-Term Power 10.49 to Form 10-K 1-4698 Purchases from a Qualifying Year 1989 Facility dated October 27, 1989 between Bonneville Nevada Corporation and Nevada Power Company 10.50 Contract for Long-Term Power 10.50 to Form 10-K 1-4698 Purchases from Qualified Year 1989 Facilities dated February 12, 1990 between Las Vegas Co-generation, Inc. and Nevada Power Company 10.51 Agreement for Transmission 10.51 to Form 10-K 1-4698 Service dated March 29, 1989 Year 1989 between Overton Power District No. 5 , Lincoln County Power District No. 1 and Nevada Power Company 10.52 Contract dated June 30, 1988 10.52 to Form 10-K 1-4698 between United States Department Year 1989 of Energy Western Area Power Administration and Nevada Power Company 10.53 Executive Performance Incentive 10.53 to Form 10-K 1-4698 Plan dated as of January 1, 1989 Year 1989 10.54 Severance Allowance Plan 10.54 to Form 10-K 1-4698 adopted September 14, 1989 Year 1989 10.55 Power Purchase Contract dated 10.55 to Form 10-K 1-4698 July 5, 1990 between Year 1990 Mission Energy Company and Nevada Power Company 10.56 Contract B for Long-Term Power 10.56 to Form 10-K 1-4698 Purchases from a Qualifying Year 1990 Facility dated May 24, 1990 between Bonneville Nevada Corporation and Nevada Power Company 10.57 Amendment dated June 15, 1989 to 10.57 to Form 10-K 1-4698 Exhibit 10.46 Year 1990 22 EXHIBIT ORIGINALLY FILED NO. DESCRIPTION AS EXHIBIT FILE NO. - ------- ----------- ---------------- -------- 10.58 Amendment dated August 23, 1989 10.58 to Form 10-K 1-4698 to Exhibit 10.46 Year 1990 10.59 Amendment dated April 23, 1990 10.59 to Form 10-K 1-4698 to Exhibit 10.46 Year 1990 10.60 Exhibit H dated August 13, 1990 10.60 to Form 10-K 1-4698 to Exhibit 10.46 Year 1990 10.61 Western Systems Power Pool 10.61 to Form 10-K 1-4698 Agreement (Agreement) dated Year 1990 January 2, 1991 between thirty-nine other Western Systems Power Pool members as listed on pages 1 and 2 of the Agreement and Nevada Power Company 10.62 Financing Agreement between Clark 10.62 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1990 Company dated June 1, 1990 10.63 Restated Power Sales Agreement 10.63 to Form 10-K 1-4698 dated March 25, 1991 between Year 1991 Pacificorp and Nevada Power Company 10.64 Amendment dated July 17, 1990 to 10.64 to Form 10-K 1-4698 Exhibit 10.55 Year 1991 10.65 Financing Agreement between Clark 10.65 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1992 Company dated June 1, 1992 (Series 1992A) 10.66 Financing Agreement between Clark 10.66 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1992 Company dated June 1, 1992 (Series 1992B) 10.67 Financing Agreement between Clark 10.67 to Form 10-K 1-4698 County, Nevada and Nevada Power Year 1992 Company dated October 1, 1992 10.68 Power Sales Agreement dated 10.68 to Form 10-K 1-4698 October 19, 1992 Between the Year 1992 Department of Water and Power of the City of Los Angeles and Nevada Power Company REPORTS ON FORM 8-K The Company filed no current report on Form 8-K during the quarter ended December 31, 1993. 23 INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULES We consent to the incorporation by reference in Registration Statement No. 33-18622 on Form S-3 and in Registration Statement No. 33-15554 on Form S-3 of Nevada Power Company of our report dated February 10, 1994 (March 11, 1994 as to the fourth paragragh of Note 7) (which expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's change in method of accounting for income taxes to conform with Statement of Financial Accounting Standards No. 109) incorporated by reference in this Annual Report on Form 10-K of Nevada Power Company for the year ended December 31, 1993. Our audits of the financial statements referred to in our aforementioned report also included the financial statement schedules of Nevada Power Company, listed in Item 14. These financial statement schedules are the responsibility of Nevada Power Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE DELOITTE & TOUCHE Las Vegas, Nevada March 28, 1994 24 NEVADA POWER COMPANY SCHEDULE V - ELECTRIC PLANT FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS OF DOLLARS) Balance at Balance at Beginning Additions Retirements End of of Period At Cost (1) and Other Period ---------- ----------- ----------- ---------- Production............$ 588,492 $ 93,859 $ (824) $ 681,527 Transmission.......... 263,807 13,869 (133) 277,543 Distribution.......... 536,644 61,923 (3,693) 594,874 General............... 77,402 7,927 (713) 84,616 Construction work-in- progress............. 172,093 (4,441) -- 167,652 Property under capital lease................ 96,753 -- (5,236) 91,517 Plant held for future use.................. 4,442 -- (723) 3,719 ---------- ----------- ----------- ---------- $1,739,633 $ 173,137 $ (11,322) $1,901,448 ========== =========== =========== ========== SCHEDULE VI - ACCUMULATED DEPRECIATION FOR THE YEAR ENDED DECEMBER 31, 1993 (IN THOUSANDS OF DOLLARS) Balance at Salvage, Less Balance at Beginning Cost of End of of Period Provisions(2) Removal Retirements Period ---------- ----------- ---------- --------- --------- Production...$ 250,545 $ 19,919 $ (87) $ (823) $ 269,554 Transmission. 50,030 6,658 (108) (133) 56,447 Distribution. 98,355 14,817 121 (2,717) 110,576 General...... 12,755 3,104 74 (713) 15,220 Retirement work- in-progress. (722) -- 227 -- (495) ---------- ----------- ---------- --------- --------- $ 410,963 $ 44,498 $ 227 $ (4,386) $ 451,302 ========== =========== ========== ========= ========= ______________ (1) Additions include Allowance for Funds Used During Construction capitalized in the amount of $9,880,000. (2) Provisions include $43,341,000 charged to income and $1,157,000 charged to other accounts. The depreciation provision on the statement of income includes additional amounts for amortization of the electric plant acquisition adjustments in the amount of $17,000. 25 NEVADA POWER COMPANY SCHEDULE V - ELECTRIC PLANT FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS OF DOLLARS) Balance at Balance at Beginning Additions Retirements End of of Period At Cost (1) and Other Period ---------- ----------- ----------- ---------- Production............$ 577,565 $ 12,222 $ (1,295) $ 588,492 Transmission.......... 235,282 28,719 (194) 263,807 Distribution.......... 460,406 66,383 9,855 (2) 536,644 General............... 70,917 8,913 (2,428) 77,402 Construction work-in- progress............. 112,257 62,382 (2,546)(3) 172,093 Property under capital lease................ 96,358 -- 395 96,753 Plant held for future use.................. 9,706 -- (5,264)(4) 4,442 ---------- ----------- ----------- ---------- $1,562,491 $ 178,619 $ (1,477) $1,739,633 ========== =========== =========== ========== SCHEDULE VI - ACCUMULATED DEPRECIATION FOR THE YEAR ENDED DECEMBER 31, 1992 (IN THOUSANDS OF DOLLARS) Balance at Salvage, Less Balance at Beginning Cost of End of of Period Provisions(5) Removal Retirements Period ---------- ----------- ---------- --------- --------- Production...$ 233,539 $ 18,190 $ 111 $ (1,295) $ 250,545 Transmission. 44,151 6,102 (40) (183) 50,030 Distribution. 86,574 14,925 266 (3,410) 98,355 General...... 12,229 2,910 44 (2,428) 12,755 Retirement work- in-progress. (726) -- 4 -- (722) ---------- ----------- ---------- --------- --------- $ 375,767 $ 42,127 $ 385 $ (7,316) $ 410,963 ========== =========== ========== ========= ========= ______________ (1) Additions include Allowance for Funds Used During Construction capitalized in the amount of $7,544,000. (2) Included in retirements and other is $13,567,000 for AFUDC on Industrial Development Revenue Bond Trust Fund balances reclassified from other deferred charges. (3) Included in retirements and other is $2,546,000 for costs related to a property loss at Reid Gardner Generating Station No. 4 which were reclassified to other deferred charges. (4) Included in retirements and other is $5,794,000 reclassified as property under capital lease. (5) Provisions include $39,433,000 charged to income and $2,694,000 charged to other accounts. The depreciation provision on the statement of income includes additional amounts for amortization of the electric plant acquisition adjustments in the amount of $18,000. 26 NEVADA POWER COMPANY SCHEDULE V - ELECTRIC PLANT FOR THE YEAR ENDED DECEMBER 31, 1991 (IN THOUSANDS OF DOLLARS) Balance at Balance at Beginning Additions Retirements End of of Period At Cost (1) and Other Period ---------- ----------- ----------- ---------- Production............$ 562,858 $ 20,347 $ (5,640) $ 577,565 Transmission.......... 217,852 18,214 (784) 235,282 Distribution.......... 400,869 76,386 (16,849)(2) 460,406 General............... 63,597 8,013 (693) 70,917 Construction work-in- progress............. 75,946 30,992 5,319 (3) 112,257 Property under capital lease................ 18,199 83,000 (5) (4,841) 96,358 Plant held for future use.................. 5,786 3,188 732 (4) 9,706 ---------- ----------- ----------- ---------- $1,345,107 $ 240,140 $ (22,756) $1,562,491 ========== =========== =========== ========== SCHEDULE VI - ACCUMULATED DEPRECIATION FOR THE YEAR ENDED DECEMBER 31, 1991 (IN THOUSANDS OF DOLLARS) Balance at Salvage, Less Balance at Beginning Cost of End of of Period Provisions(6) Removal Retirements Period ---------- ----------- ---------- --------- --------- Production...$ 217,606 $ 19,807 $ 1,766 $ (5,640) $ 233,539 Transmission. 39,999 5,001 (65) (784) 44,151 Distribution. 80,618 9,084 152 (3,280) 86,574 General...... 10,633 2,151 38 (593) 12,229 Retirement work- in-progress. (634) -- (92) -- (726) ---------- ----------- ---------- --------- --------- $ 348,222 $ 36,043 $ 1,799 $ (10,297) $ 375,767 ========== =========== ========== ========= ========= ______________ (1) Additions include Allowance for Funds Used During Construction capitalized in the amount of $6,051,000. (2) Included in retirements and other is $13,567,000 for AFUDC over- accrued on Industrial Development Revenue Bond Trust Fund balances and reclassified to other deferred charges to be amortized over eight years. (3) Included in retirements and other is $5,319,000 for costs related to the Company's Harry Allen Generating Facility project which were reclassified from other deferred charges. (4) Included in retirements and other is $732,000 for amortization and interest cost for l991 reclassified as plant held for future use. (5) Additions include $83,000,000 for a capitalized lease which was recorded as a result of a power purchase contract between the Company and Mission Energy Company. (6) Provisions include $34,663,000 charged to income and $l,380,000 charged to other accounts. The depreciation provision on the statement of income includes additional amounts for amortization of the electric plant acquisition adjustments in the amount of $485,000. 27 NEVADA POWER COMPANY SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS OF DOLLARS) Reserve for Doubtful Accounts ---------- BALANCE AT DECEMBER 31, 1990............................. $ 924 Provision charged to income............................. 2,487 Amounts written off, less recoveries.................... (2,305) ------- BALANCE AT DECEMBER 31, 1991............................. $ 1,106 Provision charged to income............................. 2,068 Amounts written off, less recoveries.................... (2,371) ------- BALANCE AT DECEMBER 31, 1992............................. $ 803 Provision charged to income............................. 3,161 Amounts written off, less recoveries.................... (2,839) ------- BALANCE AT DECEMBER 31, 1993............................ $ 1,125 ======= 28 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. NEVADA POWER COMPANY ------------------------------------- (Registrant) March 28, 1994 By CHARLES A. LENZIE ------------------------------------- Charles A. Lenzie Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. March 28, 1994 By CHARLES A. LENZIE ------------------------------------- Charles A. Lenzie, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer) March 28, 1994 By STEVEN W. RIGAZIO ------------------------------------- Steven W. Rigazio, Vice President, Finance and Planning, Treasurer, Chief Financial Officer (Principal Financial and Principal Accounting Officer) March 28, 1994 By JAMES CASHMAN III ------------------------------------- James Cashman III, Director March 28, 1994 By MARY LEE COLEMAN ------------------------------------- Mary Lee Coleman, Director March 28, 1994 By FRED D. GIBSON JR. ------------------------------------- Fred D. Gibson Jr., Director March 28, 1994 By JOHN L. GOOLSBY ------------------------------------- John L. Goolsby, Director March 28, 1994 By JERRY HERBST ------------------------------------- Jerry Herbst, Director March 28, 1994 By JAMES C. HOLCOMBE ------------------------------------- James C. Holcombe, President and Director March 28, 1994 By CONRAD L. RYAN ------------------------------------- Conrad L. Ryan, Director March 28, 1994 By FRANK E. SCOTT ------------------------------------- Frank E. Scott, Director March 28, 1994 By ARTHUR M. SMITH ------------------------------------- Arthur M. Smith, Director March 28, 1994 By JELINDO A. TIBERTI ------------------------------------- Jelindo A. Tiberti, Director 29 EX-13 2 PAGES 16 TO 45 OF ANNUAL REPORT TO SHAREHOLDERS Management's Discussion and Analysis Of Financial Condition and Results of Operations Liquidity and Capital Resources RESOURCE DEVELOPMENT AND CONSTRUCTION PROGRAMS Every three years Nevada law requires the company to file with the Public Service Commission of Nevada (PSC) a forecast of electricity demands for the next 20 years and the company's plans to meet those demands. On September 16, 1991, the PSC approved the company's 1991 Resource Plan, and during 1992 and 1993, the PSC approved the first through fourth amendments to the Resource Plan. The Resource Plan, as amended and approved in 1992 and 1993, includes the following major projects: - - two 90 megawatt (MW) combined-cycle generating units at the Clark Generating Station, one added in 1993 and one to be added in 1994; - - the construction of two 70 MW combustion turbine generating units at the Harry Allen Project site, one unit in 1995 and one unit in 1996. The 1996 Allen combustion turbine will be subject to a cost comparison of purchased power resources that are being competitively bid with the least expensive resource taken as the company's supply choice; - - a total of 305 MW in purchased power from four qualifying facilities, with 175 MW and 85 MW received beginning in 1992 and 1993, respectively, and 45 MW expected to be received beginning in 1994; - - planning costs for a 500 kilovolt (KV) transmission system from the Harry Allen Substation, located north of the Las Vegas Valley, to Marketplace, a future 500 KV switching station located near the McCullough Substation south of the Las Vegas Valley. The company must present final plans on this system for PSC approval. If PSC approval is received, the transmission system could be operational by 1998; - - installation of additional emissions reduction equipment at the Navajo Generating Station; - - firm purchased power of 75 MW; - - the construction of a 230 KV transmission line from Arden Substation, located southwest of Las Vegas, to Northwest Substation, located northwest of Las Vegas; and - - several demand-side pilot projects. On September 29, 1993, a fifth amendment to the company's 20-year Resource Plan was filed with the PSC. On February 25, 1994, the PSC approved a stipulation among the company, PSC Staff, Office of the Consumer Advocate and other intervenors granting the company's request. The amendment calls for three purchase power contracts with Southern California Edison, the City of Glendale and the Salt River Project totaling 160 MWs for the years 1996 to 2000. These purchase power contracts are a result of the company's 1996 Request for Proposal for supply-side resources. The stipulation also approved a 50 MW purchase power contract with Arizona Public Service for the years 1995 to 1997. The company will file its 1994 Resource Plan on July 1, 1994. As part of the plan, the company anticipates a portion of the supply-side resources and demand-side programs to be obtained through a Request For Proposal process. Budgeted construction expenditures for 1994 and 1995 are $175 million annually including allowance for funds used during construction. For the next five years customer growth is estimated to average 5.0 percent per year while demand for electricity is estimated to increase by an average of 4.3 percent per year. FINANCIAL STRATEGIES Nevada Power Company customer growth averaged over 5.1 percent during each of the three years ended December 31, 1993. To meet the growth forecasted for the company's service territory for the mid 1990s, the company will continue to rely upon the financial markets to provide a substantial portion of the funds to build necessary company-owned facilities. The company is committed to maintaining shareholder value throughout this period of continuing rapid growth. To achieve this goal the company will: - - seek appropriate and timely rate relief from regulators; - - pursue a balanced financing approach utilizing low cost tax-exempt financing when possible; - - maintain ongoing cost containment efforts; and - - seek legislative and regulatory support when necessary. 16 Nevada Power Company Cost Containment - The company has and will continue to review all planned construction and operating expenditures in an effort to reduce the level of external financing required during this period of rapid growth. Management is constantly reviewing expenditures in light of its commitment to provide shareholders with returns that deliver long-term shareholder value, deliver quality service to customers and provide a reliable supply of electricity at reasonable prices. CAPITALIZATION To meet capital expenditure requirements through 1995, the company will utilize internally generated cash, the proceeds from industrial development revenue bonds (IDBs), first mortgage bonds (FMBs), and common stock issues through public offerings and the Stock Purchase and Dividend Reinvestment Plan (SPP). New Financing Capacity - Under the tests required by the company's FMBs and the terms of its preferred stock issues, as of December 31, 1993, the company could issue up to $379 million of additional FMBs at an assumed interest rate of 8 1/2 percent and up to $371 million of additional preferred stock at an assumed dividend of 8 1/2 percent. The company has received PSC approval for authority through December 31, 1994 to issue up to 2 million shares of common stock, $70 million of new taxable debt and $195 million of fixed rate bonds for the purpose of refinancing certain existing fixed and floating rate bonds. Earnings to Interest and Preferred Dividends Coverage - For the year 1993, the ratio of earnings to interest charges was 3.47 times compared to 2.42 times in 1992. The ratio of earnings to interest charges plus preferred dividends was 3.06 times in 1993 compared to 2.18 times in 1992. Common Equity - In June 1993, the company sold by public offering 2,700,000 shares of common stock. The net proceeds of $65.7 million were used to reduce short-term debt which was incurred primarily to construct necessary plant facilities. The company has the option to issue new common shares or purchase shares on the open market to satisfy the needs of the SPP. During 1993, the company issued $40.8 million of common stock under the SPP. (See Note (a) of "Notes to Schedules of Capitalization.") At year end, common equity represented 46.0 percent of total capitalization. Short-Term Debt - The company has received regulatory approval to issue short- term debt up to $150 million for the period 1992 through 1994 and has a committed bank line for $125 million which expires on December 31, 1994. The bank line requires that the company obtain the bank group's approval prior to incurring additional unsecured debt. The short-term financing is expected to be utilized to fund some of the company's construction expenditures until long- term financing is secured. At December 31, 1993, the company had no balance outstanding on this line. Long-Term Debt - On June 24, 1992, Clark County, Nevada issued $105 million 6.70% fixed rate 30-year IDBs (Nevada Power Company Project) Series 1992A. Net proceeds from the sale of the IDBs were placed on deposit with a trustee and are being used to finance the construction of certain facilities which qualify for tax-exempt financing. At December 31, 1993, $59.1 million remained on deposit with the trustee. REGULATION Adequate and timely rate relief will be an important factor in determining the company's ability to finance the major construction program the company faces over the next few years. Generally, the PSC allows recovery of costs on an historical basis in setting rates charged to customers for electrical service. Environmental expenditures made by the company are currently being recovered through customer rates. Management believes environmental expenditures will increase over time and the increased costs will also be recovered as necessary utility expenses. A discussion of pending environmental matters is contained in Note 7 of "Notes to Financial Statements." Nevada Power Company 17 Management's Discussion and Analysis Of Financial Condition and Results of Operations Pending Rate Matters - On February 28, 1994, the company filed requests with the PSC to recover additional fuel and purchased power costs of $38.5 million and resource planning costs of $1 million. The energy rate request included $28.7 million of deferred energy costs for the test period ended November 30, 1993, and $9.8 million to adjust the base energy rate. On November 19, 1993, the PSC Staff filed a petition with the PSC alleging that the company may be overearning as much as $17 million annually because business conditions have changed substantially since the company received its last general rate case decision in July 1992. On January 10, 1994, the PSC voted to open an investigation into the company's earnings. Management believes the company's earnings are within the authorized rate of return granted to the company in July 1992. Hearings on this proceeding are scheduled to commence in June 1994. The company has fully reserved for any negative financial effect related to a February 6, 1991, proposed order by the PSC which, if adopted, would require the company to bear the full cost of replacement power and related expenses resulting from a 1985 accident at the Mohave Generating Station. Earnings for the fourth quarter of 1990 included an after-tax charge of $12.9 million for this proposed order. On June 17, 1991, the PSC issued another order setting aside the proposed order and ordered the parties to participate in joint hearings before the California Public Utilities Commission (CPUC). The CPUC hearings are now concluded, and the PSC will prepare its own opinion based on the record created in the CPUC hearings. In January 1994, the administrative law judge in the CPUC proceeding issued a proposed opinion denying recovery to Southern California Edison (SCE) of its incremental purchased power costs resulting from the accident. SCE has filed comments with the CPUC concerning the proposed decision. Concluded Rate Matters - Effective February 1, 1994, the PSC granted the company a $23.6 million increase in the energy portion of customer rates. (See Note 7 of "Notes to Financial Statements.") The table below summarizes the rate adjustments that have been granted to the company during the past three years. Summary of Rate Adjustments 1991 through 1993 Effective Date Nature of Increase (Decrease) Amount (In millions) ____________________________________________________________________________ Jan. 1, 1991 Energy rate increase $24.4 March 4, 1991 Energy and resource plan rate increase 1.0 Nov. 12, 1991 General rate increase 12.2 Energy rate increase 11.4 July 27, 1992 General rate increase 22.2 Energy and resource plan net rate decrease (26.4) June 28, 1993 Energy and resource plan net rate increase 42.1 ____________________________________________________________________________ DEREGULATION AND COMPETITION Deregulation of the electric utility industry is accelerating with the enactment of the National Energy Policy Act of 1992 (Act). Deregulation will lead to further competition in the industry as generators of power obtain greater access to transmission facilities linking them to potential new customers. Most observers believe the electric utility beneficiaries of the Act will be twofold; those who can provide low cost generation for sale and those who have strategically located transmission highways that can transmit low cost power from one area to another. 18 Nevada Power Company Within the region the company's residential rates are competitive. However, large industrial customer rates may require adjustment to remain competitive in the changing environment. In recognition of the changing regional competitive environment, the company is focusing on the costs of serving various classes of customers and the appropriate rates to be charged based on those costs of service. The company will seek through the PSC any rate adjustments necessary to maintain a competitive position. An opportunity exists given the company's strategic location in the center of a region of price diversity. As generators arrange for sales of electricity to customers in other areas, much of the power may need to be transmitted through the company's service territory. The company would have an opportunity to charge generators for the transmission of energy through its system. The company is studying the feasibility of constructing additional cost effective transmission facilities to maximize the advantage of its strategic location. OTHER In September 1993, as a part of a comprehensive organizational study, the company offered a voluntary early retirement package to 175 employees who would be at least 55 years of age, and have completed at least 10 years of service by March 31, 1994. A total of 109 employees, or approximately 6 percent of the work force, accepted the package. In October 1993, the company's Board of Directors unanimously approved a new organization structure that realigns functions to improve operations and customer service. The company expects that the net result from the change in organizational structure will be a leaner work force that operates more efficiently and makes the company more competitive in a changing electric energy industry. At December 31, 1993, organizational study, early retirement and severance costs of $6.7 million are included in other deferred charges. (See Note 8 of "Notes to Financial Statements.") The company and the International Brotherhood of Electrical Workers Local 396 signed new Collective Bargaining Agreements for the company's plant and clerical employees in January and February 1994, respectively. The four-year plant and clerical agreements, effective February 1 and May 1, 1994, respectively, each provide for base wage increases of 4% in 1994, 3.5% in 1995, 3.25% in 1996 and a 4% lump sum increase in 1997. The company has adopted Statement of Financial Accounting Standards No. 106 (FAS 106), Employers' Accounting for Postretirement Benefits Other Than Pensions (See Note 3 of "Notes to Financial Statements") and No. 109 (FAS 109), Accounting for Income Taxes (See Note 2 of "Notes to Financial Statements") effective January 1, 1993. The increase in 1993 of other deferred charges and other deferred credits primarily reflects adjustments related to the adoption of FAS 106 and FAS 109. (See Note 8 of "Notes to Financial Statements.") In March 1994, the company resolved certain litigation and bought out the remaining obligation under a coal purchase contract. The company's portion of the settlement and buyout is $15.25 million. Management believes the cost of the buyout will be recovered through Nevada's deferred energy accounting procedures. (See Note 7 of "Notes to Financial Statements.") Results of Operations GENERAL In 1993, earnings increased, as compared to 1992, due primarily to higher revenues resulting from an increase in general rates effective July 1992 and an increase in kilowatthour sales. In 1992, earnings increased, as compared to 1991, due primarily to higher revenues resulting from two increases in general rates effective November 1991 and July 1992. Average shares of common stock outstanding for 1993 increased by 3.8 million shares compared to 1992, as a result of public offerings of 2.7 million shares in June of 1993 and 2.99 million shares in April 1992. REVENUES Revenues during 1993, 1992 and 1991 were $652 million, $601 million and $546 million, respectively. The 8.5 percent increase in 1993, as compared to 1992, was a result of a 5.8 percent increase in kilowatthour sales and an increase in energy rates effective June of 1993. The 10 percent increase in 1992, as compared to 1991, was a result of a 7.2 percent increase in kilowatthour sales and increases in general and energy rates effective November 1991. Nevada Power Company 19 Management's Discussion and Analysis Of Financial Condition and Results of Operations Increase (Decrease) in Revenue From Prior Year Nature of Increase (Decrease) (In millions) 1993 1992 1991 _______________________________________________________________________________ Kilowatthour sales $28.2 $37.7 $19.1 General rate changes 12.3 20.5 (0.3) Deferred energy adjustments (13.3) (5.3) 5.4 Fuel cost base rate changes 22.4 0.4 26.9 Resource plan cost changes and other 1.3 1.2 3.0 ------------------------- Total increase $50.9 $54.5 $54.1 ========================= _______________________________________________________________________________ FUEL AND PURCHASED POWER In 1993, as compared to 1992, and in 1992, as compared to 1991, purchased power expense increased 21.1 percent and 51.6 percent, respectively, due to increased purchases from qualifying facilities. Effective June 28, 1993, the PSC granted the company a $44.2 million increase in the energy portion of customer rates, and effective July 27, 1992, the PSC granted the company a $28.3 million decrease in energy rates. During 1993, the company deferred $48.5 million of increased energy costs for collection in a later period and collected $17 million of energy cost increases which had previously been deferred. During 1992, the company deferred $39.5 million of increased energy costs for collection in a later period and collected $26.6 million of energy cost increases which had previously been deferred. Recovery of fuel expenses is administered under the state's deferred energy cost accounting procedures. (See Note 1 of "Notes to Financial Statements.") Under the deferred energy procedure, changes in the costs of fuel and purchased power are reflected in customer rates through annual rate adjustments and do not affect earnings. The following tables summarize the source of kilowatthours sold, the percentage of company generated kilowatthours by fuel source and fuel costs per kilowatthour. 1993 1992 1991 _______________________________________________________________________________ Source of Kilowatthours Sold Company generation 49% 49% 55% Hoover Dam hydroelectric 4 4 5 Purchased power 47 47 40 --------------------------------- 100% 100% 100% ================================= Company Generated Kilowatthours By Fuel Source Coal 93% 94% 94% Natural Gas 7 5 5 Oil - 1 1 --------------------------------- 100% 100% 100% ================================= Fuel Costs Per Kilowatthour Coal 1.61 cents 1.63 cents 1.56 cents Natural Gas 2.98 3.83 3.53 Oil 4.21 4.74 6.42 _______________________________________________________________________________ 20 Nevada Power Company OTHER OPERATING EXPENSES AND TAXES Other operations expense increased by $5.5 million in 1993, as compared with 1992, primarily due to an increase in administrative and general expenses resulting mainly from increased labor costs, computer system conversion costs and an increase in the provision for uncollectible accounts. The $7.2 million increase in other operations expense for 1992 was due mainly to an increase in employee medical benefit costs, employee pension expenses and an increase in resource planning costs. The level of maintenance and repair expenses depends primarily upon the scheduling, magnitude and number of unit overhauls at the company's generating stations. During 1993, these expenses decreased by $2.5 million due primarily to lower maintenance costs at the Reid Gardner and Navajo Generating Stations. During 1992, as compared to 1991, these expenses decreased by $10 million due to major maintenance expenses at the Reid Gardner and Mohave Generating Stations in 1991. Depreciation expense increased $3.9 million in 1993 and $4.3 million in 1992 primarily because of a growing electric plant asset base. In addition, the average annual depreciation rate increased from approximately 2.8 percent to 2.9 percent effective November 1991. General taxes increased by $2.3 million in 1993 primarily due to higher assessed property values and rates for property tax purposes. OTHER INCOME AND EXPENSES Other miscellaneous, net includes a charge of $3.2 million net of tax in the fourth quarter of 1993 for a write-off of costs related to environmental and engineering studies for the cancelled coal-fired White Pine Power Project. A rate decision by the PSC on January 24, 1994, resulted in a write-off of $2 million net of tax in the fourth quarter of 1993 for previously deferred energy costs. (See Note 7 of "Notes to Financial Statements.") Other miscellaneous, net includes a charge of $2.6 million net of tax in the fourth quarter of 1992 for a write-off of costs related to the property loss on a faulty cooling tower at the company's Reid Gardner Generating Station unit 4 and associated legal fees. On August 4, 1992, the PSC issued an order resulting in a write-off of $2.4 million net of tax for previously deferred energy costs. On November 26, 1991, the PSC issued an order associated with requests by the company for a general rate increase and an increase to recover certain fuel and purchased power costs. The PSC order resulted in write-offs during the fourth quarter of 1991 to other miscellaneous, net which included a charge of $1.9 million net of tax applicable to a cancelled coal-fired generating station as well as a charge of $2.3 million net of tax for deferred energy costs. FINANCING EXPENSES Interest on long-term debt increased $2.0 million in 1992, as compared to 1991, primarily as a result of interest on IDBs issued in June 1992, offset partially by lower interest costs on several issues of long-term debt refinanced at lower interest rates and interest income on IDB proceeds held in trust. Other interest expenses decreased by $1.3 million during 1992, as compared to 1991, because of less short-term borrowing. Nevada Power Company 21 Statements of Income For the Years Ended Dec. 31, (In thousands, except per share amounts) 1993 1992 1991 ______________________________________________________________________________ Electric Revenues (Notes 1 and 7) $651,772 $600,915 $546,411 ---------------------------- Operating Expenses and Taxes: Fuel 98,701 96,563 98,084 Purchased and interchanged power 242,803 200,344 132,117 Deferred energy cost adjustments, net (Note 1) (31,490) (12,834) 38,533 ---------------------------- Net energy costs 310,014 284,073 268,734 Other production operations 17,715 17,594 17,795 Other operations 83,158 77,697 70,454 Maintenance and repairs 35,379 37,911 47,928 Provision for depreciation (Note 1) 43,358 39,450 35,148 General taxes (Note 2) 16,401 14,093 12,727 Federal income taxes (Notes 1 and 2) 37,278 29,975 16,198 ---------------------------- 543,303 500,793 468,984 ---------------------------- Operating Income 108,469 100,122 77,427 ---------------------------- Other Income (Expenses): Allowance for other funds used during construction (Note 1) 9,880 8,251 4,172 Other miscellaneous, net (Note 7) (5,496) (10,127) (6,285) ---------------------------- 4,384 (1,876) (2,113) ---------------------------- Income Before Interest Deductions 112,853 98,246 75,314 ---------------------------- Interest Deductions: Interest on long-term debt 43,173 43,500 41,518 Other interest 1,931 2,185 3,468 Allowance for borrowed funds used during construction (Note 1) (5,799) (4,219) (4,848) ---------------------------- 39,305 41,466 40,138 ---------------------------- Net Income 73,548 56,780 35,176 Dividend Requirements on Preferred Stock 3,986 4,262 2,880 ---------------------------- Earnings Available for Common Stock $ 69,562 $ 52,518 $ 32,296 ============================ Weighted Average Common Shares Outstanding 39,482 35,652 30,855 ============================ Earnings per Average Common Share $ 1.76 $ 1.47 $ 1.05 ============================ See Notes to Financial Statements. ______________________________________________________________________________ 22 Nevada Power Company Statements of Retained Earnings For the Years Ended Dec. 31, (In thousands) 1993 1992 1991 _______________________________________________________________________________ Balance at Beginning of Period $102,493 $107,516 $123,963 Add - Net Income 73,548 56,780 35,176 -------------------------------- 176,041 164,296 159,139 -------------------------------- Deduct: Dividends paid in cash: Cumulative preferred stock - 5.40%, 5.20% and 4.70% Series 224 233 243 9.90% Series (Note 6) 3,762 4,572 2,264 Common stock 62,696 56,998 49,116 -------------------------------- 66,682 61,803 51,623 -------------------------------- Balance at End of Period $109,359 $102,493 $107,516 ================================ See Notes to Financial Statements. _______________________________________________________________________________ Nevada Power Company 23 Balance Sheets December 31, (In thousands) 1993 1992 _____________________________________________________________________________ Assets Electrical Plant, at Original Cost (Notes 1, 7 and 9): Production $ 681,527 $ 588,493 Transmission 277,543 263,807 Distribution 594,874 536,644 General 84,616 77,402 ----------------------- 1,638,560 1,466,346 Less accumulated depreciation 451,302 410,963 ----------------------- Net plant in service 1,187,258 1,055,383 Construction work in progress 167,652 172,092 Property under capital leases 91,517 96,753 Plant held for future use 3,719 4,442 ----------------------- 1,450,146 1,328,670 ----------------------- Investments (Notes 1 and 7) 21,822 19,339 ----------------------- Current Assets: Cash and temporary cash investments 145 160 Customer receivables - Billed 37,270 33,988 Unbilled (Note 1) 13,000 9,945 Reserve for doubtful accounts (1,125) (803) Other receivables (Note 7) 15,465 7,139 Fuel stock, at average cost 16,613 21,717 Materials and supplies, at average cost (Note 8) 23,714 24,099 Deferred energy costs (Notes 1 and 7) 74,033 24,708 Prepayments 8,313 9,151 ----------------------- 187,428 130,104 ----------------------- Deferred Charges: Debt expense, being amortized 28,645 25,503 Accumulated deferred taxes on proposed refund of recovered energy costs - Mohave accident (Note 7) 5,417 6,055 Other (Note 8) 115,879 47,369 ----------------------- 149,941 78,927 ----------------------- $1,809,337 $1,557,040 ======================= See Notes to Financial Statements. _____________________________________________________________________________ 24 Nevada Power Company December 31, (In thousands) 1993 1992 ______________________________________________________________________________ Capitalization and Liabilities Capitalization (See Schedules of Capitalization and Long-Term Debt): Common shareholders' equity $ 645,924 $ 532,473 Redeemable cumulative preferred stock 38,000 38,000 Cumulative preferred stock with mandatory sinking funds 4,264 4,464 Long-term debt 716,589 715,451 ------------------------- 1,404,777 1,290,388 ------------------------- Current Liabilities: Notes payable (Note 7) 25,000 - Current maturities and sinking fund requirements (See Schedules of Capitalization and Long-Term Debt) 7,496 15,345 Accounts payable, including salaries and wages 70,098 46,357 Accrued taxes (1,131) 1,375 Accrued interest 6,212 7,178 Customers' service deposits 12,069 11,816 Accumulated deferred taxes on deferred energy costs 20,574 7,264 Other (Note 8) 19,372 6,716 ------------------------- 159,690 96,051 ------------------------- Commitments and Contingencies (Note 7) Deferred Credits and Other Liabilities: Accumulated deferred investment tax credits (Note 1) 35,384 36,687 Accumulated deferred taxes on income (Note 2) 126,133 84,097 Customers' advances for construction 28,455 26,803 Proposed refund of recovered energy costs - Mohave accident (Note 7) 16,698 15,113 Other (Note 8) 38,200 7,901 ------------------------- 244,870 170,601 ------------------------- $1,809,337 $1,557,040 ========================= See Notes to Financial Statements. ______________________________________________________________________________ Nevada Power Company 25 Schedules of Capitalization December 31, (Dollars in thousands) 1993 1992 _____________________________________________________________________________ Common Shareholders' Equity (a,c): Common stock, $1 par value, authorized 70,000,000 shares; issued 41,505,195 and 37,132,817 shares at December 31, 1993 and 1992; stated at $ 44,709 $ 40,337 Premium on capital stock 496,367 393,401 Unamortized capital stock expense (4,511) (3,758) Retained earnings 109,359 102,493 ----------------------------------- Total common shareholders' equity 645,924 46.0% 532,473 41.3% ----------------------------------- Redeemable Cumulative Preferred Stock (b): $20 par value, authorized 4,500,000 shares for all series; Outstanding at December 31, 1993 and 1992: 9.90% Series, 1,900,000 shares 38,000 38,000 ----------------------------------- Total 38,000 2.7 38,000 3.0 ----------------------------------- Cumulative Preferred Stock with Mandatory Sinking Funds (b): Outstanding at December 31, 1993 and 1992: 5.40% Series, 46,669 and 48,669 shares 934 974 5.20% Series, 44,507 and 46,507 shares 890 930 4.70% Series, 132,000 and 138,000 shares 2,640 2,760 ----------------------------------- 4,464 4,664 Current sinking fund requirement (200) (200) ----------------------------------- Total 4,264 0.3 4,464 0.3 ----------------------------------- Long-Term Debt (See Schedules of See Schedules of Long-Term Debt) 716,589 51.0 715,451 55.4 ----------------------------------- Total capitalization $1,404,777 100.0% $1,290,388 100.0% =================================== _____________________________________________________________________________ 26 Nevada Power Company Notes to Schedules of Capitalization (a) The changes in common stock shares for 1991, 1992 and 1993 are as follows: Shares ________________________________________________________________________________ Outstanding, December 31, 1990 28,912,228 Issued through public offering 3,000,000 Issued under 401(k) Savings Plan 30,870 Issued under Stock Purchase and Dividend Reinvestment Plan 1,032,369 ---------- Outstanding, December 31, 1991 32,975,467 Issued through public offering 2,990,000 Issued under 401(k) Savings Plan 27,644 Issued under Stock Purchase and Dividend Reinvestment Plan 1,139,706 ---------- Outstanding, December 31, 1992 37,132,817 Issued through public offering 2,700,000 Issued under 401(k) Savings Plan 32,052 Issued under Stock Purchase and Dividend Reinvestment Plan 1,640,326 ---------- Outstanding, December 31, 1993 41,505,195 ========== _______________________________________________________________________________ Premium on capital stock increased $103 million, $73.9 million and $66.8 million during 1993, 1992 and 1991, respectively, due to issue of common stock. Cash dividends paid per share on common stock were $1.60 each year during 1993, 1992 and 1991. (b) The Redeemable Cumulative Preferred Stock, 9.90% Series is redeemable at the option of the company, as a whole or in part, on April 1, 1997, and is subject to mandatory redemption in its entirety on April 1, 2002. (See Note 6 of "Notes to Financial Statements.") Under the provisions of the 4.70%, 5.20% and 5.40% series cumulative preferred stock with mandatory sinking funds, the company is obligated to use its best efforts to purchase, each year, up to an aggregate of 6,000, 2,000 and 2,000 shares, respectively, at prices not in excess of $20.00 per share. The obligations are not cumulative. The 5.20% series and 5.40% series are presently redeemable at the option of the company at $21.00 per share and the 4.70% series at $20.25 per share. (c) In October 1990, the company adopted a Stockholder Rights Plan and declared a dividend of one stock purchase right for each outstanding share of common stock. (See Note 6 of "Notes to Financial Statements.") Nevada Power Company 27 Schedules of Long-Term Debt December 31, (In thousands) 1993 1992 _________________________________________________________________________ Long-Term Debt (a) (Note 5 to Financial Statements): First mortgage bonds (b): 7 1/8% Series I due 1998 $ 15,000 $ 15,000 7 5/8% Series L due 2002 15,000 15,000 7 1/8% Series N due 2006 13,000 13,000 6 3/4% Series O due 2007 7,100 7,500 8 3/4% Series P due 1995 423 445 9 3/8% Series S due 2016 - 52,000 7.80% Series T due 2009 15,000 15,000 6.92% Series U due 1995 50,000 50,000 6.70% Series V due 2022 105,000 105,000 6.60% Series W due 2019 39,500 39,500 7.20% Series X due 2022 78,000 78,000 6.93% Series Y due 1999 45,000 45,000 8.50% Series Z due 2023 45,000 - -------------------------- 428,023 435,445 Industrial development revenue bonds (c): 7.80% due 2020 100,000 100,000 Floating rate weekly demand - Due 2015 44,000 44,000 Due 2018 25,000 25,000 Due 2019 60,000 60,000 Less funds held in trust (59,051) (65,285) 6 3/8% pollution control revenue bonds due 2004 (d) 16,000 17,000 Obligations under capital leases 109,968 114,501 -------------------------- 723,940 730,661 Debt premium and discount, being amortized (55) (65) Current maturities and sinking fund requirements (7,296) (15,145) -------------------------- Total long-term debt $716,589 $715,451 ========================== _________________________________________________________________________ 28 Nevada Power Company Notes to Schedules of Long-Term Debt (a) The amounts of long-term debt maturities, including sinking fund requirements, are $7.3 million in 1994, $57.3 million in 1995, $8 million in 1996, $7.9 million in 1997 and $7.3 million in 1998, including $5.6 million, $5.2 million, $5.3 million, $5.2 million and $4.5 million for obligations under capital leases, respectively. None of the long-term debt is held by or for the account of the company. (b) Generally, electric plant is subject to the first mortgage lien. It is the company's intention to meet the sinking fund requirement for its series I and L first mortgage bonds by pledging property additions in lieu of cash payments. The N, O and P series first mortgage bonds provide for annual payments sufficient to ratably retire the respective series by their final due dates. Payments on the N series do not commence until 1996. The series N, O, T, V, W and X first mortgage bonds correspond with respect to their terms to four series of collateralized pollution control revenue bonds and two series of industrial development revenue bonds issued by various municipal authorities. (c) The fixed rate industrial development bonds and floating rate industrial development bonds were issued by Clark County, Nevada and are guaranteed as to payment of principal and interest by the company. (d) The indenture for the 6 3/8% pollution control revenue bonds due 2004 provides for annual sinking fund payments of $1 million to and including March 1, 2003 and a final payment of $6 million on March 1, 2004. Nevada Power Company 29 Statements of Cash Flows For the Years Ended Dec. 31, (In thousands) 1993 1992 1991 __________________________________________________________________________ Cash Flows from Operating Activities: Net income $ 73,548 $ 56,780 $ 35,176 Adjustments to reconcile net income to net cash provided - Depreciation and amortization 55,139 47,356 44,686 Deferred income taxes and investment tax credits 16,504 12,030 (9,536) Allowance for other funds used during construction (9,880) (8,251) (4,172) Changes in - Receivables (4,591) (2,635) (339) Fuel stock and materials and supplies 5,490 5,928 (8,104) Accounts payable and other current liabilities 27,290 17,296 676 Deferred energy costs (37,766) (8,916) 40,466 Accrued taxes and interest 1,868 (14,683) 439 Other assets and liabilities 3,343 2,473 1,013 --------------------------------- Net cash provided by operating activities 130,945 107,378 100,305 --------------------------------- Cash Flows from Investing Activities: Construction expenditures and gross additions (163,257) (171,074) (151,089) Investment in subsidiaries and other (2,828) (4,531) (2,851) Salvage net of removal cost 227 405 1,798 --------------------------------- Net cash used in investing activites (165,858) (175,200) (152,142) --------------------------------- Cash Flows from Financing Activities: Sale of capital stock 107,329 78,066 70,814 Sale of long-term debt 45,000 317,500 - Change in funds held in trust 6,234 (21,135) 6,612 Retirement of preferred stock and long-term debt (59,405) (175,745) (9,043) Increase (decrease) in short-term borrowing - (71,000) 34,110 Cash dividends (66,883) (60,596) (51,532) Other financing activities 2,623 738 845 --------------------------------- Net cash provided by financing activities 34,898 67,828 51,806 --------------------------------- Cash and Temporary Cash Investments(Note 1): Net increase (decrease) during the period (15) 6 (31) Beginning of period 160 154 185 -------------------------------- End of period $ 145 $ 160 $ 154 ================================ Cash Paid During the Period for: Interest, net of amounts capitalized $ 57,140 $ 55,926 $ 48,919 ================================ Income taxes $ 18,001 $ 13,793 $ 22,771 ================================ See Notes to Financial Statements. __________________________________________________________________________ 30 Nevada Power Company Notes to Financial Statements Note 1 - Summary of Significant Accounting Policies For ratemaking and other purposes, the company is subject to the jurisdiction of the PSC and the Federal Energy Regulatory Commission (FERC). The accounting records of the company are maintained in accordance with the uniform system of accounts prescribed by the FERC and adopted by the PSC. Electric Revenues - The company bills its customers monthly on a cycle basis and recognizes the estimated amount of revenue applicable to kilowatthours of energy sold but not yet billed at the end of an accounting period. Deferred Energy Cost Adjustments - As permitted by state statute, the company defers differences between the current cost of fuel plus net purchased power and base energy costs as defined. Any over or under recoveries are deferred in the balance sheet as a current asset or current liability. Under regulations adopted by the PSC, deferred energy rates are revised at least every 12 months to clear the accumulated deferred balance over a future period. Electric Plant - The costs of betterments and additions to electric plant and replacements of retirement units of property are capitalized. Such costs include labor, payroll taxes, material, transportation, an allowance for funds used during construction and, where applicable, property taxes. Maintenance is charged with the cost of repairs and minor replacements. Accumulated depreciation is charged for the cost of plant retired, less net salvage. Depreciation has been provided for financial statement purposes on a straight-line basis at rates based upon the estimated useful lives of the various classes of plant. The provisions for depreciation during the first ten months of 1991 were equivalent to an annual rate of approximately 2.8 percent of the average gross investment in depreciable plant. Effective November 1991, as authorized by the PSC, the annual depreciation rate was increased to approximately 2.9 percent. Allowance for Funds Used During Construction - The allowance for funds used during construction (AFUDC) represents the estimated costs of borrowed and equity funds applicable to electric plant construction. The FERC has prescribed a specific computational method for determining the AFUDC rate. The PSC has authorized the AFUDC rate to be the lesser of the rate determined under the FERC computational method or the rate equivalent to the overall rate of return authorized by the PSC. Through December 31, 1992, the company used a rate of 10.02 percent to calculate AFUDC on construction work in progress as authorized by the PSC, effective July 1992. In January 1993, the company began using an AFUDC rate as calculated under the FERC computational method which averaged 9.88 percent for 1993. Recently Issued Accounting Standards - In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112 (FAS 112), Employers' Accounting for Postemployment Benefits which is effective for years beginning after December 15, 1993. FAS 112 established accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement (postemployment benefits). The company is currently analyzing the provisions of FAS 112 and believes that application of the new standard will not have a material impact on the company's results of operations or financial position. Federal Income Taxes - Effective January 1, 1993, the company adopted the provisions of FAS 109, Accounting for Income Taxes. FAS 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The cumulative effect of the change in accounting for income taxes is not material to net income. In November 1991, the PSC issued an order which allows the company to recover the previously flowed through tax benefits ratably over the estimated remaining book life of the plant. Calculated at current rates, approximately $38 million of income taxes will be allowed in future rates. Nevada Power Company 31 Notes to Financial Statements Investment tax credits earned have been deferred and are being amortized to income ratably over the estimated service lives of the related property. Cash Flow Information - Cash equivalents, which generally are convertible to cash at par on short notice and mature three months or less from the date of acquisition, are reported as temporary cash investments. The company had no material non-cash investing or financing transactions during 1993 or 1992. During 1991, a capital lease obligation of $83 million was incurred when the company entered into a power purchase contract with Mission Energy Company. Other Accounting Policies - The company uses the equity method of accounting to report immaterial investments in subsidiaries. Disclosure by the company of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107 (FAS 107), Disclosures about Fair Value of Financial Instruments. At December 31, 1993 and 1992, the provisions of FAS 107 apply only to the company's long-term debt and redeemable cumulative preferred stock. (See Notes 5 and 6 of "Notes to Financial Statements.") In 1993, the company adopted the provisions of FAS 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires accrual of postretirement benefits during the years an employee provides services. (See Notes 3 and 8 of "Notes to Financial Statements.") Certain amounts in prior periods have been reclassified to conform to the financial statement presentation for December 31, 1993. Note 2 - Federal Income and Other Taxes The total federal income tax expense as set forth in the accompanying Statements of Income results in an effective federal income tax rate different than the statutory federal income tax rate for the following reasons: Years Ended Dec. 31, (Dollars in thousands) 1993 1992 1991 ______________________________________________________________________________ Federal income tax at statutory rate $39,625 35.0% $29,241 34.0% $17,057 34.0% Adjustments: Investment tax credit amortization (1,303) (1.2) (1,618) (1.9) (1,618) (3.2) Other items 1,344 1.2 1,600 1.9 (446) (0.9) -------------------------------------------------- Total recorded federal income tax $39,666 35.0% $29,223 34.0% $14,993 29.9% ================================================== Federal income taxes included in: Operating expenses $37,278 $29,975 $16,198 Other income, net 2,388 (752) (1,205) -------------------------------------------------- $39,666 $29,223 $14,993 ================================================== ______________________________________________________________________________ 32 Nevada Power Company The current and deferred components of federal income taxes included in operating expenses are as follows: Years Ended Dec. 31, (In thousands) 1993 1992 1991 _________________________________________________________________________ Current federal income taxes $20,680 $18,213 $25,753 ----------------------------------- Deferred federal income taxes: Depreciation differences 8,899 13,823 8,127 Deferred energy costs 11,765 (434) (12,601) Contributions in aid of construction (1,732) (1,437) (806) Coal contract buyout (945) (1,009) (1,009) Other - net (86) 2,437 (1,648) ----------------------------------- 17,901 13,380 (7,937) ----------------------------------- Investment tax credit amortization (1,303) (1,618) (1,618) ----------------------------------- Total $37,278 $29,975 $16,198 =================================== _________________________________________________________________________ General taxes charged to operating expenses are as follows: Years Ended Dec. 31, (In thousands) 1993 1992 1991 _________________________________________________________________________ Real estate and personal property $11,338 $ 9,408 $ 8,185 Payroll 4,748 4,285 4,083 Other 315 400 459 ----------------------------------- Total $16,401 $14,093 $12,727 =================================== _________________________________________________________________________ The company adopted FAS 109, Accounting for Income Taxes, effective January 1, 1993. As a result, the company's December 31, 1993 balance sheet contains a net regulatory asset of $14 million. (See Note 8 of "Notes to Financial Statements.") The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by investment tax credits will be amortized ratably in the same fashion as the accumulated deferred investment credit under former Internal Revenue Code Section 46(f)(2). Nevada Power Company 33 Notes to Financial Statements The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less accumulated deferred federal income tax assets related to: Years ended Dec. 31, (In thousands) 1993 1992 ________________________________________________________________________ Accumulated deferred federal income tax liabilities: Temporary basis differences - plant $ (33,058) $ - Investment tax credits (35,384) (36,687) Excess of tax depreciation over book depreciation (83,309) (75,214) Coal contract buyout (2,251) (3,196) Accrued taxes (1,985) (2,418) Deferred energy (20,574) (7,264) Demand-side program costs (3,686) (1,072) Other (1,844) (2,197) ------------------------ Total (182,091) (128,048) ------------------------ Accumulated deferred federal income tax assets: Unamortized investment tax credits 19,053 - Refundable customer advances 9,867 8,800 Purchased power 5,417 6,055 Nonrefundable contributions in aid of construction 2,510 3,497 Capitalized expenses 1,439 1,556 Other 1,949 1,916 ----------------------- Total 40,235 21,824 ----------------------- Net accumulated deferred tax liability $(141,856) $(106,224) ======================= ________________________________________________________________________ Note 3 - Employee Benefits Employee Welfare Benefit Plans - The company provides certain health, dental, vision care and long-term disability benefits to employees through plans administered under a Voluntary Employee's Beneficiary Association (VEBA) Trust. Currently, substantially all of the costs of the benefit programs for employees are borne by the company. Effective August 1, 1994, current employees will begin paying 10% of the cost of providing health, dental and vision benefits. The cost of the benefit plans was approximately $10.3 million, $9.3 million and $8.2 million, during 1993, 1992 and 1991, respectively. The programs also provide benefits to retired employees who elect to continue coverage by paying the applicable premiums. (See "Postretirement Benefits Other Than Pensions" below.) Defined Contribution Retirement Plan - The company maintains an employee investment plan (401(k) Plan) which was established January 1, 1990, under Section 401(k) of the Internal Revenue Code. Employees who are at least 21 years old and who have completed one year of eligibility service may become "participants" in the 401(k) Plan. The company matched 50 percent in 1993, 1992 and 1991 of any Management, Professional, Administrative and Technical participant's contributions to the 401(k) Plan not to exceed 3 percent of the participant's annual compensation. In 1993, 1992 and 1991, the company matched 25 percent of any union-represented participant's contributions to the 401(k) Plan not to exceed 1.5 percent of the participant's annual compensation. All company contributions are invested in common stock of the company. The amounts expensed for company matching contributions to the 401(k) Plan were $921,000 for 1993, $629,000 for 1992 and $581,000 for 1991. 34 Nevada Power Company Defined Benefit Retirement Plan - The company has a non-contributory defined benefit retirement plan (PLAN) designed to meet the provisions of the Employee Retirement Income Security Act of 1974. All full-time employees age 21 and over with one year of service are covered by the PLAN. Benefits under the PLAN are dependent upon each participant's salary for the highest consecutive 60 months of service and length of service. The company also has a Supplemental Executive Retirement Plan (SERP) in addition to the regular PLAN. Participation is limited to such officers as the Board of Directors may select. Presently, 27 active or retired designated officers and employees participate in the SERP. The SERP will be funded as benefits are disbursed. The table below sets forth the funded status and amounts recognized in the company's financial statements at December 31, 1993, 1992 and 1991 for both the PLAN and SERP. The discount rate and rate of increase in future compensation levels used in determining the actuarial present value of the projected benefit obligations for both the PLAN and SERP were 7.25 percent and 4.50 percent in 1993, and 8.25 percent and 5 percent in 1992 and 1991, respectively. The expected rate of return on PLAN assets was 8.5 percent in 1993, 1992 and 1991. PLAN assets are primarily invested in listed stocks, fixed income securities and federal agencies securities. Reconciliation of Funded Status PLAN SERP ___________________________ ____________________________ Years Ended Dec. 31, (In thousands) 1993 1992 1991 1993 1992 1991 ______________________________________________________________________________ Actuarial present value of: Vested benefit obligation $54,434 $40,592 $32,458 $ 3,854 $ 2,814 $ 2,174 Nonvested benefit obligation 3,875 4,217 3,312 514 375 345 ---------------------------------------------------------- Accumulated benefit obligation $58,309 $44,809 $35,770 $ 4,368 $ 3,189 $ 2,519 ========================================================== Projected benefit obligation $80,575 $63,121 $56,032 $ 4,837 $ 3,452 $ 2,569 Plan assets at fair value 60,236 54,575 49,494 - - - ---------------------------------------------------------- Plan assets less than projected benefit obligation (20,339) (8,546) (6,538) (4,837) (3,452) (2,569) Unrecognized net transition obligation amortized over approximately nine years - - - 129 303 478 Unrecognized prior service costs 5,577 6,005 6,433 412 166 (300) Unrecognized net (gain) loss 8,949 2,925 (822) 1,267 209 84 ---------------------------------------------------------- Pension asset (liability) $(5,813) $ 384 $ (927) $(3,029) $(2,774) $(2,307) ========================================================== Net pension expense was comprised of the following: Service cost $ 3,284 $ 3,147 $ 2,884 $ 67 $ 76 $ 29 Interest cost on projected benefit obligation 5,243 4,900 4,334 297 278 211 Return on plan assets (5,371) (1,739) (8,301) - - - Net amortization and deferral 1,021 (2,117) 2,862 197 331 268 ---------------------------------------------------------- Net periodic pension cost $ 4,177 $ 4,191 $ 1,779 $ 561 $ 685 $ 508 ========================================================== ______________________________________________________________________________ Nevada Power Company 35 Notes to Financial Statements Postretirement Benefits Other Than Pensions - The company adopted FAS 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, effective January 1, 1993. The costs of these benefits have been expensed on a pay-as-you-go basis prior to the company adopting FAS 106. In July 1992, the PSC authorized the company to continue recognizing these benefit costs on a pay-as-you-go basis after adopting FAS 106 and to record any difference in costs resulting from the implementation of FAS 106 as a deferred asset. The company has elected to amortize its transition obligation at January 1, 1993 over a period of 20 years. The company provides postretirement medical, dental and vision benefits to employees who have retired or will retire and are eligible for an immediate pension benefit. The postretirement health care plan is contributory, and retirees' contributions can be adjusted annually for increases in the cost of providing the benefits. Net periodic postretirement benefit cost for the year ended December 31, 1993 included the following components: (In thousands) 1993 _______________________________________________________________________ Service cost benefit earned during the year $ 614 Interest cost on projected benefit obligation 1,881 Amortization of transition obligation 1,166 ------ Net periodic postretirement benefit cost $3,661 ====== _______________________________________________________________________ A reconciliation of the funded status of the plan to the amounts recognized in the Balance Sheet as of December 31, 1993 is as follows: (In thousands) 1993 _______________________________________________________________________ Retirees $(10,270) Fully eligible active employees (8,749) Other active employees (6,777) -------- Accumulated postretirement benefit obligation (25,796) Unrecognized transition obligation 22,149 Unrecognized loss 542 -------- Accrued postretirement benefit cost liability $ (3,105) ======== _______________________________________________________________________ The medical cost trend rate assumed for 1994 was 10.25 percent, grading down to 4.75 percent in 2001 and remaining at that level thereafter. The health care cost trend rate has a significant effect on the accumulated postretire- ment benefit obligation and net periodic cost. A one-percentage-point increase in the assumed health care cost trend rate would increase the accumulated postretirement benefit obligation at December 31, 1993 by $1.9 million and would increase the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1993 by $149,000. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation at December 31, 1993 was 7.25 percent. Note 4 -Short-Term Borrowings The company has a $125 million bank revolving credit facility which expires on December 31, 1994, and pays commitment fees based on both the unused amount of the facility and the company's first mortgage bond ratings. Borrowing rates under the bank line are determined by both current market rates and the company's first mortgage bond ratings. During 1993, the maximum amounts of short-term borrowings outstanding were $74 million, average short-term borrowings were $16.1 million and weighted average interest costs were 5.34%. There were no short-term borrowings outstanding at December 31, 1993. 36 Nevada Power Company During 1992, the maximum amounts of short-term borrowings outstanding were $71 million, average short-term borrowings were $18.6 million and weighted average interest costs were 6.01%. There were no short-term borrowings outstanding at December 31, 1992. During 1991, the maximum amounts of short-term borrowings outstanding were $71 million, average short-term borrowings were $36.2 million and weighted average interest costs were 6.91%. The weighted average interest rate for short-term borrowings outstanding at December 31, 1991, was 5.33%. Note 5 - Long-Term Debt In accordance with FAS 107, the company estimates the fair value of its long- term debt based on quoted market prices for the same or similar issues or on current interest rates available to the company for debt with similar terms and maturity. The book value and estimated fair value of the company's long- term debt, including current maturities and sinking fund requirements and excluding obligations under capital leases, were $614 million and $665 million at December 31, 1993, and $616 million and $626 million at December 31, 1992, respectively. The estimate presented herein is not necessarily indicative of the amount that the company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have an effect on the estimated fair value amount. The indentures under which the company's first mortgage bonds were issued provide for an immaterial restriction as to distributions to shareholders at December 31, 1993. Note 6 - Capital Stock In October 1990, the company issued through dividend to its common share- holders certain stock rights which expire in October 2000. The rights to purchase junior preference shares, common shares or shares of a successor corporation are not exercisable unless certain events occur and are intended to assure fair shareholder treatment in any takeover of the company and to guard against abusive takeover tactics. On April 30, 1992, the company issued shares of Redeemable Cumulative Preferred Stock, 9.90% Series consisting of the previously issued shares of Auction Preferred Stock. The company elected to establish a 10-year dividend period for this preferred stock, with mandatory redemption April 1, 2002. The dividend rate on the shares of Redeemable Cumulative Preferred Stock, 9.90% Series was determined at an auction held on April 23, 1992. Dividends on the shares are cumulative from April 30, 1992, and will be payable when, as and if declared, quarterly on January 1, April 1, July 1 and October 1 of each year commencing July 1, 1992. In accordance with FAS 107, the company estimates the fair value of its redeemable cumulative preferred stock based on the per share closing price times the number of shares outstanding. The book value and estimated fair value of the redeemable cumulative preferred stock were $38 million and $43.6 million at December 31, 1993 and $38 million and $42 million at December 31, 1992, respectively. The estimate presented herein is not necessarily indicative of the amount that the company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have an effect on the estimated fair value amount. Note 7 - Commitments and Contingencies Rate Matters - In 1985 the company incurred $15.8 million in increased fuel and purchased power expenses after a ruptured steam line at the jointly owned Mohave Generating Station resulted in a loss of the plant for six months. The PSC allowed the company to recover one half of the increased expenses subject to refund. Fourth quarter 1990 earnings reflected a $12.9 million charge to record a subsequent proposed order issued by the PSC which stated that the company shall not recover any of the increased costs. The company has fully reserved for any negative financial effect related to the proposed order. In 1991, the PSC set aside the proposed order and ordered the parties to participate in joint hearings before the CPUC. The CPUC hearings are now concluded, and the PSC will prepare its own opinion based on the record created in the CPUC hearings. In January 1994, the administrative law judge in the CPUC proceeding issued a proposed opinion denying recovery to SCE of its incremental purchased power costs resulting from the accident. SCE has filed comments with the CPUC concerning the proposed decision. On August 12, 1993, the company filed a request with the PSC to recover additional fuel and purchased power costs of $29.7 million under the state's deferred energy accounting procedures. This request included $9.8 million of deferred energy costs for the period of December 1, 1992, to May 31, 1993, and $19.9 million to adjust the base energy rate. The company subsequently amended its request to $26.8 million. Hearings in this Nevada Power Company 37 Notes to Financial Statements matter were concluded in December 1993, and the PSC granted an increase in rates of $23.6 million, effective February 1, 1994. The PSC order resulted in fourth quarter 1993 charges of $2 million net of taxes for deferred energy costs. On July 11, 1991, Nevada Electric Investment Co. (NEICO), the company's unregulated subsidiary, entered into an agreement to sell a 50 percent undivided ownership interest in certain coal mining assets to the Intermountain Power Agency (IPA). NEICO and IPA will continue the coal mining operations as joint venturers under the name of the Crandall Canyon Project. Additionally, IPA has executed a continuing coal purchase agreement. This transaction has been inquired into by the PSC, and no gain on the transaction has been recorded pending regulatory review which is expected in 1994. Legal Matters - In December 1992, the company suspended deliveries under a coal contract with Mountain Coal Co. based on a pricing dispute. Mountain Coal Co. filed a lawsuit in the federal district court for the State of Utah seeking a determination that the company had repudiated the coal supply agreement. In October 1993, the court found in favor of Mountain Coal Co.'s position. The company appealed the court's order, however, in March 1994, the company resolved the litigation and bought out the remaining obligation under the contract by issuing a promissory note (bearing interest at 10%) for a total of $25 million. The facility using the coal under this contract is jointly owned; accordingly the company's portion of this settlement is $15.25 million. The settlement and buyout have been recorded as of December 31, 1993, with $25 million included in notes payable, $15.25 million included in deferred energy costs and $9.75 million included in other receivables. The settlement and buyout will result in lower fuel costs to the company's customers over the otherwise remaining life of the contract; accordingly, based on similar past buyouts, management believes that the cost of the buyout will be recovered through Nevada's deferred energy accounting procedures. The company is involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management, based upon advice of counsel, believes that the final outcome will not have a material adverse effect on the company's financial position and results of operations. Environmental Matters - The Federal Clean Air Act Amendments of 1990 include provisions which will affect the company's existing steam generating facilities and all new fossil fuel fired facilities. Title IV of the Amendments provides a national cap on sulfur dioxide emissions by mandating emissions reductions for many electric steam generating facilities. The sulfur dioxide provisions of the Amendments will not adversely affect the company because the company's steam units burn low sulfur fuels or have sulfur dioxide control equipment. Title IV of the Amendments also provides for reduction of emissions of oxides of nitrogen by establishing new emission limits for coal-fired generating units. This Title will require the installation of additional pollution-control technology at some of the Reid Gardner Station generating units before 2000 at an estimated cost to the company of no more than $6 million. Other provisions of the Amendments will require the company to install or upgrade Continuous Emission Monitoring systems at all steam generating units before 1995 at an expected cost of up to $3.3 million. The United States Congress authorized $2 million for the Environmental Protection Agency (EPA) to study the potential impact the Mohave Generating Station (MGS) may have on visibility in the Grand Canyon. The EPA report is expected to be finalized in late 1995, with a follow-up report from the Grand Canyon Visibility Transport Commission in late 1996. Also, the Nevada Division of Environmental Protection has imposed more stringent stack opacity limits for the MGS. This change may affect the company's utilization of resources, but, until more experience is gained by operating at the new opacity levels, any effect cannot be determined. As a 14 percent owner of the MGS, the company will be required to fund any plant improvements that may result from the EPA study and operation at the new opacity levels. The cost of any potential improvements cannot be estimated at this time. In 1991, the U.S. Environmental Protection Agency published an order requiring the Navajo Generating Station (NGS) to install scrubbers to remove 90 percent of sulfur dioxide beginning in 1997. As an 11.3 percent owner of the NGS, the company will be required to fund an estimated $46.6 million for installation of the scrubbers. In 1992, the company received resource planning approval from the PSC for its share of the cost of the scrubbers up to $46.6 million. 38 Nevada Power Company Leases - In 1984, the company sold its administrative headquarters facility, less furniture and fixtures, for $27 million and entered into a 30-year capital lease of that facility with five-year renewal options beginning in year 31. The fixed rental obligation for the first 30 years is $5.1 million per year. Future cash rental payments as of December 31, 1993, are as follows: (In thousands) ___________________________________________________________________________ 1994 $ 3,605 1995 3,604 1996 3,605 1997 3,604 1998 3,605 Thereafter 109,937 -------- $127,960 ======== ___________________________________________________________________________ The amount of imputed interest necessary to reduce the future cash rental payments to present value is $85.7 million as of December 31, 1993. Total interest expense on the lease obligation was $4 million and total amortization of the leased facility was $402,000 for the year ended December 31, 1993. The total accumulated amortization of the leased facility on December 31, 1993, was $9 million. At December 31, 1993, the company has certain long-term noncancellable operating lease agreements for which the future minimum lease payments are immaterial. Fuel and Purchased Power Obligations - The company has five long-term contracts for the purchase of electric energy and/or capacity. The contracts expire in years ranging from 1995 to 2016. Total payments under these contracts were $55.9 million, $51.4 million and $42.6 million in 1993, 1992 and 1991, respectively. The cost of power obtained under these contracts is included in purchased power expense in the statements of income. At December 31, 1993, the estimated future payments for capacity and energy that the company is obligated to purchase under these contracts, subject in part to certain conditions, are as follows: Accounted for Accounted for as Long-term as Long-term (In thousands) Executory Contracts Capital Lease ___________________________________________________________________________ 1994 $ 35,600 $ 14,591 1995 36,150 13,986 1996 27,600 13,432 1997 28,600 12,902 1998 18,450 12,373 Thereafter 1,800 145,631 ---------------------------------- Total minimum payment $148,200 212,915 ======== Less amount representing estimated executory costs included in total minimum payment (98,232) -------- Net minimum payments 114,683 Less amount representing interest (47,022) -------- Present value of net minimum payments $ 67,661 ======== ___________________________________________________________________________ Nevada Power Company 39 Notes to Financial Statements Total interest expense on the purchase power obligation accounted for as a capital lease was $6.7 million and total amortization was $5.5 million in 1993. Total accumulated amortization was $15.3 million for the year ended December 31, 1993. The company has contracted with various coal suppliers to provide coal to the Reid Gardner Generating Station. The contracts expire in years ranging from 1994 to 2007. The costs of approximately $33.9 million, $38.2 million and $44.6 million were incurred under the long-term coal contracts in 1993, 1992 and 1991, respectively. At December 31, 1993, the estimated future payments for coal that the company is obligated to purchase under these contracts are as follows: (In thousands) __________________________________________________________________________ 1994 $ 29,128 1995 19,776 1996 17,258 1997 17,775 1998 18,308 Thereafter 182,258 -------- $284,503 ======== __________________________________________________________________________ Construction - Certain commitments have been incurred at December 31, 1993, in connection with the 1994 construction budget. Construction expenditures are estimated at $175 million, including AFUDC, for 1994. Note 8 - Other Deferred Charges and Credits Other Deferred Charges - At December 31, 1993, as a result of the company adopting FAS 109 effective January 1, 1993, other deferred charges include a regulatory asset of $46 million and a deferred tax asset of $19.1 million. The regulatory asset represents future revenue to be received from customers due to the flow-through of tax benefits of temporary differences in prior years and the deferred tax asset is from temporary differences caused by investment tax credits. As a result of the company adopting FAS 106 effective January 1, 1993, a regulatory asset and a postretirement benefit liability of $3.1 million are included in other deferred charges and other current liabilities, respectively, at December 31, 1993. The regulatory asset and benefit liability represent the difference between the postretirement benefit costs expensed by the company on a pay-as-you-go basis as authorized by the PSC and the costs resulting from the implementation of FAS 106. At December 31, 1993, organizational study, early retirement and severance costs of $6.7 million are included in other deferred charges to be amortized over three years beginning February 1994. Of such costs, $5.5 million are related to the company's defined benefit retirement plan and are included in other current liabilities as a part of the pension liability of $5.8 million at December 31, 1993. In May 1988, after securing PSC approval, the company paid United States Fuel Company $23.5 million to terminate an existing coal supply agreement. The amount paid plus carrying charges is being amortized over eight years and the amounts included in other deferred charges and deferred energy costs as of December 31, 1993, were $6.4 million and $2.3 million,respectively. Other deferred charges as of December 31, 1993, also include $12.4 million for deferred federal income taxes on customer advances for construction and $8.9 million for conservation programs. Other Deferred Credits - As of December 31, 1993, a credit of $4.7 million for generating station spare parts is included in other deferred credits. Effective January 1992, this credit is being amortized over a six-year period. Other deferred credits as of December 31, 1993, also include a regulatory liability of $32 million representing amounts to be refunded to customers in the future as a result of the company adopting FAS 109. 40 Nevada Power Company Note 9 -Interests in Jointly Owned Electric Utility Facilities At December 31, 1993, the company owned the following undivided interests in jointly owned electric utility facilities: Company's Share of _________________________________________________ Percent Construction Owned by Plant Accumulated Net Plant Work in (In thousands) Company In Service Depreciation In Service Progress ______________________________________________________________________________ Facility Navajo Project 11.3 $132,370 $ 59,999 $ 72,371 $ 6,016 Mohave Project 14.0 67,479 27,559 39,920 4,888 Reid Gardner Plant Unit No. 4 32.2 133,528 30,516 103,012 869 --------------------------------------------- Total $333,377 $118,074 $215,303 $11,773 ============================================= ______________________________________________________________________________ The amounts above for Navajo and Mohave include the company's share of transmission systems and general plant equipment and, in the case of Navajo, the company's share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all of these jointly owned facilities. The company's share of operating expenses for these facilities is included in the corresponding operating expenses in the Statements of Income. Note 10 - Quarterly Financial Data (unaudited) Earnings Earnings (In thousands, Available per Average except per share Electric Operating Net for Common Common amounts) Revenues Income Income Stock Share ___________________________________________________________________________ 1993: First $132,814 $16,621 $ 8,379 $ 7,382 $0.20 Second 142,318 23,022 15,238 14,241 0.37 Third 232,263 54,957 47,113 46,117 1.13 Fourth 144,377 13,869 2,818 1,822 0.04 1992: First 122,902 12,035 2,022 820 0.02 Second 140,913 20,774 10,245 9,181 0.26 Third 206,868 51,198 42,982 41,984 1.15 Fourth 130,232 16,115 1,531 533 0.01 ___________________________________________________________________________ The business of the company is seasonal in nature and it is management's opinion that comparisons of earnings for the quarters do not give a true indication of overall trends and changes in the company's operations. The fourth quarter of 1993 reflects write-offs of $5.6 million net of tax or 14 cents per average common share for certain deferred amounts including costs related to preliminary studies for the coal-fired White Pine Power Project and for deferred energy. The fourth quarter of 1992 reflects write-offs of $4.5 million net of tax or 13 cents per average common share for certain deferred amounts including costs related to a property loss at Reid Gardner Generating Station No. 4. Nevada Power Company 41 Independent Auditors' Report To the Board of Directors and Shareholders of Nevada Power Company: We have audited the balance sheets of Nevada Power Company as of December 31, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements 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 financial statements present fairly, in all material respects, the financial position of the company at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. As discussed in Notes 1 and 2 to the financial statements, the company changed its method of accounting for income taxes effective January 1, 1993 to conform with Statement of Financial Accounting Standards No. 109. Deloitte & Touche Deloitte & Touche Las Vegas, Nevada February 10, 1994 (March 11, 1994 as to the fourth paragraph of Note 7) Report of Management The management of Nevada Power Company is responsible for the financial statements presented in this report. Management prepared the financial statements in conformity with generally accepted accounting principles applicable to public utilities which are consistent in all material respects with the accounting prescribed by the Public Service Commission of Nevada and the Federal Energy Regulatory Commission. In preparing the financial statements, management made informed judgements and estimates relating to events and transactions being reported. The company has a system of internal accounting and financial controls and procedures in place to insure that the financial records reflect the transactions of the company and that assets are safeguarded. This system is examined by management on a continuing basis for effectiveness and efficiency and is reviewed on a regular basis by an internal audit staff that reports directly to the Audit Committee of the Board of Directors. The financial statements have been audited by Deloitte & Touche, independent auditors. The auditors provide an objective, independent review as to management's discharge of its responsibilities as they relate to the fairness of reported operating results and financial condition. Their audit includes procedures which provide them reasonable assurance that the financial statements are not misleading and includes a review of the company's system of internal accounting and financial controls and a test of transactions. The Board of Directors has oversight responsibility for determining that management has fulfilled its obligation in the preparation of financial statements and the ongoing examination of the company's system of internal accounting controls. The Audit Committee, which is composed solely of outside directors, meets regularly with management, Deloitte & Touche and the internal audit staff to discuss accounting, auditing and financial reporting matters. The Audit Committee reviews the program of audit work performed by the internal audit staff. To insure auditor independence, both Deloitte & Touche and the internal audit staff have complete and free access to the Audit Committee. 42 Nevada Power Company Stock Prices on New York Stock Exchange and Dividends Per Share 1993 Quarters 1992 Quarters _________________________________ __________________________________ First Second Third Fourth First Second Third Fourth ______________________________________________________________________________ Common High $25 $25 3/4 $26 3/4 $26 1/4 $19 5/8 $19 1/8 $22 5/8 $24 Low 22 5/8 24 24 5/8 22 1/2 18 5/8 18 18 1/2 21 3/4 Dividend paid .40 .40 .40 .40 .40 .40 .40 .40 ______________________________________________________________________________ High and low common stock prices shown are as reported by the Wall Street Journal as New York Stock Exchange Composite Transactions. The common stock is also listed on the Pacific Stock Exchange. Holders of common stock are entitled to dividends as are declared by the Board of Directors, subject to the rights of the cumulative preferred stock and the preference stock of the company to quarterly cumulative dividends as declared by the Board of Directors. The company has paid quarterly dividends on its common stock since August 1954. See Note 5 of "Notes to Financial Statements" for restriction on the company's ability to pay dividends. The company had 47,239 shareholders of record of common stock at December 31, 1993. Nevada Power Company 43 Statistical Summary 1993-1989
1993 1992 1991 1990 1989 ___________________________________________________________________________________________________________________ Summary of Operations (In thousands, except per share amounts): Electric Revenues: Residential $ 267,941 $ 245,160 $ 216,784 $ 194,911 $ 179,333 Commercial and industrial 326,006 305,707 287,407 256,310 210,167 Other electric sales 48,504 42,011 34,459 35,057 27,767 Miscellaneous 9,321 8,037 7,761 6,043 5,635 ---------------------------------------------------------------------- 651,772 600,915 546,411 492,321 422,902 ---------------------------------------------------------------------- Net Income (a) 73,548 56,780 35,176 24,992 51,467 Dividend Requirements on Preferred Stock 3,986 4,262 2,880 2,917 3,058 Earnings Available for Common Stock (a) $ 69,562 $ 52,518 $ 32,296 $ 22,075 $ 48,409 Weighted Average Number of Common Shares Outstanding 39,482 35,652 30,855 28,330 26,693 Earnings Per Average Common Share (a) $ 1.76 $ 1.47 $ 1.05 $ .78 $ 1.81 Dividends Per Common Share $ 1.60 $ 1.60 $ 1.60 $ 1.58 $ 1.54 Capitalization (In thousands, except per share amounts): Long-Term Debt $ 716,589 $ 715,451 $ 578,540 $ 521,340 $ 460,366 Cumulative Preferred Stock 38,000 38,000 38,000 38,000 38,000 Cumulative Preferred Stock with Mandatory Sinking Funds 4,264 4,464 4,664 4,864 5,067 Common Shareholders' Equity 645,924 532,473 460,307 406,291 383,150 Book Value Per Common Share $ 15.56 $ 14.34 $ 13.96 $ 14.05 $ 14.27 Return on Common Shareholders' Equity 10.77% 9.86% 7.02% 5.43% 12.63% Electric Plant Investment (In thousands): Gross $1,901,448 $1,739,633 $1,562,921 $1,345,107 $1,187,612 Depreciated 1,450,146 1,328,670 1,187,154 996,885 865,834 Total Assets (In thousands) $1,809,337 $1,557,040 $1,410,022 $1,236,210 $1,099,741 Construction Expenditures Excluding AFUDC (In thousands) $ 157,458 $ 167,233 $ 145,271 $ 152,583 $ 120,134 Operating and Sales Data: Generating Capacity and Firm Purchases (Megawatts) 3,488 2,989 2,719 2,534 2,333 Peak Load (Megawatts) 2,681 2,501 2,373 2,248 2,092 Electric Sales (Megawatthours) 11,155,270 10,541,204 9,834,952 9,619,723 8,715,442 Number of Customers (Year End) 403,875 383,036 366,325 347,969 318,036 Average Annual Kilowatthour Sales Per Residential Customer 13,008 13,343 13,213 13,331 13,624 Number of Employees (Year End) 1,741 1,734 1,689 1,639 1,543 ___________________________________________________________________________________________________________________
(a) Amount for 1990 includes a provision for a proposed regulatory disallowance and other adjustments. Amount for 1991 includes write-offs for deferred energy and environmental study costs. Amount for 1993 includes write-offs for deferred energy costs and preliminary study costs for a cancelled coal-fired generating station project. 44 Nevada Power Company 45 EX-10.69 3 LONG-TERM INCENTIVE PLAN NEVADA POWER COMPANY 1993 LONG-TERM INCENTIVE PLAN ARTICLE I PURPOSES The purposes of this Plan are to motivate and reward corporate officers and certain other key managerial employees of Nevada Power Company (the "Company") to achieve the Company's long term objective of providing the Company shareholders with an above average return on the shareholders' investment and to retain in its employ and reward those persons who by their position, ability and diligence are able to make important contributions to the Company's success. ARTICLE II DEFINITIONS The terms used in this Plan shall have the following meanings: (a) "Award" means the right to receive Incentive Compensation Units following the adjustment, if any, by the Committee to previously granted Units at the end of the Performance Period. (b) "Board of Directors" means the Board of Directors of the Company. (c) "Committee" means the Compensation Committee of the Board of Directors of the Company. (d) "Company" means Nevada Power Company. (e) "Employee" means any person who is employed on a permanent basis by and receives a regular salary from the Company. (f) "Fair Market Value" means the average closing market price of the common shares of the Company on the New York Stock Exchange for the 15 trading days immediately preceding the date in question. (g) "Grant" means a conditional right to receive Incentive Compensation Units, subject to adjustment or rescission by the Committee pursuant to the terms of the Plan. (h) "Incentive Compensation Units" means the units granted or awarded to Participants pursuant to the provisions of the Plan. Each Incentive Compensation Unit awarded under the Plan represents the right to receive one common share of the Company. (i) "Participant" means any Employee who is granted Incentive Compensation benefits hereunder. (j) "Performance Period" means the time period beginning on the date of the grant of Incentive Compensation Units (as defined below) pursuant to this Plan, and ending on the third anniversary of the date of the grant. (k) "Total Common Shareholder Return" means the dividends paid with respect to the common shares of a company and the increase in the Fair Market Value of the common shares of a company. 1 ARTICLE III ADMINISTRATION (a) The complete and sole administration of the Plan is the responsibility of the Compensation Committee (sometimes hereinafter called the "Committee"), appointed by the Board of Directors. No member of the Committee shall be eligible for any grant under the Plan for any period during which he served as a member of the Committee. No member of the Committee shall be liable for any act done or determination made in good faith. (b) The construction and interpretation by the Committee of any provision of this Plan shall be final and conclusive. The Committee shall determine, from time to time, subject to the provisions of this Plan, the Employees who shall participate in the Plan (sometimes hereinafter called "Participants"), and the number of Incentive Compensation Units (sometimes hereinafter called "Units") to be granted and awarded to each Participant under this Plan. (c) The Committee's determinations under the Plan, including without limitation, determinations as to the persons to receive grants or awards of Units, the terms and provisions of such grants or awards and the agreements evidencing the same, need not be uniform and may be made by it selectively among persons who receive or are eligible to receive grants or awards under the Plan, whether or not such persons are similarly situated. ARTICLE IV MAXIMUM NUMBER OF UNITS The maximum number of Units outstanding according to the Incentive Compensation Ledger to the credit of the Participants at any one time shall not exceed 200,000 Units. Each Unit awarded under the Plan will represent the right to receive one common share of the Company. ARTICLE V INCENTIVE COMPENSATION UNITS (a) Incentive Compensation Units may be granted to persons who at the time of the grant are full time Employees of the Company. While all such Employees are eligible to be considered for the receipt of Incentive Compensation Units, it is contemplated that only those Employees who perform services of special importance to the Company in the management, operation, and development of the business will be selected to receive Incentive Compensation Units. Subject to the terms, provisions, and conditions of this Plan, the Committee is hereby authorized to (a) select the Employees to be granted Incentive Compensation Units (it being understood that more than one grant may be made to the same person), (b) determine the number of Incentive Compensation Units covered by each grant, and (c) prescribe the form, which shall be consistent with this Plan, of the instruments evidencing any Incentive Compensation Units granted under this Plan. (b) The amount of the individual grant of Incentive Compensation Units to the Employees will be determined by the Committee by giving consideration to the functions and responsibilities of the Employee, the Employee's contribution to the achievement of the Company's objectives, and such other factors as the Committee deems relevant. 2 ARTICLE VI ADJUSTMENTS TO ACCOUNTS OF PARTICIPANTS (a) At the end of each Performance Period, the Committee may adjust the number of Incentive Compensation Units previously granted to the Participants based upon the Total Common Shareholder Return of the Company as compared with the Total Common Shareholder Return of companies included in the Merrill Lynch Electric Utility Index during the Performance Period, or such other measures of performance as the Committee deems appropriate. (b) Except as otherwise provided herein, in making adjustments to the number of Units granted to Participants pursuant to this Paragraph, the Committee shall have the discretion to rescind the Incentive Compensation Units previously granted to the Participants. (c) Except as otherwise provided herein, in the event of any share dividend on the common shares of the Company, any split-up or combination of the common shares, any distribution other than in cash, the issuance of rights to subscribe to additional common shares of the Company, or any material change in the capitalization or business structure of the Company, appropriate adjustment shall be made by the Committee subject to approval of the Board of Directors, in the aggregate number of Units which may be granted and awarded under this Plan and in the number of Units granted to each Participant under this Plan. In the event of the reclassification of common shares of the Company into shares of any other class, the Committee, subject to approval of the Board of Directors, is authorized to make such adjustment in the terms of the Plan as the Committee may deem equitable. (d) Notwithstanding the foregoing, previously granted Units which have been awarded to a Participant pursuant to the provisions of the Plan will not be subject to adjustment or rescission. ARTICLE VII TERMINATION OF EMPLOYMENT (a) A Participant whose employment with the Company is terminated by voluntary resignation (other than retirement) or by termination for cause during a Performance Period will not be entitled to an award of any of the Incentive Compensation Units granted to him (nor to any upward adjustments to such grant), except as provided in Paragraph (b) of Article VIII, unless the Committee in its absolute discretion determines the circumstances exceptional and not contrary to the interest of the Company. (b) A Participant whose employment with the Company is terminated without cause due to retirement or death during a Performance Period will be entitled to a prorated portion of a grant based upon the proportion of full time employment during the Performance Period, counting the year of retirement as a full year, after adjustment to the Units granted pursuant to Article VI. 3 ARTICLE VIII PAYMENT OF AWARDS (a) At the end of a Performance Period, or upon the termination of any Participant's employment with the Company, and after the adjustment provided for by Article VI, there shall be awarded to the Participant, or in the event of the Participant's death to his Beneficiary or Beneficiaries designated under Paragraph (d) of this Article VIII, the Incentive Compensation Units previously granted to the Participant. (b) Notwithstanding anything herein to the contrary, in the event of a change in control of the Company, Units previously granted to Participants under the Plan shall automatically be awarded to Participants without the necessity of further action by the Committee or Company and shall be paid to Participants pursuant to this Article VIII. The occurrence of any of the following events shall constitute a change in control of the Company: (1) the dissolution or liquidation of the Company; (2) the reorganization, merger, or consolidation with one or more corporations in which the Company is not the surviving corporation; (3) the sale, exchange, or transfer of Company stock resulting in any person or the person's affiliates owning more than 20 percent of the outstanding shares; (4) the election to the Company's Board of Directors of new members who were not originally nominated to the Board at the previous two annual meetings if, as a result of this election, new members constitute a majority of the Board, and (5) the sale of all or substantially all of the Company's assets. (c) Awards shall be made by payment to the Participant of one common share of the Company for each Incentive Compensation Unit awarded to the Participant. (d) Each person within 30 days of becoming a Participant under this Plan shall file with the Secretary of the Company a notice in writing designating one or more Beneficiaries to whom payments otherwise due the Participant shall be made in the event of his death while in the employ of the Company or after severance therefrom. The benefits of a deceased Participant who has not completed a beneficiary designation shall be paid to the Participant's spouse, or if none, to the Participant's estate. (e) Notwithstanding the foregoing, and except as provided in Paragraph (b) of this Article VIII, previously granted Incentive Compensation Units will not be awarded at the end of a Performance Period if dividends on the common shares of the Company have been reduced during the Performance Period, and any Units granted at the beginning of the Performance Period will be held until such time as the Committee determines that the grant shall be either awarded or rescinded. ARTICLE IX NONALIENATION OF BENEFITS No right or benefit or payment under this Plan shall be subject to transfer, anticipation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit or payment hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefits. If any Participant or Beneficiary hereunder should become bankrupt or attempt to transfer, anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefit or payment hereunder, then such right or benefit or payment shall, in the sole discretion of the Committee, terminate. 4 ARTICLE X AMENDMENT OR TERMINATION OF PLAN (a) The Board of Directors may amend or terminate this Plan at any time, except that Units awarded to a Participant (and the corresponding right to receive common shares of Company stock) pursuant to the Plan may not be subject to reduction or rescission, and except that without approval by vote of holders of the outstanding common shares of the Company, the maximum number of Plan Units which may be granted to all Participants may not be increased and this Article X may not be amended. (b) Unless sooner terminated pursuant to the provisions herein, the Plan shall terminate on January 1, 2006. No grants of Incentive Compensation Units shall be made under this Plan after December 31, 2002, and no awards of Incentive Compensation Units shall be made under this Plan after December 31, 2005. ARTICLE XI MISCELLANEOUS PROVISIONS (a) No Employee or other person shall have any claim or right to receive Units under the Plan until an award is approved by the Committee, except as provided in Paragraph (b) of Article VIII. Neither the Plan nor any action taken hereunder shall be construed as giving any Employee any right to be retained in the employ of the Company. (b) The Plan shall at all times be entirely unfunded and no provision shall at any time be made with respect to segregating assets of the Company for the payment of any benefits hereunder. No Participant or other person shall have any interest in any particular asset of the Company by reason of the right to receive a benefit under the Plan and any such Participant or other person shall have only the right of a general unsecured creditor of the Company with respect to any rights under the Plan. (c) The Company shall have the right to deduct from all amounts paid pursuant to the Plan any taxes required by law to be withheld with respect to such award. (d) No Employee shall have any right as a shareholder under this Plan unless and until certificates for shares of common shares are transferred to Employee in payment of an award hereunder. (e) For purposes of paying benefits to the Participants pursuant to the Plan, the Committee may purchase common shares, may use common shares held in the Company's treasury, or may issue authorized but unissued common shares, subject to appropriate regulatory approval. (f) The obligation of the Company to sell and deliver common shares under the Plan shall be subject to all applicable laws, regulations, rules and approvals, including, but not by way of limitation, the effectiveness of a registration statement under the Securities Act of 1933 if deemed necessary or appropriate by the Company. Certificates for shares of common shares issued hereunder may be legended as the Board shall deem appropriate. 5 ARTICLE XII EFFECTIVE DATE OF PLAN This Plan shall become operative and in effect on such date as shall be fixed by the Board of Directors of the Company in its sole discretion following approval by vote of the holders of the outstanding common shares of the Company. 6 EX-10.70 4 CONTRACT WITH LAS VEGAS CO-GENERATION, INC. LAS VEGAS COGENERATION LIMITED PARTNERSHIP CONTRACT WITH NEVADA POWER COMPANY FOR LONG TERM POWER PURCHASES FROM A QUALIFYING FACILITY TABLE OF CONTENTS SECTION PAGE 1. INTRODUCTION AND AGREEMENT.......................... 1 2. DEFINITIONS......................................... 2 3. CONTRACT TERMINATION AND MILESTONES................. 5 4. CAPACITY AND ENERGY PAYMENT PROVISIONS.............. 7 5. CAPACITY REQUIREMENTS............................... 9 6. CAPACITY AND ENERGY METERING........................ 11 7. SELLER'S FACILITIES................................. 13 8. NEVADA'S FACILITIES................................. 21 9. INTERCONNECTION FACILITIES AGREEMENT................ 23 10.OPERATIONS COORDINATION AGREEMENT................... 23 11.IMPROVEMENTS AGREEMENTS............................. 23 12.ESCROW PROVISIONS................................... 23 13.BILLING PROVISIONS.................................. 24 14.ASSIGNMENT AND DELEGATION........................... 24 15.TAXES............................................... 25 16.LIABILITY........................................... 25 17.INSURANCE........................................... 26 18.UNCONTROLLABLE FORCES............................... 26 19.NON-DEDICATION OF FACILITIES........................ 27 20.AMENDMENTS.......................................... 27 21.PREVIOUS COMMUNICATIONS............................. 27 22.NON-WAIVER.......................................... 27 23.DISPUTES............................................ 27 24.REMEDIES............................................ 28 25.GOVERNING LAW....................................... 28 26.NATURE OF OBLIGATIONS............................... 28 27.COMMISSION APPROVAL................................. 28 28.SIGNATURES.......................................... 29 EXHIBIT A Payment Provisions..................................... A-1 EXHIBIT B Interconnection Facilities Agreement................... B-1 EXHIBIT C Operations Coordination Agreement...................... C-1 EXHIBIT D Project Improvement Agreement.......................... D-1 EXHIBIT E Procedure for Establishing Firm Operation.............. E-1 EXHIBIT F Form of Insured Endorsement............................ F-1 EXHIBIT G Standby Service Agreement.............................. G-1 1. INTRODUCTION AND AGREEMENT: This Contract and its Exhibits, entered into between NEVADA POWER COMPANY (Nevada) and LAS VEGAS COGENERATION LIMITED PARTNERSHIP (Seller), constitutes the entire agreement between the Parties for the sale of electric capacity and energy to Nevada from a Qualifying Facility owned and operated by Seller. 1.1 Seller shall own, operate, and maintain a Qualifying Facility providing electric capacity and energy which Nevada agrees to purchase under the terms and conditions of this Contract. 1.1.1 Operating Option: During On-Peak hours, the entire electric capacity and energy output of Seller's Generating Facility net of station usage shall be dedicated to Nevada. During all other hours, Nevada shall have first right of refusal to purchase the entire electric capacity and energy output of Seller's Generating Facility net of station usage. 1.2 Notices to Seller: 1.2.1 Written notices and correspondence shall be sent to Seller at the following address: Las Vegas Cogeneration Limited Partnership c/o United Cogen Glenway Avenue P.O. Box 1280 Bristol, VA 24203 1.2.2 Seller's Operating Representative shall be: J. Thomas Fowlkes. 1.2.3 Oral notices shall be conveyed to Seller via telephone at: (703) 466-3322. 1.2.4 Notices to Seller shall be effective upon receipt by Seller. 1.3 Notices to Nevada: 1.3.1 Written notices and correspondence shall be sent to Nevada at the following address: 1 Nevada Power Company Attention: Secretary P. O. Box 230 Las Vegas, Nevada 89151 with a copy to Nevada's Operating Representative at the same address. 1.3.2 Nevada's Operating Representative shall be the Manager of Power Systems Operations; the Supervisor of Interchange Scheduling shall be Nevada's Alternate Operating Representative. 1.3.3 Oral notices shall be conveyed to Nevada's Operating Representative via telephone at:(702) 367- 5390. 1.3.4 Notices to Nevada shall be effective upon receipt by Nevada. 1.4 Seller's Qualifying Facility: 1.4.1 Prior to Firm Operation, Seller shall obtain Qualifying Facility status for Seller's Generating Facility and shall maintain qualification as required by the Federal Energy Regulatory Commission throughout the Contract Term. 1.4.2 Location: S.E. Corner of Alexander and Bruce North Las Vegas, Nevada 1.4.3 Contract Capacity: 45 MW. 1.4.4 Estimated Annual Energy Delivery: 208,000 MWH. 1.4.5 Fuel Type: Gas. 1.4.6 The expected date of Firm Operation for Seller's Facilities is June 1, 1994. Nevada's Facilities shall be completely constructed and capable of energization not later than February 1, 1994. 2. DEFINITIONS: Common electric utility industry terms shall have the meaning ascribed to them in the Edison Electric Institute "Glossary of Electric Utility Terms" (Pub. No. 04- 84-06). The following terms, whether used in the singular or plural, and when initially capitalized, shall have the indicated meanings: 2 2.1 Applicable Laws: Any effective law, rule, regulation, ordinance, order, code, judgment, decree, injunction, or decision of any federal, state, or local government, authority, agency, court, or other governmental body having jurisdiction over the matter in question. 2.2 Applicable Permits: Any action, approval, consent, waiver, exemption, variance, franchise, order, authorization, right, or license required in connection with Seller's Facilities. 2.3 Capacity: The kilowatts produced by Seller's Generating Facility and purchased by Nevada. 2.4 Commission: The Public Service Commission of Nevada. 2.5 Contract: This document and its attached exhibits, as amended. 2.6 Contract Capacity: The electric power producing capability of Seller's Generating Facility that is dedicated to Nevada and more specifically described in Section 1.4.3. 2.7 Contract Term: The period during which Nevada shall purchase Capacity or Energy, or both, from Seller and ending on the date set forth in Section 3.1. 2.8 Electric System Integrity: The state of operation of an electric system that maximizes the health, welfare, and safety of personnel and the general public; minimizes the risk of injury to personnel and the general public; minimizes the risk of damage to property; and maximizes the system's ability to provide electric service to customers in accordance with electric utility standards. 2.9 Emergency: Any condition that, in Nevada's judgment, adversely affects Nevada's Electric System Integrity. 2.10 Energy: The kilowatt-hours produced by Seller's Generating Facility that are purchased by Nevada. 2.11 Excess Capacity: Capacity that exceeds Contract Capacity. 2.12 Excess Energy: Energy associated with Excess Capacity. 2.13 Firm Operation: The date agreed upon by the Parties on which Seller complied with the requirements of Exhibit E. 3 2.14 Forced Outage: Any outage, other than a Scheduled Outage, that fully or partially curtails the production or delivery of Energy to Nevada. 2.15 Generating Facility: A plant containing prime movers, electric generators, and auxiliary equipment required to produce electric energy. 2.16 Interconnection Facilities: The facilities that shall be required to connect a Generating Facility to an electric system, and the incremental facilities that shall be required to transmit the output of a Generating Facility to distribution points on that electric system. 2.17 Interconnection Point: The point designated in Exhibit B where the transfer of electric energy between Nevada and Seller will take place. 2.18 Lender: The entities that have provided financing for Seller's Facilities. 2.19 Maintenance Months: As designated in Exhibit A, the months of March, April, October, and November. 2.20 Nevada: Nevada Power Company, its directors, officers, employees, and agents with authority to act on its behalf. 2.21 Off-Peak Hours: The hours designated in Exhibit A. 2.22 On-Peak Hours: The hours designated in Exhibit A. 2.23 Operating Communications: Any transmittals between the Parties of information required to ensure Nevada's Electric System Integrity. Provisions for Operating Communications are contained in Exhibit C. 2.24 Operating Representative: The individuals appointed by each Party to ensure effective communication, coordination, and cooperation between the Parties. Either Party may change its Operating Representative by providing written notice of the change to the other Party. Such changes shall not be considered amendments to this Contract. 2.25 Party: Nevada or Seller. 2.26 Qualifying Facility: A cogeneration or small power production facility that meets the criteria defined in Title 18, Code of Federal Regulations, Sections 292.201 through 292.207. 4 2.27 Scheduled Outage: Any outage, other than a Forced Outage, that shall fully or partially curtail the production and delivery of Seller's electric energy to Nevada and has been noticed in accordance with the requirements of this Contract. 2.28 Seller: The entity designated in Section 1, its directors, officers, employees, and agents with authority to act on its behalf. 2.29 Tariff: The rate schedules and service rules that have been promulgated by Nevada and approved by the Commission, as amended from time to time. Nevada's Tariffs shall be on file with the Commission. 2.30 Uncontrollable Force: Any occurrence beyond the reasonable control of a Party that renders a Party incapable of performing its obligations. Uncontrollable Forces shall include, but not be limited to floods, droughts, earthquakes, storms, fires, pestilence, lightning or other natural catastrophes; epidemics; wars; riots, civil disturbance, or other civil disobedience; strikes or other labor disputes; action or inaction of legislative, judicial, regulatory, or other governmental bodies that may render or may have rendered actions illegal in accordance with this Contract; and failure, threat of failure, or sabotage of facilities that have been operated and maintained in accordance with the requirements of this Contract. 3. CONTRACT TERMINATION AND MILESTONES: 3.1 This Contract shall become effective upon execution by the Parties and shall terminate on May 31, 2024 unless the Commission does not approve this Contract within ninety (90) days of receipt from Nevada; in that case, this Contract shall terminate ninety (90) days after Commission receipt. If, however, the docket assigned to this Contract is scheduled for hearing within ninety (90) days of receipt of this Contract by the Commission, then the Contract shall terminate six (6) months after the Commission's receipt if it has not been approved by the Commission according to Section 27. Any amendments to this Contract shall also be subject to the approval process described in this Section 3.1. 3.2 Seller has established the following milestones to demonstrate to Nevada diligent development of Seller's Facilities. 5 3.2.1 Not later than May 1, 1993, Seller shall provide Nevada a copy of Seller's Agreement with Seller's steam host. Confidential and proprietary information may be deleted from the submittal. 3.2.2 Not later than May 1, 1993, Seller shall obtain a firm, fifteen (15) year primary and secondary fuel supply and related transportation. Seller shall provide Nevada copies of signed agreements indicating accomplishment of this project development task. Confidential and proprietary information may be deleted from the submittals. 3.2.3 Not later than May 1, 1993, Seller shall provide Nevada a copy of Seller's water service agreement; zoning permits; Clark County Health District/Environmental Protection Agency Permit to Construct; and, Utility Environmental Protection Act (UEPA) Permit to construct as described in NRS 704.820 to 704.900, inclusive. 3.2.4 Not later than July 1, 1993, Lender shall provide Nevada a letter written on Lender's corporate letterhead stationery certifying that it is providing full project financing for Seller through Firm Operation. 3.2.5 Not later than April 1, 1993, Seller shall provide Nevada a copy of its Engineering, Procurement, and Construction (EPC) Contract evidencing consummation of a turnkey agreement for project construction. Confidential and proprietary information may be deleted from the submittal. 3.2.6 Not later than February 1, 1994, Seller shall start construction, i.e., pour first structural concrete, of Seller's Facilities. Commencing with start of construction, Seller shall provide Nevada copies of monthly construction progress reports. 3.2.7 Not later than May 1, 1994, Seller shall provide Nevada a copy of the Federal Energy Regulatory Commission (FERC) Order granting Application for Certification as a Qualifying Facility for Seller's Facilities. 6 3.2.8 Not later than January 1, 1995, Seller shall achieve Firm Operation of Seller's Facilities. If Seller does not achieve Firm Operation by June 1, 1994, for any reason, and Nevada must purchase replacement power between June 1, 1994 and January 1, 1995 at a cost higher than the contract rate, Seller agrees to reimburse Nevada the difference between Nevada's replacement power cost and the cost Nevada would have paid Seller for the same increment of power. 3.3 This contract shall be terminated thirty (30) days after Seller's failure to meet any milestone specified in Section 3.2, unless such failure has been caused by Nevada, or unless such failure has been cured by Seller or Lender within thirty (30) days of Seller's failure to meet the specified milestone. 3.3.1 The milestones of Section 3.2 shall be appropriately adjusted to reflect any delays caused by Nevada. 3.4 Termination of this Contract shall not excuse either Party from any obligations, other than Seller's obligation to deliver additional Capacity and Energy to Nevada, incurred by either Party prior to termination of this Contract. This Contract shall remain effective until both Parties have discharged their obligations and have exercised their rights and remedies in accordance with the provisions of this Contract. 4. CAPACITY AND ENERGY PAYMENT PROVISIONS: 4.1 Capacity Rates: 4.1.1 Starting with Firm Operation and continuing through the Contract Term, Seller shall be paid for Capacity at the rates agreed upon by the Parties and set forth in Exhibit A. 4.1.2 Prior to Firm Operation, Seller shall not be paid for capacity unless Nevada, because of operating conditions, experiences a capacity requirement that may be met by Seller, in which case Seller shall be paid for Capacity at Nevada's Tariff Schedule QF-Short Term Capacity rates effective at the time of delivery. 4.1.3 Seller shall not be paid for Excess Capacity unless Nevada, because of operating conditions, experiences a capacity requirement that may be met by Seller's Excess Capacity, in which case Seller shall be paid for Excess Capacity at Nevada's Tariff 7 Schedule QF-Short Term Capacity rates effective at the time of delivery. 4.1.4 If Seller obtains Qualifying Facility status prior to Firm Operation and subsequent to Firm Operation loses such status for reasons beyond Seller's reasonable control, Seller shall be paid for Capacity delivered to Nevada during the periods that Seller does not have Qualifying Facility status at rates equal to eighty (80) percent of the Capacity rates otherwise agreed upon by the Parties. 4.2 Energy Rates: 4.2.1 Starting with Firm Operation and continuing through the Contract Term, Seller shall be paid for Energy at the rates agreed upon by the Parties and set forth in Exhibit A. 4.2.2 Prior to Firm Operation, Seller shall be paid for Energy at Nevada's Tariff Schedule QF-Short Term Energy rates effective at the time of delivery. 4.2.3 Seller shall be paid for Excess Energy at Nevada's Tariff Schedule QF-Short Term Energy rates effective at the time of delivery. 4.2.4 If Seller obtains Qualifying Facility status prior to Firm Operation and subsequent to Firm Operation loses such status for reasons beyond Seller's reasonable control, Seller shall be paid for Energy delivered to Nevada during the periods that Seller does not have Qualifying Facility status at Energy rates equal to eighty (80) percent of the Energy rates otherwise agreed upon by the Parties. 4.3 Payment Procedures: 4.3.1 Not later than thirty (30) days after the end of each monthly payment period, Nevada shall send Seller a statement showing the Capacity and Energy received by Nevada during the payment period and Nevada's check in payment of the amount due Seller. If two or more rates are applicable to any payment period, Nevada's payment shall be based upon the amount of Capacity and Energy received by Nevada during the period each rate was applicable, or, if such information is unavailable, Nevada's payment shall be based upon the number of hours each rate was applicable. 8 4.3.2 Seller shall have the right of access to Nevada's records that are reasonably required to confirm the accuracy of Nevada's statement. Within thirty (30) days of Seller's receipt of Nevada's statement, Seller shall notify Nevada in writing of any error in Nevada's statement. If Seller fails to provide such notice, Seller shall waive all rights to an adjusted payment for the subject payment period. If Seller notifies Nevada of an error in Nevada's statement, or if Nevada discovers an error in its statement within thirty (30) days of issuing the statement, Nevada shall provide an adjusted statement to Seller. If Nevada's error results in an additional payment to Seller, Nevada's check in payment of the amount due Seller shall accompany the adjusted statement. If Nevada's error results in a refund to Nevada, Nevada's bill for the amount due Nevada shall accompany the adjusted statement. 5. CAPACITY REQUIREMENTS: Unless otherwise provided within this section, Uncontrollable Forces shall not excuse Seller from the performance requirements of this section. 5.1 Performance Requirements: Unless otherwise instructed by Nevada, Seller shall make Contract Capacity available to Nevada during On-Peak hours during the Contract Term. Seller shall be considered to have met that obligation whenever Seller meets or exceeds the performance requirements of this Section 5. 5.1.1 Summer Season: For the purposes of this section, a summer season shall include May, June, July, August, and September. During a summer season, total Energy produced and delivered to Nevada during the On-Peak hours of that season must equal or exceed the product of Contract Capacity, the number of On-Peak hours during that season, and 0.90. 5.1.2 Winter Season: For the purposes of this section, a winter season shall include the months of December, January, and February. During a winter season, total Energy produced and delivered to Nevada during the On-Peak hours of that season must equal or exceed the product of Contract Capacity, the number of On-Peak hours during that season, and 0.90. 9 5.1.3 For the purposes of this section, On-Peak hours shall be those hours designated in Exhibit A for the summer and winter seasons less any coincidental operating hours lost because of the occurrence of the events expressly listed in Sections 5.2.1 and 5.3.1. 5.2 Summer Probation: 5.2.1 If, for reasons other than limitations imposed by Nevada, or natural catastrophes, epidemics, wars, civil disobedience, or sabotage of facilities, Seller fails to meet the performance requirements of Section 5.1.1 during any summer season, Seller shall be placed on summer probation for a period not to exceed twelve (12) months. 5.2.2 If, for reasons other than limitations imposed by Nevada, Seller fails to produce and deliver Energy to Nevada that equals or exceeds the product of Contract Capacity, the number of On-Peak hours in the month, and 0.90 during any month of a summer season within a summer probationary period, Nevada shall have the right to extend the summer probationary period for an additional twelve (12) months or to reduce Contract Capacity to a level not less than the average capacity level achieved by Seller during the On-Peak hours of the preceding summer season. 5.2.3 If Seller meets the performance requirements of this Contract during each month of a summer season within a summer probationary period, Seller shall be taken off summer probation. Seller shall also be taken off summer probation if Seller demonstrates, to Nevada's reasonable satisfaction that the problems which caused Seller to be placed on summer probation have been rectified, and Seller is able to produce and deliver Contract Capacity to Nevada in accordance with the requirements of this Contract. 5.3 Winter Probation: 5.3.1 If, for reasons other than limitations imposed by Nevada, or natural catastrophes, epidemics, wars, civil disobedience, or sabotage of facilities, Seller fails to meet the performance requirements of Section 5.1.2 during any winter season, Seller shall be placed on winter probation for a period not to exceed twelve (12) months. 10 5.3.2 If, for reasons other than limitations imposed by Nevada, Seller fails to produce and deliver Energy to Nevada that equals or exceeds the product of Contract Capacity, the number of On-Peak hours in the month, and 0.90 during any month of a winter season within a winter probationary period, Nevada shall have the right to extend the winter probationary period for an additional twelve (12) months or to reduce Contract Capacity to a level not less than the average capacity level achieved by Seller during the On-Peak hours of the preceding winter season. 5.3.3 If Seller meets the performance requirements of this Contract during each month of a winter season within a winter probationary period, Seller shall be taken off winter probation. Seller shall also be taken off winter probation if Seller demonstrates, to Nevada's reasonable satisfaction, that the problems which caused Seller to be placed on winter probation have been rectified, and that Seller is able to provide Contract Capacity in accordance with the requirements of this Contract. 5.4 Contract Capacity Changes: If Contract Capacity is reduced for any reason the requirements and provisions of this Contract shall remain applicable in their entirety to the reduced capacity. If contract Capacity is reduced for any reason, Seller shall, upon receipt of Nevada's bill, refund to Nevada with interest at the rate established by the Commission for Nevada's overall rate of return, all payments to Seller in excess of the amount that would have been paid if Contract Capacity reduction had been in effect for the time periods shown in the following table. Contract Capacity In Reduction Effect 0 to 1,000 kW 1 year 1,001 to 70,000 kW 3 years 6. CAPACITY AND ENERGY METERING: 6.1 Unless otherwise agreed upon by the Parties and set forth in Exhibit B, meters and metering equipment to measure Capacity and Energy shall be provided, owned, operated, and maintained by Nevada as Nevada's Facilities. 6.2 Meters and metering equipment shall be installed in locations designated by Nevada in Exhibit B. If the meters and metering equipment are installed at locations other than the Interconnection Point, Nevada shall have the right to install loss compensation equipment to reflect the losses that would have been recorded by the 11 meters if the meters and metering equipment had been installed at the Interconnection Point. 6.3 Seller shall not undertake any action that may interfere with the operation of Nevada's meters and metering equipment. If Seller fails to comply with the requirements of this section, Nevada shall have the right, without liability, to isolate Seller's Facilities from Nevada's electric system until Nevada's meters and metering equipment are reinstalled in a location that is inaccessible to Seller. 6.4 Nevada's meters and metering equipment shall be tested and calibrated upon installation and thereafter at intervals not to exceed two (2) years in accordance with the provisions of the American National Standard Institute Code for Electricity Metering (ANSI C12.1, latest revision). Nevada shall provide fifteen (15) days prior written notice of meter testing to Seller. Seller shall have the right to monitor Nevada's meter testing. Seller shall also have the right to request additional testing and calibration of Nevada's meters and metering equipment. If so requested in writing, Nevada shall test and calibrate Nevada's meters and metering equipment within thirty (30) days of receipt of Seller's request. If the accuracy of Nevada's meters and metering equipment is within the limits established in ANSI C12.1, Seller shall bear the cost of such additional tests. Billing for such costs shall be in accordance with the requirements of Section 13 or Exhibit B, whichever is applicable. If the accuracy of Nevada's meters and metering equipment is outside the limits established in ANSI C12.1, Nevada shall bear the cost of such additional tests. 6.5 If the accuracy of Nevada's meters and metering equipment is outside the limits established in ANSI C12.1, Nevada shall repair and recalibrate or replace Nevada's meters and metering equipment, and Nevada shall adjust payments to Seller for Capacity and Energy delivered to Nevada during the period in which the inaccuracy existed. If the period in which the inaccuracy existed cannot be determined, adjustments shall be made for a period equal to one-half of the elapsed time since the last test and calibration of Nevada's meters and metering equipment; however, the adjustment period shall not exceed six (6) months. If adjustments are required, Nevada shall render a statement describing the adjustments to Seller within thirty (30) days of the date on which the inaccuracy was rectified. Additional payments to Seller, or Nevada's bill for refunds due Nevada, as applicable, shall accompany Nevada's statement. 12 6.6 If Nevada's meters fail to register, Nevada shall make payments to Seller that are based upon Nevada's estimate of the best available alternative information. Nevada's estimated payments shall have the same meaning as actual payments. 7. SELLER'S FACILITIES: Seller's Facilities shall mean Seller's Generating Facility and Seller's Interconnection Facilities. Seller's Interconnection Facilities are described in Exhibit B. 7.1 Ownership: Seller's Facilities may be leased or owned, and shall be designed, constructed, operated, maintained, and improved by Seller. All costs associated with Seller's Facilities, whether incurred by Nevada or by Seller, shall be borne by Seller. 7.2 General: 7.2.1 Nevada shall have the right, without liability, to either isolate Seller's Facilities from Nevada's electric system or to refuse to connect Seller's Facilities to Nevada's electric system if Seller fails to comply with any of the requirements of this Contract and adversely affects Nevada's Electric System Integrity. Nevada shall also have the right, without liability, to either isolate Seller's Facilities from Nevada's electric system or to refuse to connect Seller's Facilities to Nevada's electric system if failure to do so would render Nevada's conduct unlawful. 7.2.2 Seller shall neither solicit nor accept advice from any Nevada representative except Nevada's Operating Representative. If requested by Seller, Nevada's Operating Representative shall provide, to the extent possible, advice to Seller relative to the design, construction, operation, maintenance, and improvement of Seller's Facilities. Such advice shall be provided as a courtesy. Seller shall save harmless and indemnify Nevada from any direct or indirect loss or liability, including attorney's fees and other costs of litigation, resulting from Seller's implementation of Nevada's advice. 7.2.3 Seller shall design, construct, operate, maintain, and improve Seller's Facilities in accordance with prudent engineering, construction, operation, and maintenance practices. Seller shall comply with all Applicable Laws even if compliance necessitates improvements to Seller's Facilities or interferes with the operation of Seller's Facilities. In addition, Seller shall operate 13 Seller's Facilities so as to ensure, to a reasonable extent, the production and delivery of electric energy to Nevada consistent with Nevada's requirements. If Seller fails to comply with the requirements of this section, Seller shall save harmless and indemnify Nevada from any direct or indirect loss or liability, including attorney's fees and other costs of litigation, resulting from Seller's failure to comply with these requirements. 7.2.4 Nevada shall have the right, without liability, to monitor and make recommendations to Seller regarding any aspect of the construction, operation, maintenance, and improvement of Seller's Facilities provided that such recommendations, if implemented, do not unreasonably interfere with the construction, operation, maintenance, or improvement of Seller's Facilities and, provided further, that such recommendations are required, in Nevada's reasonable judgment, to maintain Nevada's Electric System Integrity or to ensure compliance with the requirements of this Contract. Nevada's recommendations shall be made as a courtesy. Seller shall save harmless and indemnify Nevada from any direct or indirect loss or liability, including attorney's fees and other costs of litigation, resulting from Seller's implementation of Nevada's recommendations. 7.2.5 Seller shall acquire and maintain all Applicable Permits for Seller's Facilities. 7.2.6 Seller shall acquire and maintain all easements, rights-of-way, and land rights required for Seller's Facilities. 7.2.7 Seller shall complete all environmental impact studies required for Seller's Facilities. 7.2.8 Seller shall complete all feasibility studies required for Seller's Facilities. 7.3 Design: 7.3.1 Seller shall design Seller's Facilities so that those facilities do not impose any voltage or current upon Nevada's system that could interfere with Nevada's operations, lower the quality of service to Nevada's customers, or interfere with the operation of any communications facilities. 14 7.3.2 Seller shall design Seller's Facilities so that those facilities are protected from damage that could result from disturbances on Nevada's electric system or the electric systems to which Nevada is interconnected. 7.3.3 Seller shall design Seller's Facilities so that those facilities incorporate reactive power equipment capable of maintaining a power factor ranging from 0.90 lagging to 0.90 leading at the Interconnection Point whenever Capacity is being delivered to Nevada at that point. 7.3.4 Seller shall design Seller's Facilities so that they incorporate two separate, independent fuel supplies and transportation systems throughout the term of the Contract. The design should assure that Seller's Generating Facility will be available during periods when fuel supply curtailments might otherwise limit the delivery of Contract Capacity and Energy to Nevada. Proof of compliance with this Section 7.3.4 will be submitted to the Commission following approval of the Contract. 7.3.5 Seller shall provide those drawings and specifications reasonably required by Nevada to accomplish its design review. Nevada shall review and specify modifications to the design of Seller's Facilities if necessary to maintain Nevada's Electric System Integrity and to ensure compliance with the requirements of this Contract. In conjunction with Nevada's design review, Nevada shall designate the minimum set of protective devices that shall be required to protect Nevada's electric system whenever any of Seller's Facilities are connected to Nevada's electric system. Nevada shall not unreasonably withhold or delay its review of any design related drawing or specification that has been submitted to Nevada for review and approval. 7.3.6 Seller shall modify Seller's design as reasonably required by Nevada and shall provide revised drawings and specifications that are required by Nevada to confirm compliance with Nevada's requirements. 7.4 Construction: 7.4.1 Prior to the start of Seller's construction, Seller shall furnish Nevada a construction schedule for Seller's Facilities. Upon receipt of pertinent information, Seller shall notify Nevada of any 15 changes in that construction schedule that may affect or may have affected Firm Operation. 7.4.2 Seller shall construct Seller's Facilities in accordance with Seller's design as modified to reflect the changes, if any, that are reasonably required by Nevada. Seller shall furnish and install all equipment that may be reasonably required by Nevada to maintain Nevada's Electric System Integrity and to ensure compliance with the requirements of this Contract. 7.4.3 Seller shall provide to Nevada, as reasonably required by Nevada, "as built" drawings and specifications for Seller's Facilities. 7.5 Initial Operation: 7.5.1 Seller shall not connect any of Seller's Facilities to Nevada's electric system or operate any of Seller's generators in parallel with Nevada's electric system, without the prior written approval of Nevada's Operating Representative and without properly calibrated, tested, and fully operational protective devices in service, as designated by Nevada. Nevada's approval shall not be unreasonably withheld or delayed. If Nevada's approval is withheld, Nevada shall provide Seller a written explanation including a list of required remedial actions within fifteen (15) days of the date Nevada withheld its approval. 7.5.2 Seller shall notify Nevada's Operating Representative at least fifteen (15) days prior to initial energization of any of Seller's Interconnection Facilities. Nevada shall then inspect Seller's Interconnection Facilities and approve initial energization if, in Nevada's reasonable judgment, Seller's Facilities can be energized without adversely affecting Nevada's Electric System Integrity. Nevada's approval shall be in writing. 7.5.3 Seller shall notify Nevada's Operating Representative at least fifteen (15) days prior to initial testing and calibration of Seller's protective devices. Nevada shall inspect and approve Seller's protective devices after that initial testing and calibration if Seller has demonstrated, to Nevada's reasonable satisfaction, the correct calibration and operation of Seller's protective devices. Nevada's approval shall be in writing. 16 7.5.4 Seller shall notify Nevada's Operating Representative at least fifteen (15) days prior to initial operation of any of Seller's generators in parallel with Nevada's electric system. Nevada shall inspect and approve Seller's generators prior to initial operation of those generators in parallel with Nevada's electric system if Seller has demonstrated, to Nevada's reasonable satisfaction, the ability to synchronize Seller's generators with Nevada's electric system, and to operate Seller's generators in parallel with Nevada's electric system without adversely affecting Nevada's Electric System Integrity. Nevada's approval shall be in writing. 7.5.5 Prior to Firm Operation, Seller shall demonstrate, to Nevada's reasonable satisfaction, the ability to produce and deliver Contract Capacity to Nevada. Seller's demonstration shall be according to the procedures set forth in Exhibit E. If Seller fails to demonstrate the ability to produce and deliver Contract Capacity to Nevada, Nevada shall have the right, without liability, to reduce Contract Capacity to the level Seller is able to produce and deliver. 7.6 Operation and Maintenance: 7.6.1 To the extent set forth in Exhibit C, Seller shall maintain Operating Communications with Nevada. 7.6.2 Seller shall neither connect any of Seller's Facilities to Nevada's electric system nor operate a generator in parallel with Nevada's electric system without the prior approval of Nevada's Operating Representative. Procedures for obtaining such approval are set forth in Exhibit C. 7.6.3 Nevada shall have the right to require Seller to reduce the output of Seller's Generating Facility or to isolate any of Seller's Facilities from Nevada's electric system if, in Nevada's reasonable judgment, such actions are required to facilitate the maintenance of any of Nevada's facilities or to maintain Nevada's Electric System Integrity. Nevada shall, within a reasonable period of time and to the extent possible, endeavor to correct the condition that necessitated the reduction or isolation. The duration of such reduction or isolation shall be limited to the period of time that the condition exists plus a reasonable period of time for the restoration of Nevada's electric system to an operating condition that allows Nevada to resume the discharge of its obligations in accordance with the requirements of this Contract. 17 In accordance with 18 CFR Section 292.304(f), Nevada shall also have the right to require Seller to reduce the delivery of electric energy to Nevada during Off-Peak or light-load hours when, due to operational circumstances other than economic dispatch, purchases from Seller will result in costs greater than those that Nevada may otherwise incur if Nevada generates or purchases an equivalent amount of energy. Nevada shall provide one (1) hour's oral notice of such reduction to Seller. The exercise of Nevada's right shall be subject to a calendar year energy limitation equal to the product of Contract Capacity and one thousand (1,000) hours. The amount of energy curtailed shall be determined by multiplying the hours of curtailment by the magnitude of the reduction below Seller's average rate of delivery (KW) to Nevada during the hour immediately preceding the start of curtailment. If Nevada requires Seller to reduce the output of Seller's Generating Facility or to isolate any of Seller's Facilities from Nevada's electric system, Seller shall neither increase the output nor reconnect the isolated facilities without the prior approval of Nevada's Operating Representative. Provisions for obtaining such approval are set forth in Exhibit C. 7.6.4 Seller shall avoid the imposition of any voltage or current upon Nevada's electric system that interferes with Nevada's operations, distorts the electric service provided to Nevada's customers, or interferes with the operation of any communications facilities. If Seller imposes such a voltage or current upon Nevada's electric system, Seller shall, immediately upon learning of such condition, pursue and implement remedial measures. 7.6.5 Except as otherwise agreed upon by the Parties' Operating Representatives, Seller shall have all of Seller's protective devices, as designated by Nevada, in service whenever Seller's Facilities are connected to Nevada's electric system. 7.6.6 Seller shall provide Seller's reactive power requirements. Seller shall also provide reactive power reasonably required by Nevada to maintain Nevada's Electric System Integrity, provided that such requirements are consistent with the capabilities of Seller's Facilities and do not adversely affect Seller's ability to provide Capacity and Energy to Nevada in accordance with 18 the requirements of this Contract. Seller shall not deliver excess reactive power to Nevada without the prior approval of Nevada's Operating Representative. Procedures for obtaining such approval are set forth in Exhibit C. 7.6.7 Seller shall maintain operation and maintenance logs for Seller's Facilities that contain such data as are set forth in Exhibit C. Nevada shall have the right to inspect or request a copy of Seller's operation and maintenance logs. If so requested, Seller shall provide the copy within five (5) days of Seller's receipt of Nevada's request. 7.6.8 Seller shall notify Nevada's Operating Representative of any condition that may have affected Seller's ability to produce and deliver Contract Capacity to Nevada. Procedures for such notice are set forth in Exhibit C. 7.6.9 If Nevada, as a result of participation in a power pool or coordinating council, is required to routinely demonstrate the capacity of its generating facilities, Seller shall routinely demonstrate, to Nevada's reasonable satisfaction, the ability to produce and deliver Contract Capacity to Nevada. Seller's demonstrations shall be in accordance with the procedures established by the power pool or coordinating council. 7.6.10 If Nevada, as a result of participation in a power pool or coordinating council, is required to comply with the operating criteria of that power pool or coordinating council, Seller shall also comply with those operating criteria. The criteria which Seller shall comply with are set forth in Exhibit C. 7.6.11 Seller shall notify Nevada's Operating Representative in advance of all Scheduled Outages. Unless the Parties' Operating Representatives agree otherwise, the minimum required advance notice shall be two (2) days if the expected outage duration is less than one (1) day; five (5) days if the expected outage duration is between one (1) and five (5) days; and, fifteen (15) days if the expected outage duration is longer than five (5) days. Procedures for Seller's notices are set forth in Exhibit C. Unless operating conditions dictate otherwise, Seller shall schedule all outages of expected duration of less than five (5) days for completion during the period designated by Nevada's Operating 19 Representative. Unless operating conditions dictate otherwise, Seller shall schedule all outages of expected duration of greater than five (5) days for completion during Maintenance Months as designated by Nevada's Operating Representative. 7.6.12 If requested by Nevada's Operating Representative, Seller shall, at no additional cost to Nevada, make every reasonable effort to produce Contract Capacity in case of an Emergency during On-Peak hours. If Seller has scheduled an outage when the Emergency occurs, Seller shall make every reasonable effort to reschedule the outage. Nevada waives the minimum notice requirements of Section 7.6.11 if Seller, at Nevada's request, does not take a properly scheduled outage and subsequently seeks to reschedule that outage. 7.6.13 Seller shall test and calibrate Seller's protective devices at intervals agreed upon by the Parties' Operating Representatives, but not more than every four (4) years. Seller shall notify Nevada's Operating Representative at least thirty (30) days prior to such testing and calibration. Procedures for Seller's notices are set forth in Exhibit C. If Nevada, because of an analysis of operating conditions, or the addition of facilities to Nevada's electric system, or the modification of facilities on Nevada's electric system, has reason to doubt the effectiveness of Seller's protective devices, Nevada shall have the right, without liability, to require Seller to retest and recalibrate those devices and to demonstrate, to Nevada's reasonable satisfaction and at no additional cost to Nevada, the proper calibration and operation of those devices. If operating conditions allow, Nevada shall also have the right, without liability, to retest and recalibrate those devices and to bill Seller for the associated costs in accordance with the provisions of Section 13 or Exhibit B, whichever is applicable. 7.7 Nevada's Review: Any review of the design, construction, operation, maintenance, or improvement of Seller's Facilities by Nevada is solely for Nevada. Nevada makes no representation as to the economic or technical feasibility or suitability of any of Seller's Facilities for any purpose. Seller shall not represent to any third party that Nevada's review constitutes such a representation. 20 8. NEVADA'S FACILITIES: Nevada shall, as agreed upon by the Parties and set forth in Exhibit B, provide facilities required to implement the requirements of this Contract. Nevada's Facilities shall be those facilities designated in Exhibit B. 8.1 Ownership: Nevada's Facilities shall be owned, designed, constructed, operated, maintained, and improved by Nevada. Unless otherwise agreed upon by the Parties and set forth in Exhibit B, all costs associated with Nevada's Facilities, whether incurred by Nevada or by Seller, shall be borne by Seller. 8.2 Construction Cost and Deposits: 8.2.1 The estimated cost of Nevada's Facilities for which Seller shall have cost responsibility shall be determined according to procedures set forth in Exhibit B1. 8.2.2 Within thirty (30) days of Commission approval of this Contract, Seller shall deposit the estimated cost of Nevada's Facilities with Nevada. Failure to do so shall be cause for immediate cancellation of this Contract by Nevada. Seller's cost for the design and construction of that portion of Nevada's Facilities for which Seller has deposited the estimated cost with Nevada shall be adjusted to Nevada's actual cost after the facilities are complete. If Seller's construction deposits exceed Nevada's actual cost, Nevada shall refund the excess to Seller within sixty (60) days of completing those facilities. If Nevada's actual cost exceeds Seller's construction deposits, Nevada shall bill Seller for the excess cost. Seller shall have sixty (60) days to remit payment to Nevada for Nevada's excess construction costs. Failure to do so shall be cause for immediate cancellation of this Contract by Nevada. 8.2.3 If any portion of Nevada's Facilities which Seller has paid for is used for the sale of electric energy to Seller and related parties as defined in Internal Revenue Service Advance Notice 88-129, and if the electric energy that is sold to Seller and related parties is projected to exceed five (5) percent of the electric energy sold to Nevada by Seller under the provisions of this Contract, the estimated cost of such facilities shall be increased by 30.185 percent to cover the income tax liability attributable to such facilities. 8.2.4 If any portion of Nevada's Facilities which Seller has paid for is deemed "nontaxable" for the 21 purposes of Section 8.2.3, and if those facilities subsequently become taxable, Nevada shall bill Seller for the income tax liability attributable to such facilities because of the sales to Seller and related parties. 8.3 Construction: Prior to the start of construction, Nevada shall furnish a construction schedule for Nevada's Facilities to Seller. Nevada shall notify Seller of any changes in that schedule that may affect or may have affected Firm Operation. Seller shall release Nevada from any direct or indirect loss and liability, including attorney's fees and other costs of litigation, resulting from any delay in completing Nevada's Facilities that is caused by Seller or by circumstances beyond Nevada's reasonable control. 8.4 Project Abandonment: If this Contract is terminated prior to Firm Operation, Seller shall bear all costs associated with Nevada's Facilities that were incurred by Nevada prior to Contract termination plus all removal and abandonment costs incurred by Nevada subsequent to contract termination. Seller's cost for the design, construction, and removal and abandonment of Nevada's Facilities shall be adjusted to Nevada's actual cost net of salvage value after Nevada's removal and abandonment activities are complete. 8.5 Operation and Maintenance: 8.5.1 Nevada shall operate and maintain Nevada's Facilities in accordance with Nevada's methods of operation and maintenance. 8.5.2 Nevada shall notify Seller's Operating Representative of any condition that may affect or may have affected Seller's ability to produce and deliver Contract Capacity to Nevada. 8.5.3 Unless otherwise agreed upon by the Parties and set forth in Exhibit B, Nevada shall render monthly bills to Seller for direct and indirect operation and maintenance costs associated with Nevada's Facilities that were incurred by Nevada during the billing period. Indirect costs shall include, but not be limited to, labor loadings for administrative and general, FICA, bodily injury insurance, property damage insurance, group insurance, industrial insurance, holiday pay, sick leave, vacation pay, 22 pension plans, supervision, tools, transportation, and unemployment taxes. 9. INTERCONNECTION FACILITIES AGREEMENT: Upon execution of this Contract, the Parties shall execute an Interconnection Facilities Agreement which shall be attached to this Contract as Exhibit B. 10. OPERATIONS COORDINATION AGREEMENT: Upon execution of this Contract, the Parties shall execute an Operations Coordination Agreement which shall be attached to this Contract as Exhibit C. 11. IMPROVEMENTS AGREEMENTS: If improvements are required, the Parties shall execute Improvements Agreements which shall be attached to this Contract as Exhibit D. Improvements shall include any modifications and additions to Seller's Interconnection Facilities or Nevada's Facilities that are required to maintain Nevada's Electric System Integrity or to comply with the directive of any governmental body. The execution of Improvements Agreements shall not obligate Nevada to increase the rates set forth in Exhibit A or to otherwise compensate Seller for costs incurred by Seller as a result of implementing the Improvements Agreements. 12. ESCROW PROVISIONS: Upon execution of this Contract, Seller shall deposit with Nevada an amount equal to $5.00 per kilowatt of Contract Capacity. Within thirty (30) days of Commission approval of this Contract, Seller shall deposit with Nevada an additional amount equal to $20.00 per kilowatt of Contract Capacity. Seller's deposits shall be in addition to any other deposits required under this Contract. Seller's deposits shall be placed in escrow and shall accrue interest at the rate set by the Commission for interest paid on customer deposits. 12.1 If this Contract is not approved by the Commission, Seller's escrow deposit and accrued interest shall be refunded to Seller within sixty (60) days of the Commission's failure to approve this Contract. 12.2 If Seller achieves Firm Operation at the level of capacity specified in Section 1.4.3, Seller's escrow deposits and accrued interest shall be refunded to Seller within sixty (60) days of Firm Operation. 12.3 If Seller achieves Firm Operation at a capacity level less than the level specified in Section 1.4.3, the refund of Seller's escrow deposits and accrued interest shall be prorated on the basis of actual performance. That portion of Seller's escrow deposits and accrued interest attributed to Seller's actual performance shall be refunded to Seller; the balance shall be totally 23 forfeited to Nevada. Seller's refund shall be sent to Seller within sixty (60) days of Firm Operation. 12.4 If Seller fails to achieve Firm Operation at any level, Seller's escrow deposits and accrued interest shall be totally forfeited to Nevada. 12.5 Instead of cash deposits, Seller may substitute irrevocable letters of credit or surety bonds in the amounts of the escrow deposits. Such irrevocable letters of credit or surety bonds shall be in a form acceptable to Nevada. 13. BILLING PROVISIONS: Nevada's bills rendered in accordance with the requirements of this Contract shall be due upon receipt by Seller and payable within twenty (20) days of receipt by Seller. Seller shall make every reasonable effort to pay Nevada's bills promptly. If Seller fails to make timely payment of any of Nevada's bills, Nevada shall have the right, without liability, to withhold the amount due Nevada from payments due Seller for Capacity and Energy. Also, if Seller fails to make timely payment of any of Nevada's bills, Nevada shall have the right to exercise any other rights and remedies available to Nevada under the provisions of this Contract. 14. ASSIGNMENT AND DELEGATION: Neither Party shall assign any right nor delegate any duty under this Contract without the written consent of the other Party. Consent for assignment or delegation shall not be unreasonably withheld or delayed. Nevada hereby gives Seller the right to assign Seller's rights under this Contract as collateral in conjunction with project financing. However, Seller shall notify Nevada in writing within ten (10) working days following such assignment as collateral for project financing. Failure of Seller to accordingly notify Nevada shall nullify Nevada's consent for such assignment. If Seller assigns Seller's rights under this Contract as collateral in conjunction with project financing, and if Seller fails to perform in accordance with the terms and conditions of this Contract, then upon receipt of Nevada's written notice to Seller and Lender of such failure, Lender shall have the right to appoint, subject to Nevada's prior written approval, operating agents who shall assume responsibility for the construction, operation, and maintenance of Seller's Facilities. Nevada's approval shall not be unreasonably withheld or delayed. If Lender's operating agents fail to cure, or fail to commence action with all due diligence to cure, Seller's default within thirty (30) days of receipt of Nevada's written notification of such default, Nevada shall have the right without liability to terminate this Contract. 24 Nevada shall also have the right to assume responsibility for the operation and maintenance of Seller's Facilities if Seller fails to perform in accordance with the terms and conditions of this Contract, and Lender fails to appoint operating agents to assume responsibility for the operation and maintenance of Seller's Facilities. However, if Nevada does not assume responsibility for the operation and maintenance of Seller's Facility, Nevada's failure to assume such responsibility in accordance with the provisions of this Contract shall not be deemed a waiver of any right or remedy Nevada may have under this Contract. 15. TAXES: 15.1 Seller and Nevada shall each pay ad valorem and other taxes properly attributed to their respective facilities. 15.2 Seller and Nevada shall provide information concerning either Party's Facilities to any tax authority. 15.3 Nevada shall pay franchise and other taxes properly attributed to Nevada's resale of Capacity and Energy. 16. LIABILITY: 16.1 Neither Party shall be saved harmless and indemnified from any loss and liability resulting from that Party's negligence or willful misconduct. 16.2 Each Party shall release the other Party from any direct or indirect loss and liability, including attorney's fees and other costs of litigation, resulting from damages to property of the releasing Party arising out of the other Party's efforts to perform its obligations under this Contract, if such damages were not caused by negligence or willful misconduct of the indemnified Party. 16.3 Each Party shall be solely responsible for the costs and liability of all claims brought by its employees or contractors, and shall save harmless and indemnify the other Party from all such costs and liability. Costs arising out of worker's compensation laws shall be considered employee related claims for the purposes of this section. 16.4 Each Party shall save harmless and indemnify the other Party from any direct or indirect loss and liability, including attorney's fees and other costs of litigation, resulting from the injury or death of any person and damage to any property of a third party arising out of the indemnifying Party's performance of obligations under this Contract if such injury, death, or damage was not 25 caused by negligence or willful misconduct of the indemnified Party. 16.5 If the Commission does not approve this Contract in accordance with Section 27 of the Contract, Seller shall release Nevada from any direct or indirect loss and liability, including attorney's fees and other costs of litigation, resulting from the actions of both Parties prior to the Commission's failure to approve the Contract. 17. INSURANCE: Until this Contract has been terminated, Seller shall maintain comprehensive general liability coverage with a minimum combined single limit per occurrence of five million dollars ($5,000,000.00). Seller's insurance policy shall be subject to Nevada's approval. Seller shall deliver a copy of Seller's insurance policy to Nevada prior to the date Seller's Interconnection Facilities are first energized. Seller's insurance policy shall provide for thirty (30) days written notice to Nevada of alteration or termination. Seller shall also provide an insured endorsement to Nevada in the form set forth in Exhibit F. If Seller fails to comply with the provisions of this section, Seller shall save harmless and indemnify Nevada from any direct or indirect loss and liability, including attorney's fees and other cost of litigation, resulting from the injury or death of any person or damage to any property if Nevada would have been protected had Seller complied with these requirements. If Seller fails to comply with the requirements of this section, Nevada shall have the right, without liability, to either refuse to connect Seller's Facilities to Nevada's system or to isolate Seller's Facilities from Nevada's system. Once isolated, Seller's Facilities shall remain isolated until Seller is in compliance with these requirements. 18. UNCONTROLLABLE FORCES: Except as otherwise provided in Section 5, if Uncontrollable Forces renders a Party wholly or partially unable to perform any obligations under this Contract, the non-performing Party shall be excused from such performance if that Party delivers a written description of the problem to the other Party within two weeks of the occurrence. Statements should be included that the suspension of performance was no greater in magnitude and no longer in duration than was dictated by the problem; that the non- performing Party made every reasonable effort to alleviate the problem; and that the non-performing Party notified the other Party in writing as soon as the non-performing Party was able to resume full performance of its obligations under this Contract. Neither Party shall be required to settle any labor dispute on terms it considers are contrary to its best interests. 26 19. NON-DEDICATION OF FACILITIES: By this Contract, neither Party dedicates any part of its facilities to the public or to the service provided under this Contract. Such service shall cease upon termination of this Contract. 20. AMENDMENTS: Unless otherwise specified herein, all modifications to this Contract shall require Contract amendments. Amendments shall be in writing and shall be executed by both Parties, and shall be filed with the Commission for approval. 21. PREVIOUS COMMUNICATIONS: This Contract contains the entire agreement and understanding between the Parties thereby merging and superseding all prior agreements and representations by the Parties. 22. NON-WAIVER: Any waiver of the requirements or provisions of this Contract shall be in writing. The failure of either Party to insist upon strict performance of Contract requirements or provisions or to exercise any Contract right shall not be construed as a waiver of such Contract requirement or provision or a relinquishment of such Contract right. 23. DISPUTES: The Parties shall negotiate in good faith and attempt to resolve any dispute arising between the Parties and requiring an interpretation of the provisions of this Contract. However, if the Parties are unable to resolve any such dispute, either Party shall have the right to submit a demand to the other Party that such dispute be arbitrated. If such a demand is submitted, the dispute shall be resolved by arbitration conducted in accordance with the rules of the American Arbitration Association (AAA). The demanding Party shall file a request with the AAA for the selection, pursuant to the AAA rules, of a member of the AAA in good standing who shall serve as the sole arbitrator. After the arbitrator has been selected, the arbitration shall be held in Las Vegas, Nevada. The Parties shall proceed with the arbitration expeditiously and shall conclude all proceedings thereunder so that a decision may be rendered within one hundred twenty (120) days of the submittal of the demand for arbitration. Pending resolution of a dispute, the Parties shall proceed diligently with the performance of their obligations under this Contract. The award of the arbitrator shall be final and binding on both Parties and shall be enforceable by any court having jurisdiction over the Party against whom enforcement is sought. Each Party shall bear its own costs associated with resolution of the dispute except that all costs associated with the arbitration shall be apportioned in the award of the arbitrator based upon the respective merit of the claims of the Parties. 24. REMEDIES: Except as otherwise set forth in this Contract, each Party, upon the other Party's failure to perform in 27 accordance with the requirements of this Contract, shall have the right to exercise any right or remedy that Party may have at law or in equity including but not limited to compensation for monetary damages such as the cost of removal or abandonment of Nevada's Facilities and the incremental cost of replacement power plus the incremental installed cost of replacement generation and transmission facilities, injunctive relief, and specific performance. Neither Party shall be liable for any indirect, consequential, incidental, punitive, or exemplary damages. If applicable, forfeited escrow deposits and refunded Capacity and Energy payments shall be subtracted from monetary damages due Nevada in accordance with the requirements of this section. 25. GOVERNING LAW: This Contract shall be interpreted under the laws of the State of Nevada as if executed and performed wholly within that state. 26. NATURE OF OBLIGATIONS: Unless otherwise agreed upon by the Parties and set forth herein, the duties, obligations, and liabilities of the Parties shall be several, not joint or collective. The requirements and provisions of this Contract shall not be construed as creating an association, trust, partnership, or joint venture, or as imposing a trust or partnership duty, obligation, or liability on either Party, or as creating any relationship between the Parties other than that of independent contractors for the sale and purchase of electric capacity and energy. Nothing in this Contract nor any action taken hereunder shall be construed as creating any duty, liability or standard of care to any person not a Party to this Contract. 27. COMMISSION APPROVAL: Within thirty (30) days of the Commission's acceptance of the stipulation entered into by the Parties in the Commission's Docket 91-10047, Nevada shall submit this Contract to the Commission for review and approval. This Contract shall be void if not approved by the Commission as executed. 28 28. SIGNATURES: IN WITNESS WHEREOF, the Parties hereto have executed this Contract this 27th day of May, 1992. NEVADA POWER COMPANY: LAS VEGAS COGENERATION LIMITED PARTNERSHIP: By: Steven W. Rigazio By: J. Thomas Fowlkes Name: Steven W. Rigazio Name: J. Thomas Fowlkes Title: Vice President Title: President Treas. & CFO United Cogen Corporation APPROVED AS TO FORM: Gloria Moore 29 EXHIBIT A Payment Provisions For the purposes of this exhibit, a summer season shall include the months of May, June, July, August, and September. The associated On-Peak hours shall be the twelve (12) hours from 10:00 am to 10:00 pm each day of the summer period; all other hours shall be Off-Peak hours. For the purposes of this exhibit, a winter season shall include the months of January, February, March, April, October, November, and December. The associated On-Peak hours shall be the five (5) hours from 5:00 am to 10:00 am and the eight (8) hours from 4:00 pm to midnight each day of the winter period; all other hours shall be Off-Peak hours. Maintenance months shall include the months of March, April, October, and November. Except as otherwise provided, the rates ($/kWh) applicable to this Contract shall be: Summer Summer Winter Winter On-Peak Off-Peak On-Peak Off-Peak Capacity 0.04781 0.00000 0.02282 0.00000 Energy 0.02273 0.01986 0.02273 0.01986 Total 0.07054 0.01986 0.04555 0.01986 The above cited rates shall be effective from January 1, 1991 through April 30, 1992. The above cited rates shall be adjusted annually, on May 1 of each year beginning with the annual adjustment date of May 1, 1992 and ending with the annual adjustment date May 1, 2023, by eighty (80) percent of the changes in the Consumer Price Index for all Urban Consumers; the base index shall be the index for January of 1991 (134.6). A-1 EXHIBIT B Interconnection Facilities Agreement WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration Limited Partnership (Seller) entered into a Contract for a Long Term Power Purchase from Seller's Facilities located at North Las Vegas, Nevada on the 27th day of May,1992, and WHEREAS, the Parties agreed to execute an Interconnection Facilities Agreement (Exhibit B) as a condition of that Contract. NOW, THEREFORE, Nevada and Seller agree to own, design, construct, operate, maintain, and improve the facilities required to implement the provisions of that Contract in accordance with the terms and conditions of that Contract and the additional terms and conditions set forth herein. 1. Purpose: 1.1 This Exhibit B generally describes the facilities that shall be required to implement the requirements and provisions of the Contract and to designate those facilities as either Seller's Facilities or Nevada's Facilities. Since interconnection studies require data for Seller's Facilities that may have been unavailable upon execution of this Exhibit B, Nevada shall have the right to complete those studies in phases linked to the availability of such data and to modify this Exhibit B accordingly. 1.2 Nothing in the Contract or this Exhibit B shall be construed, by virtue of the absence of a specific reference, as relieving either Party of the responsibility for all labor, equipment, and materials incidental to the construction of facilities designated herein as being the responsibility of that Party. Upon completion of construction, the facilities constructed per this Exhibit B should be fully capable of completing the interconnection between Nevada and Seller in accordance with the terms and conditions of the Contract and this Exhibit B. B-1 2. Attachment of Documents: 2.1 If necessary to accomplish the purposes of this Exhibit B, documents shall be attached and shall be a part of the Contract to the same extent as set forth herein. 2.2 Preliminary documents shall be replaced with final documents as they become available. 2.3 The following designated documents shall be attached to this Exhibit B. X Exhibit B1: "Procedures For Determining QF Interconnection Facility Cost Responsibilities." X Exhibit B2: A "List of Drawings" and the referenced drawings, X Exhibit B3: a "List of Major Components", __ Exhibit B4: a "List of Specifications" and the referenced specifications, __ Exhibit B5: a "List of Standards" and the referenced standards, and X Exhibit B6: a "List of Miscellaneous Attachments" and the referenced attachments. 3. Interconnection Point: The Interconnection Point shall be that point designated on Drawing No. 2.3. 4. Seller's Facilities: 4.1 Seller's Facilities shall be those facilities designated on the attached drawings and List of Major Components. 4.2 If set forth in the documents attached to this Exhibit B, Seller's Facilities shall conform to the specifications and standards attached hereto. 5. Nevada's Facilities: 5.1 Nevada's Facilities shall be those facilities designated on the attached drawings and List of Major Components. 5.2 If set forth in the documents attached to this Exhibit B, Nevada's Facilities shall conform to the specifications and standards attached hereto. B-2 5.3 The estimated cost of Nevada's Facilities which Seller shall be required to place construction deposits with Nevada is $1,100,000. 5.4 Following receipt of Seller's authorization to proceed and Seller's deposit of the estimated cost of Nevada's Facilities, Nevada shall use its best efforts to complete the construction of Nevada's Facilities no later than February 1, 1994. 5.5 The special provisions for Seller's construction deposits associated with Nevada's Facilities, as set forth in Miscellaneous Attachment No. 3, shall be applicable to the Contract. 6. Capacity and Energy: Meters and metering equipment shall be installed inside Nevada's relay and control building which shall be located within Nevada's Switchyard. 7. Protective Devices: The minimum set of protective devices required to protect Nevada's electric system whenever Seller's Facilities are connected to or operated in parallel with Nevada's electric system shall be the protective devices designated on a drawing to be agreed upon by the Parties and attached to this Exhibit B. B-3 8. Signatures: IN WITNESS WHEREOF, the Parties hereto have executed this Exhibit B this 27th day of May, 1992. NEVADA POWER COMPANY: LAS VEGAS COGENERATION LIMITED PARTNERSHIP: By: Steven W. Rigazio By: J. Thomas Fowlkes Name: Steven W. Rigazio Name: J. Thomas Fowlkes Title: Vice President Title: President Treas. & CFO United Cogen Corporation APPROVED AS TO FORM: Gloria Moore B-4 EXHIBIT B1 PROCEDURES FOR DETERMINING QF INTERCONNECTION FACILITY COST RESPONSIBILITIES 1. Nevada Power Company (NPC) shall determine the interconnection facilities which will be built between NPC's system and a Qualified Facility (QF) based on the following requirements: a. Such facilities shall be adequate to maintain a minimum transfer capability which will allow the QF to sell the desired amount of power to NPC; and b. Such facilities shall maximize the efficient development of NPC's system for existing or future benefits. 2. The QF shall be responsible for the proportionate share of costs of the interconnection facilities which is adequate to transfer the amount of capacity and energy to be sold by the QF to NPC with the following exceptions. a. If such facilities are determined by NPC to not be needed to serve NPC's customers within five years of the in-service date, then QF shall be responsible for all costs. However, if NPC subsequently determines, within 10 years of the in-service date, that such facilities are needed to serve load, NPC shall refund, without interest, the cost of such interconnection facilities less the QF's proportionate share. b. If such facilities involve the rebuilding of a portion of NPC's system, the QF shall also be responsible for the portion of the interconnection costs plus income taxes, if applicable, for capacity NPC had available prior to the rebuilding. 3. NPC shall be responsible for those costs of the interconnection facilities not covered in No. 2 above. 4. Definitions: Interconnection Facilities: Those facilities constructed between the QF interconnection point and a point on NPC's system adequate to receive power from the QF. Such facilities shall include, but not be limited to, new or rebuilt transmission lines, substation modification, metering, relaying, and communication equipment. Interconnection facilities shall not include any B-5 modification of facilities beyond the point of receipt within NPC's system. Transfer Capability: The normal rating of the transmission line based on NPC's standard rating of conductors, unless otherwise limited as determined by NPC. Example: 138 kV transmission line using 954 MCM ACSR conductor shall have a capability of (138kV) (837 amperes)(1.732) = 200 MW Proportionate Share: The ratio of the QF capacity amount to be sold to NPC relative to the transfer capability of the interconnection facilities. Example: an 85 MW QF sale to NPC on a 200 MW transmission line shall produce a proportionate share of (85/200)(100%) =42.5% B-6 EXHIBIT B2 List of Drawings Drawing Number Description 2.1 Transmission Requirement to Interconnect - dated 5/22/89 2.2 Interconnection with Pecos and Craig Substations - dated 5/22/89 2.3 Interconnection Detail - dated 5/22/89 B-7 LVCOGEN PRELIMINARY INTERCONNECTION FACILITIES DWG. 2.1 Area map bordered by Bruce Street, Gowan Road, Losee Road and Craig Road showing the relative location of the LVCOGEN 138 KV Substation and the Craig 138/12 KV Substation as well as existing 138 KV transmission line, new conductor on existing 138 KV double circuit structures, and new 138 KV double circuit structures. B-8 LVCOGEN PRELIMINARY INTERCONNECTION FACILITIES DWG. 2.2 Drawing showing existing 138 KV PCBs at the Pecos and Craig Substations and a new 138 KV PCB at LVCOGEN with the existing and new transmission lines connecting these PCBs. B-9 LVCOGEN PRELIMINARY INTERCONNECTION FACILITIES DWG. 2.3 Drawing showing interconnection detail at LVCOGEN. B-10 EXHIBIT B3 List of Major Components Constr. Deposit Description Quantity Owner Required Taxable 138 kV Termination 1 Nevada Yes No (Craig Sub) 138 kV Transmission Line 1.6 miles Nevada Yes No (LV Cogen - Craig) Provisions for future 138 kV as req'd Nevada No No Breaker Bay 138 kV Breaker Bay 1 Nevada Yes No (LV Cogen Sub) 138 kV Power Circuit Breaker 1 Nevada Yes No (LV Cogen Sub) 138 kV Disconnects 2 Nevada Yes No (LV Cogen Sub) 138/13.8 kV Transformer as req'd Seller No No (LV Cogen Sub) 13.8 kV Switchgear as req'd Seller No No (LV Cogen Sub) Protective Devices for Craig 138 kV PCB as req'd Nevada Yes No for LV Cogen 138 kV PCB as req'd Nevada Yes No for 138 kV Switchgear as req'd Seller No No Metering Equipment (138 kV) as req'd Nevada Yes No Remote Terminal Unit 1 Nevada Yes No Automatic Synchronizing Equipment as req'd Seller No No B-11 EXHIBIT B6 List of Miscellaneous Attachments Number Description 1 Temporary Easement 2 Protective Equipment 3 Special Provisions B-12 Miscellaneous Attachment No. 1 Temporary Easement 1. To facilitate the preparation of easements required by Nevada to implement the requirements of this Contract, Seller shall provide the following documents to Nevada: a. A map or maps showing the location of Seller's Facilities and the ownership of all parcels which Nevada must traverse to gain access to the site of Seller's Facilities; b. A copy of the deed or deeds of ownership for all parcels which Nevada must traverse to gain access to the site of Seller's Facilities; and c. A letter, executed by the owners of all parcels which Nevada must traverse to gain access to the site of Seller's Facilities, granting Nevada the right of ingress and egress to implement the requirements of this Contract until such time as permanent easements, rights-of-way, and land rights have been obtained. 2. The above cited documents shall be delivered to Nevada coincident with Seller's deposit for Nevada's Facilities. B-13 Miscellaneous Attachment No. 2 Protective Equipment Nevada has established minimum requirements essential for the safe and reliable operation of Qualifying Facilities operating in parallel with Nevada's system. Those requirements provide for control and protective equipment which is required to: 1. Protect Nevada's personnel and the general public; 2. Sense and properly react to disturbances on Nevada's system; 3. Assist Nevada's efforts to maintain its system integrity. The following list presents the various devices and features generally required by Nevada as a prerequisite to operation of a Qualifying Facility in parallel with Nevada's electric system. 1. A dedicated transformer; 2. An interconnection disconnect; 3. A generator circuit breaker; 4. Under/over-voltage protection; 5. Under/over-frequency protection; 6. Ground fault protection; 7. Overcurrent relays with voltage restraint; 8. Automatic synchronizing; 9. Voltage and power factor regulation; and 10. No automatic line restoration equipment. B-14 Miscellaneous Attachment No. 3 Special Provisions 1. Deposits for Nevada's Facilities for which Seller has been required to place construction deposits with Nevada: Seller shall have the option of establishing an escrow account to pay for Nevada's Facilities which Seller has been required to fund. Such escrow account shall be located at a Las Vegas area financial institution that has been approved by Nevada. Nevada's approval shall not be unreasonably delayed or withheld. Seller shall deposit the full estimated cost of Nevada's Facilities in the escrow account within thirty (30) days of Commission approval of the Contract. Nevada shall have the right to make withdrawals from the escrow account as required to pay materials and labor costs associated with construction of Nevada's Facilities. Seller shall not make withdrawals from the escrow account without Nevada's written approval. Seller's escrow account shall be established in a manner that precludes withdrawals without such approval. If the balance in Seller's escrow account is less than Nevada's actual cost for that portion of Nevada's Facilities for which Seller has been required to place a construction deposit with Nevada, Seller shall be billed for Nevada's excess cost in accordance with the provisions of Section 13 of the Contract. If the balance of Seller's escrow account exceeds Nevada's actual cost for that portion of Nevada's Facilities for which Seller has been required to place a construction deposit with Nevada, Nevada shall provide Seller with written authorization for Seller to withdraw such excess funds within sixty (60) days of completion of Nevada's Facilities. 2. The Parties agree to collectively put forth their best efforts to achieve Firm Operation of The Las Vegas Cogeneration Project at Contract Capacity of 45 megawatts not later than June 1, 1994. B-15 EXHIBIT C Operations Coordination Agreement WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration Limited Partnership (Seller) entered into a Contract for a Long Term Power Purchase from Seller's Facilities located at North Las Vegas, Nevada on the 27th day of May, 1992, and WHEREAS, the Parties agreed to execute an Operations Coordination Agreement (Exhibit C) as a condition of that Contract, NOW THEREFORE, Nevada and Seller agree to coordinate the operations of their respective facilities in accordance with the requirements and provisions of that Contract and the additional terms and conditions set forth herein. 1. Purpose: 1.1 This Exhibit C generally describes the procedures that shall be required to implement the requirements and provisions of the Contract. 1.2 Nothing in the Contract or this Exhibit C shall be construed, by virtue of the absence of a specific reference, as relieving either Party of the responsibility for communicating with the other Party in a manner that will allow both Parties to operate their facilities in a safe manner consistent with the best interests of the Parties and the general public. 2. Communications: 2.1 Seller shall maintain telephone service to Seller's Generating Facility. 2.2 The following points of contact have been designated for Operating Communications. C-1 2.2.1 Communications to Seller: Seller's Operator (____) ____ - _______ 2.22 Communications to Nevada: Nevada's System Dispatcher (702) 451-2026 Nevada's Program Coordinator (702) 731-3382 Each Party shall notify the other Party in writing prior to changing any of the above cited points of contact. 2.3 Unless otherwise specified herein, Nevada's System Dispatcher shall be the point of contact for Operating Communications with Nevada. 3. Jurisdiction: When any of Seller's Facilities are connected to Nevada's electric system, those facilities shall be under the jurisdiction of Nevada's System Dispatcher. Seller's Operator shall comply with all of the instructions provided by Nevada's System Dispatcher at the time designated in the instructions. In the course of operating or maintaining Seller's Facilities, Seller's Operator shall not undertake any action that may have an adverse impact on Nevada's electric system integrity without contacting Nevada's System Dispatcher and receiving prior authorization. Such activities shall include, but not be limited to, energization or deenergization of Seller's Interconnection Facilities, connection of Seller's generators to Nevada's electric system, isolation of Seller's generators from Nevada's electric system, and adjustment of the amount of real or reactive power being delivered to Nevada's electric system. Only authorized representatives of Nevada shall be allowed to connect Seller's Interconnection Facilities to Nevada's electric system or to isolate Seller's Interconnection Facilities from Nevada's electric system. This restriction shall not be applicable to the operation of power circuit breakers and other protective devices that have been designed to react to abnormal conditions. C-2 4. Operating Criteria: 4.1 Power pool or coordinating council operating criteria applicable to Seller's Facilities shall be attached to this exhibit as Exhibit C1. Exhibit C1 shall be made a part hereof to the same extent as set forth herein. 4.2 Nevada shall have the right to modify Exhibit C1 so that the criteria set forth therein are consistent with the criteria which Nevada must comply with as a result of Nevada's participation in a power pool or coordinating council. Nevada's modifications shall be written. 5. Seller's Generators: The following procedures shall be used to connect Seller's generators to Nevada's electric system (connection), to disconnect Seller's generators from Nevada's electric system (isolation), and to adjust the output of Seller's Generating Facility. 5.1 Connection Under Normal Conditions: 5.1.1 Seller's Operator shall notify Nevada's Program Coordinator at least seventy-two (72) hours prior to connection of any of Seller's generators. 5.1.2 Nevada's Program Coordinator shall advise Seller's Operator of any conditions that may preclude connection of Seller's generator at the time requested by Seller's Operator. If necessary, Seller's Operator shall adjust Seller's startup schedule to accommodate the changes requested by Nevada's Program Coordinator. 5.1.3 At lease two (2) hours prior to connection of any Seller's generators, Seller's Operator shall contact Nevada's System Dispatcher and provide the following information. A. The time when Seller's Operator expects Seller's turbine to start; B. The time when Seller's Operator expects to connect Seller's generator to Nevada's electric system; and C. The ramping rate that Seller's Operator expects to use while loading Seller's generator. C-3 5.1.4 Unless otherwise instructed by Nevada's System Dispatcher, Seller's Operator shall maintain communications with Nevada's System Dispatcher prior to and during synchronization of Seller's generator with Nevada's electric system. 5.1.5 The scheduling requirements of this section may be waived by Nevada's System Dispatcher if connection is requested after a Forced Outage or if Nevada's System Dispatcher deems it otherwise prudent to do so. 5.2 Isolation Under Normal Conditions: 5.2.1 Seller's Operator shall notify Nevada's Program Coordinator at least seventy-two (72) hours prior to isolation of Seller's generator. 5.2.2 Nevada's Program Coordinator shall advise Seller's Operator of any conditions that may preclude isolation of Seller's generators at the time requested by Seller's Operator. If necessary, Seller's Operator shall adjust Seller's shutdown schedule to accommodate the changes requested by Nevada's Program Coordinator. 5.2.3 At least two (2) hours prior to isolation of any of Seller's generators, Seller's Operator shall contact Nevada's System Dispatcher and provide the following information: A. The ramping rate that Seller's Operator expects to use to unload Seller's generator; B. The time when Seller's Operator expects to isolate Seller's generator from Nevada's electric system; and C. The time when Seller's Operator expects to shut down Seller's turbine. 5.2.4 Unless otherwise instructed by Nevada's System Dispatcher, Seller's Operator shall maintain communications with Nevada's System Dispatcher prior to and during isolation of Seller's generator from Nevada's electric system. C-4 5.2.5 The scheduling requirements of this section may be waived by Nevada's System Dispatcher if isolation is required by a Forced Outage or if Nevada's System Dispatcher deems it otherwise prudent to do so. 5.3 Output Adjustment Initiated By Seller: 5.3.1 If abnormal conditions require an adjustment in the output of Seller's Generating Facility that is being delivered to Nevada, Seller's Operator shall contact Nevada's System Dispatcher and provide the following information to Nevada's System Dispatcher. A. The reason why Capacity and Energy being delivered to Nevada must be adjusted; B. The amount and the expected duration of the adjustment; C. The time when Seller's Operator expects to begin adjusting the output of Seller's generator; D. The ramping rate that Seller's Operator expects to use while adjusting the output of Seller's generator; and E. The level of deliveries of Capacity and Energy to Nevada that Seller expects to maintain after the output of Seller's generator has been adjusted to the prescribed level. 5.3.2 After the abnormal condition has been alleviated, Seller's Operator shall comply with the applicable provisions of Section 5.1 or Section 5.2 of this exhibit while restoring the output of Seller's generator to the normal level. 6. Curtailments: Consistent with the provisions of the Contract, Nevada's System Dispatcher shall have the right to either order reductions in the output of Seller's Generating Facility or the isolation of any of Seller's Facilities from Nevada's electric system. To the extent possible, Nevada shall attempt to notify Seller's Operator in advance of such reductions and isolations. Regardless of the notice provided, the following procedure shall be applicable. C-5 6.1 Nevada's System Dispatcher shall contact Seller's Operator and instruct Seller's Operator to reduce the output of Seller's Generating Facility to the prescribed level over the specified period of time. 6.2 Seller's Operator shall reduce the output of Seller's Generating Facility to the prescribed level in accordance with the instructions from Nevada's System Dispatcher. If Nevada's System Dispatcher is unable to contact Seller's Operator or if Seller's Operator fails to comply with the instructions from Nevada's System Dispatcher, Nevada's System Dispatcher shall isolate Seller's Facilities from Nevada's electric system. 6.3 Unless Nevada's System Dispatcher has established an alternative procedure, Seller's Operator shall notify Nevada's System Dispatcher after the output of Seller's Generating Facility has been reduced to the prescribed level. Once reduced, Seller's Operator shall not increase the output of Seller's Generating Facility until instructed to do so by Nevada's System Dispatcher. 6.4 After the condition dictating the reduction has passed or Nevada's electric system has been adjusted to accommodate increased deliveries from Seller's Facilities, Nevada's System Dispatcher shall instruct Seller's Operator to return Seller's Generating Facility to its normal operating status. 7. Reactive Power: 7.1 Seller shall provide the reactive power required to maintain voltage at Seller's 138 kV bus in the range from 138,000 volts to 144,900 volts: or, Seller shall provide the reactive power required to maintain power factor at the 138 kV bus in the range from ninety (90) percent lagging to one hundred (100) percent, whichever has been designated by Nevada's System Dispatcher. 7.2 If Seller's Operator is unable to maintain the specified voltage or power factor, whichever is applicable, within the prescribed range, Seller's Operator shall immediately contact Nevada's System Dispatcher and describe the nature of the problem that precludes maintaining the specified voltage or power factor. C-6 7.3 Nevada's System Dispatcher shall then describe any remedial actions to be taken by Seller's Operator. 7.4 Seller's Operator shall implement the instructions provided by Nevada's System Dispatcher for alleviation of the abnormal conditions. 8. Operation and Maintenance Logs: Seller's operation and maintenance logs shall contain the following minimum information: 8.1 The gross real and reactive power output of Seller's Generating Facility and Seller's real and reactive power consumption, both on an hourly basis, or the real and reactive power delivered to Nevada by Seller, on an hourly basis. 8.2 The date and time at which any of Seller's generators are connected to or isolated from Nevada's electric system. 8.3 The date and time of any unscheduled operations of Seller's power circuit breakers and a list of relay targets from the protective devices that may have caused those circuit breakers to operate. 8.4 The beginning and ending dates and times for all periods during which Seller's Generating Facility is operated at less than full output and a description of the reasons for the reduced output. 8.5 A description of any other unusual events. 8.6 The date and time of all telephone calls placed to Nevada's System Dispatcher or Nevada's Program Coordinator and a summary of the information that was exchanged during the telephone conversation. 8.7 Any other information that may be reasonably required by Nevada's System Dispatcher. 9. Abnormal Conditions: Seller shall immediately notify Nevada's System Dispatcher of any abnormal conditions. Abnormal conditions shall always include the following: 9.1 Conditions that may result or may have resulted in injury to Nevada's or Seller's personnel or the general public. 9.2 Conditions that may result or may have resulted in damage to Nevada's or Seller's property or the property of the general public. C-7 9.3 Conditions that may adversely affect or may have adversely affected Nevada's ability to provide electric service to Nevada's customers. 9.4 Conditions that may adversely affect or may have adversely affected Seller's ability to produce and deliver Capacity and Energy to Nevada. 9.5 Conditions that may cause or may have caused an unscheduled reduction in the rate of delivery of electric energy to Nevada. 9.6 Conditions that may cause or may have caused an unscheduled isolation of any of Seller's Facilities from Nevada's electric system. 10. Scheduled Outages: Seller shall make every reasonable effort to schedule all outages in accordance with Nevada's electric system requirements. 10.1 On or before January 1, and July 1 of each year, Seller shall provide a written schedule of outages to Nevada for Seller's Facilities. Seller's schedule shall cover the following twenty-four (24) month period beginning with the date on which the schedule is provided to Nevada. Seller's schedule shall be mailed to Nevada's Program Coordinator at Mail Station 58, Nevada Power Company, P. O. Box 230, Las Vegas, NV 89151. 10.2 Nevada's Program Coordinator shall advise Seller's Operator of any changes to Seller's outage schedule that may be required to maintain Nevada's electric system integrity. 10.3 If necessary, Seller's Operator shall reschedule Seller's outages in accordance with the changes that are described by Nevada's Program Coordinator. 10.4 Unless conditions dictate otherwise, Seller's Operator shall accomplish outages in accordance with Seller's schedule as modified by Nevada's Program Coordinator. 10.5 If Seller's outage schedule must be adjusted for reasons beyond Seller's reasonable control, Seller's Operator shall contact Nevada's Program Coordinator who shall adjust Seller's outage schedule as necessary. 10.6 If unforeseen circumstances require Seller's Operator to schedule outages that were not addressed on Seller's outage schedule, Seller's C-8 Operator shall contact Nevada's Program Coordinator and advise Nevada's Program Coordinator of Seller's requirements. Nevada's Program Coordinator shall make every reasonable effort to adjust Seller's outage schedule as requested by Seller's Operator. 11. Relay Calibration: Seller shall make every reasonable effort to schedule testing and calibration of Seller's protective devices in accordance with Nevada's requirements. 11.1 Seller's Operator shall notify Nevada's Program Coordinator at least thirty (30) days prior to any scheduled testing or calibration of Seller's protective devices. Seller's notice shall include Seller's proposed schedule for testing or calibration of individual protective devices. 11.2 Nevada's Program Coordinator shall advise Seller's Operator of any potential conflicts that may preclude testing or calibration of Seller's protective devices. Seller's Operator shall adjust Seller's schedule as requested by Nevada's Program Coordinator. 11.3 Prior to removing any of Seller's protective devices from operation, Seller's Operator shall advise Nevada's System Dispatcher of Seller's intent. Nevada's System Dispatcher shall withhold authorization for removal of Seller's protective devices from service if such removal will adversely affect Nevada's Electric System Integrity. Seller shall not remove any protective devices from operation without authorization from Nevada's System Dispatcher. 11.4 After any of Seller's protective devices have been returned to normal operation, Seller's Operator shall advise Nevada's System Dispatcher accordingly. 11.5 After any of Seller's protective devices have been tested or calibrated, Seller shall provide a copy of the Seller's test reports to Nevada. Such reports shall be mailed to Nevada's Program Coordinator or provided to Nevada's representative if Nevada monitors Seller's testing or calibration. 12. Maintenance Authorization: 12.1 Seller shall not perform any maintenance on Seller's energized Facilities without prior C-9 authorization from Nevada. Normally, such authorization shall only be provided for the maintenance of control equipment and protective devices if the equipment and devices cannot be deenergized during the maintenance. 12.2 Seller shall not perform any maintenance on Seller's energized Facilities without a clearance from Nevada's System Dispatcher. Seller's Operator shall use the following procedure to obtain a clearance. 12.2.1 To arrange for the clearance, Seller's Operator shall contact Nevada's Program Coordinator at lease seventy-two (72) hours prior to a requested outage, unless an emergency exists. Nevada's Program Coordinator shall make every reasonable effort to schedule the outage in accordance with Seller's request. 12.2.2 Nevada's Program Coordinator shall advise Seller of any conditions that may preclude isolation of Seller's Facilities. The schedule for Seller's outage shall be adjusted accordingly. 12.2.3 Switching to isolate Seller's Facilities from Nevada's electric system shall be completed by Nevada's authorized representative who shall be acting in accordance with an approved switching program and under the direction of Nevada's System Dispatcher. After the switching to isolate Seller's Facilities has been completed, Nevada's System Dispatcher shall issue a clearance to Seller's Operator releasing the isolated facilities to Seller's Operator for the prescribed maintenance. Under no circumstances shall Seller physically contact any of Seller's Facilities that are normally energized until those facilities have been released to Seller's Operator. 12.2.4 Isolation of Seller's Interconnection Facilities from Nevada's electric system shall be accomplished at a lockable disconnect. Seller shall not attempt to operate the disconnect, attempt to remove the lock from the disconnect, or attempt to remove any safety tags that accompany the lock. C-10 12.2.5 Seller shall complete maintenance in accordance with prudent maintenance practices. Seller shall take all necessary steps to ensure that maintenance will be conducted in a manner that does not endanger the safety of persons or equipment. Nevada assumes no responsibility for the safety and well being of Seller's personnel or contractors. Nevada assumes no responsibility for Seller's equipment. 12.2.6 After Seller has completed the prescribed maintenance on Seller's Interconnection Facilities, removed all protective grounds, and returned those facilities to the normal operating condition, Seller's Operator shall contact Nevada's System Dispatcher and release the previously issued clearance. 12.2.7 After Seller's Operator has released the previously issued clearance and Seller's Facilities have been inspected to the extent deemed necessary by Nevada's System Dispatcher to protect Nevada's Electric System Integrity, Nevada's authorized representative, acting in accordance with an approved switching program and under the direction of Nevada's System Dispatcher, shall energize Seller's Interconnection Facilities. Nevada's inspection shall be solely for Nevada. Nevada assumes no responsibility for the safety and well being of Seller's personnel, the personnel of Seller's contractors, or the general public. Nevada assumes no responsibility for Seller's equipment or the property of the general public. C-11 13. Signatures: IN WITNESS WHEREOF, the Parties hereto have executed this Exhbit C this 27th day of May, 1992. NEVADA POWER COMPANY: LAS VEGAS COGENERATION LIMITED PARTNERSHIP: By: Steven W. Rigazio By: J. Thomas Fowlkes Name: Steven W. Rigazio Name: J. Thomas Fowlkes Title: Vice President Title: President Treas. & CFO United Cogen Corporation APPROVED AS TO FORM: Gloria Moore C-12 EXHIBIT D Project Improvement Agreement [Intentionally left blank, pending the need for such agreement pursuant to Section 11 of the Contract.] D-1 EXHIBIT E Procedure For Establishing Firm Operation 1. Tests for establishing Firm Operation shall be conducted over a period of not more than one hundred (100) continuous hours. A separate test shall be performed for each generator or group of generators. 2. Seller shall notify Nevada's Operating Representative at least fifteen (15) days prior to the start of each of Seller's proposed test periods. 3. Nevada shall have the right to monitor Seller's tests. 4. Firm Operation testing shall not be permitted during the months of July, August, and September. 5. If Seller's test is conducted during the months of October through April, inclusive, Seller's actual performance (KW) shall equal Seller's actual energy (KWH) produced and delivered to Nevada during the test period divided by one hundred and ten (110) hours. 6. If Seller's test is conducted during the months of May through June, inclusive, Seller's actual performance (KW) shall equal Seller's actual energy (KWH) produced and delivered to Nevada during the test period divided by one hundred (100) hours. 7. Seller shall notify Nevada's Operating Representative in writing of the results of Seller's tests. Seller's notices shall contain sufficient information to allow Nevada to confirm Seller's actual performance. Seller shall be considered to have attained Firm Operation at Seller's actual performance or Contract Capacity, whichever is lower, upon Nevada's receipt of Seller's notices that Seller complied with the provisions of this exhibit and that Seller does not elect retesting. 8. If Seller elects retesting, the procedure set forth herein shall be applicable in its entirety. E-1 EXHIBIT F Form of Insured Endorsement Seller shall provide an insured endorsement in substantially the following form: "In consideration of the premium charged, Nevada Power Company (Nevada) is named as additional insured with respect to all liabilities arising out of Seller's ownership and use of Seller's Facilities. The inclusion of more than one insured under this policy shall not operate to impair the rights of one insured against another insured and the coverages offered by this policy shall apply as though separate policies had been issued to each insured. The inclusion of more than one insured under this policy shall not, however, operate to increase the limit of the carrier's liability. Nevada shall not, by reason of its inclusion under this policy, incur any liability to the insurance carrier for payment of any premium for this policy. Any other insurance carried by Nevada that may be applicable shall be excess insurance and Seller's insurance shall be primary for all purposes despite any conflicting provisions in Seller's policy." F-1 EXHIBIT G Standby Service Agreement WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration Limited Partnership (Seller) entered into a Contract for a Long Term Power Purchase from Seller's Facilities located in North Las Vegas, Nevada on the 27th day of May, 1992, and WHEREAS, Seller wants Standby Service from Nevada, NOW THEREFORE, Nevada, in exchange for the compensation referenced herein, hereby agrees to provide Standby Service to Seller pursuant to the terms and conditions of that Contract and the additional terms and conditions set forth herein. 1. General: 1.1 Standby Capacity: 1000 KW. 1.2 Expected Annual Standby Energy Requirement: 500,000 KWH. 1.3 Standby Term: Coincident with the Contract Term. 2. Definitions: When used in this Contract and initially capitalized the following terms shall have the indicated meaning: 2.1 Standby Capacity: Seller's capacity requirement that Nevada is obligated to serve whenever Seller's Generating Facility experiences a Forced or Scheduled Outage. 2.2 Standby Term: The period during which Nevada shall provide Standby Service. 3. Termination: Unless otherwise provided within this Exhibit G, this Exhibit G shall become effective upon execution by the Parties and shall be terminated upon expiration of the Standby Term set forth in Section 1.3. 4. Standby Metering: Meters and metering equipment required to measure Standby Service shall be installed in accordance with Nevada's Tariff. Meters so installed shall be equipped with detents to preclude reversal. If Nevada's meters fail to register, Nevada shall render bills to Seller based upon Nevada's estimate of Seller's Standby Service requirements. Estimated bills shall have the same force and effect as actual bills. G-1 5. Capacity Provisions: Standby Capacity shall not exceed five (5) percent of Contract Capacity. 5.1 Standby Capacity Reduction: After Seller has attained Firm Operation, Seller shall have the right to reduce Standby Capacity by providing six (6) months prior written notice of Seller's intent. The provisions of this Exhibit G shall be applicable to the reduced Standby Capacity. 5.2 Standby Capacity Increase: After Seller has attained Firm Operation, Seller shall have the right to increase Standby Capacity by providing six (6) months prior written notice of Seller's intent. The provisions of this Exhibit G shall be applicable to the increased Standby Capacity. 6. Attachment of Documents: 6.1 If necessary to accomplish the requirements of this Exhibit G, documents shall be attached hereto and made a part hereof to the same extent as set forth herein. 6.2 Preliminary documents shall be replaced with final documents as final documents become available. 6.3 Standby meters and metering equipment shall be installed in the location designated on Drawing No. 2.3, Exhibit B2. 7. Billing Provisions: Seller shall pay for Standby Service at Nevada's Tariff Schedule SS rates effective when such Standby Service is provided. Nevada shall render monthly bills to Seller for Standby Service. G-2 8. Signatures: IN WITNESS WHEREOF, the Parties hereto have executed this Exhibit G this 27 th day of May, 1992. NEVADA POWER COMPANY: LAS VEGAS COGENERATION LIMITED PARTNERSHIP: By: Steven W. Rigazio By: J. Thomas Fowlkes Name: Steven W. Rigazio Name: J. Thomas Fowlkes Title: Vice President Title: President Treas. & CFO United Cogen Corporation APPROVED AS TO FORM: Gloria Moore G-3 APPENDIX A LIST OF GRAPHIC AND IMAGE MATERIAL 1. Drawing of transmission requirement to interconnect. See page B-8 of Exhibit B1 to the contact for a description of the drawing. 2. Drawing of interconnection with Pecos and Craig Substations. See page B-9 of Exhibit B1 to the contact for a description of the drawing. 3. Drawing of interconnection detail. See page B-10 of Exhibit B1 to the contact for a description of the drawing. EX-10.71 5 CONTRACT WITH MOUNTAIN COAL AND ATLANTIC RICHFIELD SETTLEMENT AGREEMENT -------------------- THIS SETTLEMENT AGREEMENT is made as of the 9th day of March, 1994, between Mountain Coal Company and Atlantic Richfield Company ("Plaintiffs") and Nevada Power Company ("Defendant"). RECITALS -------- 1. The parties are engaged in litigation before the United States District Court for the District of Utah (Civil No. 92-C-522-S) concerning three coal supply agreements (the "1980 Agreement, "the "1982 Agreement," and the "1985 Agreement") and one agreement for loading services ("Loading Agreement") (the "Utah Action"); 2. The parties have agreed to compromise and settle their pending disputes upon the terms set out below. NOW, THEREFORE, Plaintiffs and Defendant agree in compromise and settlement of their claims as follows: 1. Defendant shall pay Plaintiff ARCO $25,000,000 for coal not sold under the 1985 Agreement from December 31, 1992, through the expiration of the term of the 1985 Agreement, and for loading services not performed under the Loading Agreement, according to the terms of a promissory note annexed hereto as Exhibit A, which note shall be executed by Defendant concurrently with execution by Defendant of this Settlement Agreement. 2. Defendant shall pay Plaintiff ARCO $310,552 in satisfaction of certain price adjustments for past deliveries under the 1985 Agreement, made over the period 1987-1991, which sum is included in the annexed Promissory Note. 3. The parties shall cause their legal counsel to do the following(except as may be required to preserve the pricing approach approved by the court in Civil No. 92-C-522-S as contained in paragraph 9 of its July 30, 1993, Order) within ten (10) days of the date of this Agreement: a. Defendant shall dismiss with prejudice its appeal pending before the United States Court of Appeals for the Tenth Circuit, Case No. 93-4165; b. Defendant shall dismiss with prejudice all claims pending against Plaintiffs in the Utah Action; c. Plaintiffs shall dismiss with prejudice all claims pending by Plaintiffs against Defendant in the Utah Action; d. All parties shall dismiss the Utah action. 4. The parties specifically exclude from this Settlement Agreement the retroactive adjustment amounts on the 1980 and 1982 Agreements as detailed in ARCO's letter of January 6, 1994, which 1 amounts are subject to ongoing audit and possible adjustment. The parties further understand that performance under these Agreements is ongoing and that NPC has not completed its audits for deliveries under these agreements for the years 1991 to date. These audits will be completed in the ordinary course, using West Elk actual costs as approved by the Court in Civil No. 92-C-522-S in paragraph 9 of its July 30, 1993, Order. 5. The parties acknowledge and agree that the 1985 Agreement and Loading Agreement are at an end as of midnight, December 31, 1992. The parties confirm and agree that the 1980 and 1982 Agreements are in full force and effect and that, apart from price adjustments, including without limitation any applicable retroactive adjustments as may be required thereunder: (1) no party has any claim against the other under either the 1980 or 1982 Agreements, (2) no party is in default thereunder as of the date hereof, and (3) except for possible retroactive adjustments as described in paragraph 4 above, each party hereby releases any and all claims, known or unknown, which each may have against the other party based upon any action or inaction occurring prior to the date of this Agreement arising out of or in consequence of any of the three Coal Supply agreements or the Loading Services Agreement. 6. Each party shall bear its own costs and attorneys' fees for or in connection with this litigation. 7. This Settlement Agreement contains the entire agreement between the parties respecting settlement of the disputes between them and there exists no other covenant, representation or agreement respecting the subject matter hereof between the parties. NEVADA POWER COMPANY MOUNTAIN COAL COMPANY By: David G. Barneby By: Anthony G. Fernandes An Authorized Representative An Authorized Representative Title: Vice President - Power Delivery Title: Chairman Dated: March 11, 1994 Dated: March 9, 1994 ATLANTIC RICHFIELD COMPANY By: Anthony G. Fernandes An Authorized Representative Title: Senior Vice President Dated: March 9, 1994 2 EXHIBIT A PROMISSORY NOTE Pursuant to a Settlement Agreement of even date herewith, Nevada Power Company, a Nevada corporation ("Nevada Power"), for value received, hereby promised to pay to the order of ATLANTIC RICHFIELD COMPANY, a Delaware corporation ("ARCO"), or ARCO's assigns, the sum of Twenty-five Million three Hundred Ten Thousand, Five Hundred Fifty-two Dollars ($25,310,552.00) in immediately available funds on or before June 11, 1994, at 555 Seventeenth Street, Suite 2100, Denver, Colorado 80202. Payment shall be made without interest if made on or before the close of business on the thirtieth day after execution of the Settlement Agreement by Plaintiffs. If payment is made after the thirtieth day, interest shall be paid at a rate of ten percent (10%) annually ($6,934.40 per day), calculated from April 13, 1994. If unpaid, in whole or in part, on June 11, 1994, Nevada Power agrees to confess judgment in any court of competent jurisdiction which ARCO may choose, in favor of ARCO and against Nevada Power with interest accruing on said sum as from April 13, 1994, at the rate of Ten Percent (10%) per annum. Nevada Power hereby consents to jurisdiction and venue in any such court. Nevada Power hereby waives presentment for payment, demand, notice of dishonor and protest of this promissory note. This instrument shall be governed in all respects by the law of the State of Utah. Any expense incurred by ARCO in the collection of this note by suit or otherwise, including, but not limited to, attorneys' fees and court costs, shall be borne by Nevada Power. NEVADA POWER COMPANY By: David G. Barneby An Authorized Representative Dated: March 9, 1994 -----END PRIVACY-ENHANCED MESSAGE-----