ITEM 1. BUSINESS
SIERRA PACIFIC RESOURCES
Sierra Pacific Resources, hereafter known as SPR, was incorporated under Nevada law on December 12, 1983. SPR's mailing address is P.O. Box 30150 (6100 Neil Road), Reno, Nevada 89520-3150 (89511).
SPR has seven primary, wholly owned subsidiaries: Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Sierra Energy Company, dba e-three (e-three), Sierra Pacific Energy Company (SPE), and Lands of Sierra (LOS). NPC and SPPC are referred to together in this report as the "Utilities."
Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on the Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company websites, www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com and through links on these websites to the SEC's website at www.sec.gov as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website addresses are not part of this Form 10-K.
The discussion in this report has been divided wherever possible to highlight the activities of the major subsidiaries of SPR. Parenthetical references are included after each major section title to identify the specific entity addressed in the section. References to SPR refer to the consolidated entity, except for the section related to debt financing in which SPR debt is discussed separately from that of its subsidiaries.
INDUSTRY AND REGIONAL PROBLEMS AFFECTING THE UTILITIES (NPC AND SPPC)
ELECTRIC INDUSTRY TRENDS
In the wake of volatile and unprecedented energy prices in the Western United States in 2000 and a portion of 2001, the credit quality of a number of utilities and power merchants deteriorated in 2002.
Like other utilities in the West, NPC and SPPC were adversely affected by increased wholesale prices and by regulatory decisions that denied the utilities the ability to recover in full their higher fuel and purchased power costs. Major disallowances of power costs by the Public Utilities Commission of Nevada (PUCN) in March and May of 2002 led to severe liquidity problems, depressed earnings, and debt ratings downgrades for SPR and the Utilities. Although energy price volatility has subsided, many policy, regulatory, business, and financial issues remain, a number of which are being addressed or litigated at state and federal levels. See Liquidity and Capital Resources, and Regulation and Rate Proceedings, in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for additional information regarding these issues.
Adding to liquidity concerns in the industry, a number of power merchants had increased borrowings to purchase or build assets based on the prospect of higher overall wholesale prices. Wholesale prices remained
relatively steady in the latter part of 2002, causing demand projections to be revised downward, with the result that planned investment in generation suddenly declined and a number of highly leveraged companies were at risk of defaulting on their obligations.
The year 2002 was also marked by a general economic downturn that left few industries untouched. Several companies admitted to fraudulent energy trading activities. Companies inside and outside the electric utility industry admitted to fraudulent accounting practices. As a result, federal investigations of corporations and energy markets were conducted and are ongoing. Investor, consumer, and employee protection issues led to increased oversight of the accounting profession, audit quality and independence, and to new accounting principles and legislation. Passed in July, the Sarbanes-Oxley Act of 2002 enhances criminal penalties for certain corporate wrongdoings.
Rating agencies have also increased their scrutiny of the industry. According to a recent release by Standard & Poors', credit rating activity in 2002 for the investor-owned power industry involved 182 downgrades compared with only 15 upgrades during the year. The credit ratings of a number of companies, including SPR, NPC, and SPPC, were downgraded more than once.
Transmission capacity continued to be constrained in many regions of the country, according to the North American Electric Reliability Council. In the second quarter of 2002, transmission congestion was almost three times the level experienced during the same period in 1999. Investment in transmission has been declining over the last decade.
REGULATION AND ELECTRIC RESTRUCTURING
The transition to retail competition continues to be highly uncertain, driven by a changing wholesale market, the different approaches to retail competition taken by state regulators and legislators, and the varying results from those approaches.
Electric industry restructuring has been achieved in some states, including Texas and a number of states in the Northeast. In the majority of states, however, restructuring activities are either not active or they have been suspended or eliminated. While retail competition has been halted for most customers in Nevada, Assembly Bill 661 (AB 661), passed in 2001, allows commercial and governmental customers with an average demand greater than one megawatt (MW) annually to choose a new energy supplier beginning mid-2002 with permission from the PUCN upon meeting public interest tests. To date, none have left the system. However, 12 large customers have such applications pending with the PUCN.
The Federal Energy Regulatory Commission (FERC) has remained committed to regional transmission organization development and wholesale power competition, and issued an initial standard market design (SMD) during 2002. The SMD rule proposed to establish a single, standardized transmission service and a single, standardized wholesale market design. In response to concerns expressed by utility regulators in a number of states, the FERC announced it would issue a white paper on its proposed SMD rule in April 2003.
NEVADA POWER COMPANY
NPC is a Nevada corporation organized in 1921. NPC became a wholly owned subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.
NPC is a public utility engaged in the distribution, transmission, generation, purchase, and sale of electric energy in Clark County in southern Nevada. NPC provides electricity to approximately 669,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining
areas, including Nellis Air Force Base. Service is also provided to the Department of Energy's Nevada Test Site in Nye County.
During 2002, Nevada Electric Investment Company (NEICO) became a wholly owned subsidiary of NPC. In October of 1997, NEICO and UTT Nevada, Inc., an affiliate of Exelon Thermal Technologies, formed Northwind Las Vegas, LLC, a Nevada limited liability company, for the purpose of evaluating district energy projects in southern Nevada. Also, in October of 1997, NEICO and UTT Nevada, Inc. formed Northwind Aladdin, LLC, a Nevada limited liability company, for the purpose of owning, constructing, operating and maintaining a facility for the production and distribution of chilled water, hot water and emergency power for Las Vegas' Aladdin Hotel and Casino, which filed for Chapter 11 bankruptcy protection in September 2001. The project was completed in the first quarter of 2000 and is operational.
In September 1998, NEICO and e-three formed e-three Custom Energy Solutions, LLC, a Nevada limited liability company, for the purpose of selling and implementing energy-related performance contracts and similar energy services in southern Nevada. Refer to Other Subsidiaries of Sierra Pacific Resources, e-three for a more complete discussion of these activities.
BUSINESS AND COMPETITIVE ENVIRONMENT
NPC's electric business contributed 100% of its 2002 operating revenues of $1.9 billion. The system has an annual load factor of approximately 49%, which is slightly lower than the industry norm of 50% to 55%.
Summer retail peak loads are driven by air conditioning demand. NPC's peak load increased an average of 5.7% annually over the past three years, reaching 4,617 MW on July 12, 2002. NPC's total electric megawatt-hour (MWh) sales have increased an average of 3.9% annually over the past three years. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven by air handling in forced air furnaces.
NPC's service territory continues to be one of the fastest growing areas in the nation, with residential customer growth averaging 5.3% per year over the past 5 years. A significant part of the growth in NPC's electric sales has resulted from new residential, industrial, and gaming customers.
NPC's electric customers by class contributed the following toward 2002 and 2001 MWh sales:
Tourism and gaming remain southern Nevada's premier industries. Over 35 million tourists visited Las Vegas in 2002, infusing approximately $19.6 billion into the local economy during the year. Currently, Las Vegas is the home of 17 of the world's 20 largest hotels. Las Vegas' newest casino, the 201 room Cannery, opened on January 2, 2003 and carries a 1940s industrial theme throughout the property. The Ritz-Carlton opened the upscale 349-room, Mediterranean-themed MonteLago Village at Lake Las Vegas on February 11, 2003. The Venetian Hotel plans to open its 1,013-suite second tower in June 2003. Mandalay Resort Group has started construction on a 1,125-suite hotel tower slated to open in November 2003. Steve Wynn's Le Reve Resort is under construction and is scheduled for completion March 2005.
The Mandalay Resort Group opened a new 1.5 million square foot Mandalay Bay Convention Center on January 6, 2003, becoming the nation's fifth largest convention center. The Las Vegas Convention Center now has more than 3.2 million square feet of total space and features approximately 2 million square feet of net exhibit space and 380,000 square feet of net meeting room space, accommodating 170 meeting rooms with seating capacities from 20 to 7,500. In 2002 more than 5.1 million convention and trade show delegates traveled to Las Vegas, generating more than $5.9 billion in non-gaming revenue.
Despite the expansion of tourism and gaming properties in southern Nevada, a number of gaming properties filed for bankruptcy during 2002 and the industry is subject to a number of risks described later in Item 7, Management's Discussion and Analysis.
During 2002, firm and non-firm sales to wholesale customers comprised 20.6% of total energy sales, a decrease of 58.7% from the prior year. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with NPC.
NPC's decrease in wholesale MWh sales from last year was a result of market conditions and a change in NPC's power procurement activities. See Energy Supply in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of the Utilities' purchased power procurement strategies.
CONSTRUCTION PROGRAM
NPC'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, the number and status of proposed independent generation projects, the need for additional transmission capacity in southern Nevada, adequacy of rate relief, NPC's ability to raise necessary capital, and changes in environmental regulations. Under NPC's franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. NPC's service territory is one of the fastest growing areas in the nation. Capital construction expenditures and estimates are reflective of this obligation to serve.
Gross construction expenditures for 2002, including allowance for funds used during construction (AFUDC) and contributions in aid of construction, were $294.5 million, and for the period 1998 through 2002, were $1.24 billion. Estimated construction expenditures for 2003 and the period from 2004 to 2007 are as follows (dollars in thousands):
Total construction expenditures estimated for 2003 and the 2004-2007 period consist of the following (dollars in thousands):
The Centennial Plan involves construction of the following 500 kV lines: (1) the Harry Allen substation to Crystal substation 500 kV lines, (2) the Harry Allen substation to Northwest substation 500 kV line, and (3) the Harry Allen substation to Mead substation 500 kV line. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformer at Mead and Northwest substation, phase shifting transformer at Crystal substation, and several other sub-transmission upgrades and additions. Total estimated cost of the Centennial project is $307.7 million. Total project costs incurred through December 31, 2002, were $112.9 million. Estimated costs for 2003 are $58.0 million, which are expected to be financed utilizing internally generated cash.
The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. An amendment to NPC's Refiled Resource Plan was approved by the PUCN in August 2002, which amended the in-service date for the
Harry Allen to Mead 500 kV project from June 2003 to April 2005. Meetings have been held with the PUCN to review the revision to the scheduled in-service date from April 2005 to April 2006 for the Harry Allen to Mead project. See Transmission, later, for additional information about the Centennial Plan.
FACILITIES AND OPERATIONS
TOTAL SYSTEM
NPC maintains a wide variety of resources in its generation system. During 2002, NPC generated 44.0% of its total electric energy requirements, purchasing the remaining 56.0% as shown below:
NPC's decision to purchase short-term and spot energy is based on the economics of purchasing "as-available" energy when it is less expensive than its own generation.
NPC's 2002 company generation of 10,147,053 MWh is up 2.5% from NPC's 2001 company generation of 9,899,195 MWh. NPC's 2002 purchased power of 12,907,835 MWh is down 33.0% from NPC's 2001 purchased power of 19,268,305 MWh due to changes in NPC's purchased power procurement strategies. See Energy Supply in Management's Discussion and Analysis for additional information regarding NPC's purchasing strategies.
RISK MANAGEMENT
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
LOAD AND RESOURCES FORECAST
NPC's electric customer growth rate was 4.8% in 2002, 4.5% in 2001, and 5.1% in 2000. Annual retail electricity sales were 17.6 million MWh in 2002, which represents an increase of 2.3% over 2001 retail electricity sales of 17.2 million MWh. Annual wholesale electricity sales reached 4.6 million MWh in 2002, which represents a decrease of 58.6% from 2001 wholesale electricity sales of 11.1 million MWh. Overall, annual system electricity sales reached 22.2 million MWh in 2002, which represents a decrease of 21.5% from 2001 system electricity sales of 28.3 million MWh. The bulk of the 21.5% decrease is attributed to wholesale sales. The peak electric demand rose from 4,412 MW in 2001 to 4,617 MW in 2002.
The projections shown below are forecasts of the load to be provided to all of NPC's current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to NPC loads due to the passage of AB 661 and Senate Bill 211 (SB 211). SB 211 allows the Colorado River Commission to sell electricity to its purveyors of water. AB661 allows commercial and governmental customers with an average demand greater than 1 MW to select other energy suppliers. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB661 in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. The forecast takes into account many sources of information. The peak load forecast uses the economic forecast produced by the University of Nevada Las Vegas' Center for Business and Economic Research. The population forecast is used to develop a customer forecast for NPC. Other major assumptions are normal weather (based on 20-year averages), and the addition of hotel rooms will continue as expected. Other uncertainties include abnormal temperatures, the price levels NPC will be allowed to charge, and the timing of rules allowing customers to leave NPC under AB 661 and SB 211. Also, bundled retail price levels, as well as availability of power in the West, could have great effects on consumption by customers of NPC. NPC's total system capability and peak loads for 2002, and the forecast for summer peak demand for 2003 and 2004 (assuming no curtailment of supply or load, and normal weather conditions), are indicated below:
(1) Existing Generation Capacity includes Clark, Reid Gardner, Sunrise, Harry Allen Generating Stations, and NPC's share of Mohave and Navajo Generating Stations.
(2) NPC and its partners in the Mohave Generating Station have not been able to install extensive pollution control equipment necessary to have Mohave's operations extended past 2005 due to coal supply and water issues. The Mohave plant represents 196 MW of capacity. See Note 17 of Notes to Financial Statements, Commitments and Contingencies, Environment for further discussion.
(3) Long-Term Purchases include NPC's allotment of hydroelectric power from Hoover Dam. Values are net of line losses.
(4) Non-Utility Generation Capacity includes SunPeak units and the Qualifying Facilities.
(5) Amount represents on peak wholesale to Silver State Power Pool. Silver State Power Pool, a wholesale customer, is not included in the system peak value of 4,617 MW for 2002. Therefore, NPC resources (generation and purchases) are reduced by the amount of load serving Silver State to show NPC's resources left available to meet the system peak.
(6) Additional Required represents the additional, uncommitted capacity needed in order to maintain an adequate reserve margin consistent with the Western Electricity Coordinating Council planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases.
(7) The system peak shown for 2002 of 4,617 MW occurred on July 12, 2002 at 4:00 p.m.
NPC plans its system capacity needs in accordance with the Western Electricity Coordinating Council (WECC) reliability criteria, which recommends planning reserves in excess of required operating reserves.
GENERATION
The following is a list of NPC's share of generation plants (except Reid Gardner No. 4, see note (2) below), including the MW summer net capacity, the type and fuel used for generation, and the year(s) that the unit(s) was (were) installed.
(1) The combined cycles at Clark Station each consist of one steam turbine and two combustion turbines for a total of six generating units.
(2) Reid Gardner Units 1 through 3 are owned by NPC. Reid Gardner Unit No. 4 is jointly owned by the California Department of Water Resources (CDWR) (67.8%) and NPC (32.2%). NPC is the operating agent. Contractually, NPC is entitled to receive 24 MW of base load capacity from Reid Gardner Unit No. 4 and 226 MW of peaking capacity from Reid Gardner Unit No. 4 for a total base load capacity of 354 MW and peaking capacity of 605 MW for all Reid Gardner Units. NPC is entitled to use 100% of the unit's peaking capacity for 1,500 hours each year and is entitled to 9.6% of the first 250 MW of capacity and associated energy.
(3) This represents NPC'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 represents NPC's 14% undivided interest in the Mohave Generating Station as tenant in common without right of partition with three other non-affiliated utilities, less operating restrictions.
(5) Due to coal supply and water issues, the Mohave plant will not be able to operate after December 31, 2005. See Note 17 of Notes to Financial Statements, Commitments and Contingencies, Environment for further discussion.
PURCHASED POWER
NPC continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2002, NPC experienced favorable market energy prices when compared with the previous four years. The decrease in market energy prices is reflective of FERC price cap regulation, plus the price of gas and power volatility in general, which decreased electricity costs throughout the western United States.
During 2002, NPC experienced difficulty maintaining liquidity in western energy markets due to counterparties' credit concerns with NPC when its credit rating dropped below investment grade. With only a handful of counterparties willing to transact, NPC found it necessary to 1) contract with energy marketers to transact on NPC's behalf, and 2) negotiate special payment arrangements to satisfy credit concerns. These two actions remedied the liquidity limitation.
If NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers and/or to continue to operate outside of bankruptcy.
NPC is a member of the Western Systems Power Pool and the Southwest Reserve Sharing Group (SRSG). NPC's membership in the SRSG has allowed it to network with other utilities in an effort to use its resources more efficiently in the sharing of responsibilities for reserves.
NPC purchases both forward firm energy (typically in blocks) and spot market energy based on economics, operating reserve margins and unit availability. NPC seeks to manage its growing loads efficiently by utilizing its generation resources in conjunction with buying and selling opportunities in the market.
NPC 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. NPC's allocation of hydroelectric capacity is 235 MW annually.
NPC has a contract to purchase 222 MW annually from Nevada Sunpeak Limited Partnership, an independent power producer. The contract became effective June 8, 1991 and will continue through May 31, 2016.
According to regulations issued pursuant to the Public Utility Regulatory Policies Act (PURPA), NPC is obligated, under certain conditions, to purchase the output produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 2002, NPC had a total of 305 MW of contractual firm capacity under contract with four QFs. All QF contracts currently delivering power to NPC at long-term rates have been approved by the PUCN and have QF status as approved by the FERC. The QFs are as follows:
Energy purchased by NPC from the QFs constituted 25.7% of the net purchased power requirements (excluding wholesale purchases) and 12.4% of the net system requirements during 2002. All of the QFs are co-generators providing steam for various products and businesses.
In November 2002, NPC executed and filed with the PUCN four long term power purchase agreements (PPAs) with geothermal developers in northern Nevada for a total of 97 MW or an estimated 841,000 MWh per year, and two PPAs with wind developers, one in each of northern and southern Nevada for a total of 130 MW or an estimated 405,000 MWh per year. The combined total estimated non-solar supply is 1,246,000 MWh annually. The contract term for all but one geothermal PPA is for twenty years. The term for the remaining geothermal PPA is ten years, with an option for either party to extend the PPA by an additional ten years.
NPC also executed five power purchase agreements related to the purchase of renewable energy under the terms of which NPC sells the power associated with the renewable energy contracts located in northern Nevada to SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in SPPC's service territory, NPC will receive "Product" (Product is a defined term in the PPA that includes all Renewable Energy Credits "RECs" and energy supplied by the developer) from the renewable supplier at a delivery point on SPPC's transmission system and then NPC will immediately resell the energy to SPPC under the terms and conditions of a "Related PPA" (defined term in the original PPA). NPC will retain the RECs to comply with the requirements of SB 372, Nevada's renewable portfolio law.
NPC has also executed a solar renewable energy PPA with Duke Solar for a 50 MW facility located near Boulder City in Clark County, Nevada in NPC's service territory. NPC expects to purchase approximately 70 GWh of energy that includes Renewable Energy Credits "RECs" annually.
SPPC entered into a solar PPA with Duke Solar from the same facility located in NPC's service territory. NPC executed an additional Related PPA for this facility. For SPPC's solar PPA, SPPC will receive Product from the renewable supplier at a delivery point on NPC's transmission system and then SPPC will immediately resell the energy to NPC under the terms and conditions of the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to purchase 32 GWh of energy under the terms of the Related PPA. The terms for both SPPC and NPC's solar PPAs are 20 years.
NPC also executed a long term PPA with MNS Wind on the Nevada Test Site for an 85 MW wind project in February 2002.
TRANSMISSION
NPC's existing transmission lines are primarily located within Clark County, Nevada. Six 230 kV transmission lines and two 230/69 kV transformers connect NPC to the Western Area Power Administration's transmission facilities at Henderson and Mead substations. Three 230 kV lines connect NPC to the Los Angeles Department of Water and Power's transmission facilities at McCullough Substation. Two 500/69 kV transformers connect NPC to the Southern California Edison system at the Mohave Generating station. A 345 kV line connects NPC to PacifiCorp at the Utah-Nevada state line. Also, NPC has two 500/230 kV transformers that connect NPC to the Navajo Transmission System at the Crystal Substation. Finally, NPC has ownership rights in two 500 kV transmission lines that allow for the transmittal of NPC's share of power from its interests in the Mohave and Navajo Generating Stations to the NPC control area. If the Mohave Generating station is shut down in 2005, NPC intends to continue to utilize the Eldorado Transmission System that is connected to the Mohave Generating station to supply NPC load and to meet other transmission service obligations currently in place. The transmission and generation are governed under separate contracts.
NPC received approval from the PUCN to construct two transmission line projects and four switchyards proposed in NPC's 2001 Refiled Resource Plan. The Arden-Tolson 230 kV line upgrade, was completed in June 2002 to meet Independent Power Producers (IPP's) transmission service requests at a cost of $475,000. The Faulkner-Tolson 230 kV transmission line will be completed in 2003 at a cost of $9.65 million and will increase NPC's import capability by 300 MW. The Equestrian switchyard was placed in service in 2001. The McDonald switchyard is planned to be completed in 2006. The Avera 230/138 kV switching station and the Beltway 230/138 switching station upgrade projects are all internal NPC reinforcements with 2003 and 2004 in-service dates, respectively. The Avera and Beltway projects are needed for system reliability, increased import capability, and to provide a path for Centennial IPP energy to be delivered into or through NPC's transmission system. The Avera project costs are estimated at $5.3 million and the Beltway project costs are approximately $8.25 million.
As a result of the supply shortage in the western United States experienced during 2000 and 2001, several IPPs proposed the construction of new generating plants in southern Nevada and requested transmission service from NPC. NPC proposed the Centennial Plan to address transmission service requests from these IPPs. The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. This plan, consistent with its tariff and the FERC pricing policies, involves the following lines (1) the Harry Allen substation to Crystal substation 500 kV line, (2) the Harry Allen substation to Northwest substation 500 kV line, (3) the Harry Allen substation to Mead substation 500 kV line and (4) two Bighorn to Arden 230 kV lines. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformers at Mead, McCullough and Northwest substations, two phase shifting transformers at Crystal substation, and several other sub-transmission upgrades and additions. The Harry Allen - -Crystal 500 kV line and the Harry Allen 500 kV substation were energized in June 2002. The Arden- Bighorn 230 kV #1 and #2 lines were completed in July 2002. The Harry Allen - Northwest 500 kV line, the Northwest 500/230 kV transformer and the Northwest 500 kV substation were completed in mid-March 2003. The Crystal 500 kV phase shifting transformers will be installed in February 2004. The scheduled in-service date for the Harry Allen-Mead 500 kV line, the Mead 500/230 kV transformer and the McCullough 500/230 kV transformer is April 2006.
See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of regional transmission issues.
FUEL AVAILABILITY
NPC's 2002 fuel requirements for electric generation were provided by natural gas, coal and oil. The average costs of coal, gas and oil for energy generation per million British thermal units (MMBtu) for the years 1998 - 2002, along with the percentage contribution to total fuel requirements were as follows:
Average Consumption Cost & Percentage Contribution to Total Fuel Requirements
* Oil was less than .1% of consumption
For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Coal delivered to the Reid Gardner Station originates from various mines in the Utah coalfields and is delivered to the station via the Union Pacific Railroad. Partial requirements for coal supplies are under contract for various terms up to 2007, with the remainder of 2002's requirements purchased from the spot market under four one-year contracts. NPC's long-term coal supply agreement with RAG Coal Sales of America, Inc. is supplied from its Willow Creek Mine in Carbon County, Utah, which experienced an explosion and fire on July 31, 2000. No deliveries under this agreement were scheduled for 2002 and NPC replaced these volumes with spot market purchases. The mine remains sealed and NPC does not anticipate that deliveries will resume before the contract terminates. The contract remains in a force majeure status. The contract was due to expire in 2007 and has been replaced by short-term purchases.
The Union Pacific Rail Transportation contract provides for deliveries from the Provo, Utah interchange as well as various mines in the Price, Utah area, to the Reid Gardner Station in Moapa, Nevada. This contract was effective January 1, 1996 and has been extended through December 31, 2004. The Utah Railway contract provides for the remainder of NPC's Price, Utah area supplies. This contract has been extended through December 31, 2003 and will be renegotiated year to year as needed. All of NPC's rail transportation contracts contain certain tonnage requirements and railroad service criteria.
Coal for both the Mohave and Navajo Stations is obtained from surface mining operations conducted by Peabody Coal Company on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian Tribes reservations. The supply contracts with Peabody extend to December 31, 2005, for Mohave and to June 1, 2011, for Navajo, with each contract having an option to extend for an additional 15 years. The Mohave coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, Southern California Edison's (SCE's) application with the California Public Utility Commission (CPUC) to determine whether it is in the public interest to continue operation of the Mohave facility states that it probably will not be possible for SCE, the operating partner, to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005.
NPC purchases natural gas on a firm, fixed and indexed price basis from the Rocky Mountain Basin.
Natural gas is transported to the Clark, Sunrise and Harry Allen stations via Kern River Gas Transmission Company from the Rocky Mountain Basin. NPC has entered into a summer seasonal transportation contract for 50,000 decatherms (Dth)/day and an annual contract for 75,000 Dth/day of Kern River Pipeline capacity. This service is scheduled for delivery in May 2003 and will run for a period of 15 years. NPC also responded to an open season for shorter term service in the Kern River California Emergency Expansion and was awarded 29,600 Dth/day for the period July 2001 to April 2002, and 5,600 Dth/day for the period May 2002 to April 2003. The Kern River California Emergency Expansion service does not carry any renewal rights.
Local natural gas transportation service to Clark and Sunrise Stations is provided under a 32-year transportation services contract with Southwest Gas Company signed in 1995. This contact provides firm service and contains certain operating and nominating provisions. The Harry Allen Station is directly connected to Kern River Pipeline.
Oil provides a secondary fuel for Clark, Sunrise and Harry Allen Stations and is used in the igniters at Reid Gardner.
REGULATION AND RATE PROCEEDINGS
See Regulation and Rate Proceedings in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
OTHER
On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002, general election ballot which asked voters in a non-binding initiative whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." The Company and various private entities and public interest groups strongly opposed the measure. Although passing by a 57% majority, this was substantially below the level of support indicated in early polls. No bills related to this issue were introduced in the 2003 Nevada legislative session.
On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiations of definitive agreements to acquire NPC in some undetermined way (stock purchase or all or some of its assets) and to assume some unspecified amount of indebtedness, at a purchase price subject to adjustment at SNWA's discretion at the conclusion of negotiations and due diligence. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal, SNWA's lack of utility management experience, and ambiguity in the proposal. SPR was served with a complaint by a shareholder seeking class action status to require SPR to enter into negotiations. See Legal Proceedings for further details.
SIERRA PACIFIC POWER COMPANY
SPPC is a Nevada corporation organized in 1965 as a successor to a Maine corporation organized in 1912. SPPC became a wholly owned subsidiary of Sierra Pacific Resources on May 31, 1984. Its mailing address is Post Office Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024.
SPPC is a public utility primarily engaged in the distribution, transmission, generation, purchase, and sale of electric energy. It provides electricity to more than 318,000 customers in an approximately 50,000 square mile service area in western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. In 2002, electric revenues were 86.1% of SPPC's revenue.
SPPC also provides natural gas service in Nevada to approximately 123,500 customers in an area of about 600 square miles in Reno/Sparks and environs. In 2002, natural gas revenues were 13.9% of SPPC's revenues.
In June 2001, SPPC completed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of income taxes of $18.2 million. The sale agreement contemplates a second closing for the transfer of hydroelectric facilities included in the contract of sale for an additional $8 million to accommodate review of the transaction by the CPUC. See Sale of Water Business, later, for further discussion.
SPPC has three primary, wholly owned subsidiaries: GPSF-B, Pinon Pine Corp. (PPC) and Pinon Pine Investment Co. (PPIC). GPSF-B, PPC and PPIC, collectively, own Pinon Pine Company, L.L.C., which was formed to take advantage of federal income tax credits available under Section 29 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Pinon Pine facility. See Note 21 of Notes to Financial Statements, Pinon Pine.
BUSINESS AND COMPETITIVE ENVIRONMENT
In 2002, SPPC's electric business contributed $931 million (86.1%) in revenues from continuing operations. The electric system peak typically occurs in the summer, while the winter peak is nearly as high. The system has an annual load factor of approximately 74.98%, which is higher than the industry norm of 50% to 55%.
Winter retail peak loads are primarily driven by increased demand for space heating, demand for air movement (with forced air gas and oil furnaces), and ski resort demands (hotels, lifts, etc.). Summer retail peak loads are primarily driven by cooling equipment demand (including air conditioning demand) and irrigation pumping. SPPC's peak load increased an average of 2.7% annually over the past three years, reaching 1,590 MW on July 10, 2002. SPPC's total retail electric MWh sales have increased an average of 1.1% annually over the past three years.
SPPC's electric customers by class contributed the following toward 2002 and 2001 MWh sales:
According to the Nevada Division of Minerals, gold is Nevada's most important mineral commodity in terms of economic impact on the state and on communities located near mining operations. The state's gold production has remained near 8 million ounces per year over the past 5 years, enabling Nevada to maintain its position as the leading gold producing state in the U.S. While gold mining in past years has been challenged by a relatively low commodity price, individual mines have focused on improving efficiency at their operations, reducing overhead costs, and closing down less efficient and uneconomic properties. While these actions led to a small decrease in total MWh sales by SPPC to the mining industry during 2002, they also enabled mines to lower production costs so they could operate economically during the period of low gold prices and improve their competitive position. With projections that recent increases in gold prices will be sustained at or above current levels for a number of years, individual companies are expected to maintain their production activities and resulting energy use at current levels for the foreseeable future.
SPPC has long-term electric service agreements with eight of its major mining customers. The terms range from 5 to 15 years from the effective dates of these agreements with the longest term contract expiring in 2011. SPPC had sales in 2002 of approximately $148 million in annual revenues, which is 16.0% of 2002 electric operating revenues under these agreements. The agreements require that customers maintain minimum demand and load factor levels, and include termination charge provisions to recover all of SPPC's customer-specific facilities investment and secures approximately $6 million in annual revenues through electric facilities charges.
The offices/schools/government and healthcare customer segment continues to grow with the addition of new schools, government facilities and healthcare facilities. At the same time that growth is occurring, customers' implementation of energy conservation and efficiency programs has led to a 4.85% decrease in energy sales to the overall sector. In healthcare, increasing demands for new long term and acute care facilities is expected to double the number of facilities by 2006. In the education sector, one new high school will open in 2003, a middle school in 2004, and on average, two new schools will be added each year between 2005 and 2007.
The resorts and recreation customer segment, consisting of hotels, casinos and ski resorts, account for 7.3% of the total electric system retail MWh sales. MWh sales were down 8% in 2002 compared to 2001 primarily as a result of customers' continued efforts to implement energy conservation measures. In the ski
resort segment, energy consumption was reduced in response to heavy natural precipitation and snow early in the 2002-2003 ski season that enabled resorts to decrease their use of artificial snowmaking equipment.
In 2002, tourism and gaming were negatively impacted by a reduction in flight schedules to northern Nevada and a continuing increase in competition from gaming on Indian reservations in California. In response, the industry and the community continued to work together to strengthen the region's competitive position in the tourism, gaming and leisure markets. These efforts included the opening of a major new hotel casino in Reno, the completion of a $105 million, 500,000 square foot renovation and expansion of the Reno-Sparks Convention Center, and the repositioning of the state's tourism advertising to promote its natural resources and its diversified entertainment and recreation opportunities.
The manufacturing and warehousing customer segment overall continued to decline for a second straight year. Many manufacturing customers have suffered large order reductions and production losses due to the economic slowdown. However, manufacturing orders are beginning to recover from their all time low point in 2002. At the same time, there has been an increase in the number of customers in the sector as the result of small manufacturers relocating out of the California market. Northern Nevada continues to develop as a destination for relocating high-technology companies, which could result in an increase in sales to the manufacturing and warehousing customer segment. In 2002 SPPC continued to solidify working relationships within the business community by assisting in the recruitment of industries in targeted sectors such as plastic manufacturers and high-technology companies.
The 2001 session of the Nevada State Legislature enacted AB 661. One provision of this bill allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider beginning in mid-2002. This provision was part of a package of legislation passed by the 2001 Legislature to ensure the continued creditworthiness of the Utilities, protect consumers from unexpected rate hikes, and attract new energy suppliers to Nevada. During 2002, one qualifying customer filed a notice of intent with the PUCN indicating their desire to procure energy services from a new provider. This customer has not yet filed a formal application with the PUCN but could do so at any time. Under the law, the earliest departure date would be 180 days after the application is filed.
SPPC's MWh sales to wholesale customers have decreased 36.8% over the past year. During 2002 firm and non-firm sales to wholesale customers comprised 23.0% of total energy sales. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with SPPC.
SPPC's decrease in wholesale MWh sales from last year was a result of market conditions and SPPC's power procurement activities. See Energy Supply in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of the Utilities' purchased power procurement strategies.
CONSTRUCTION PROGRAM
SPPC'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, the number and status of proposed independent generation projects, the need for additional transmission capacity in northern Nevada, adequacy of rate relief, SPPC's ability to raise necessary capital and changes in environmental regulation. Under SPPC's franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. SPPC's service territory continues to experience steady growth. Capital construction expenditures and estimates are reflective of this obligation to serve.
Gross construction expenditures for 2002, including AFUDC and contributions in aid of construction, were $105.3 million, and for the period 1998 through 2002, were $719.4 million. Estimated construction expenditures for 2003 and the period 2004-2007 are as follows (dollars in thousands):
Total construction expenditures estimated for 2003 and the 2004-2007 period, for each segment of SPPC's business, consist of the following (dollars in thousands):
The Falcon to Gonder Transmission Project is a 345kV transmission line within northern Nevada with a planned in-service date of May 2004. Total project costs incurred through December 31, 2002, were $32.8 million. Actual costs incurred in 2002 were $21.0 million. Estimated costs for 2003 are $46.5 million.
FACILITIES AND OPERATIONS
TOTAL SYSTEM
SPPC maintains a wide variety of resources in its generation system. The availability of alternate resources allows SPPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. SPPC also supplies its customers' electric power needs using a combination of firm and interruptible resources to maximize operating flexibility and reliability while minimizing cost. During 2002, SPPC generated 39.5% of its total electric energy requirements in its own plants, purchasing the remaining 60.5% as shown below:
As a supplement to its own generation, SPPC purchases both firm and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. SPPC's decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing "as-available" energy when it is less expensive than SPPC's own generation, again, subject to net system import limits. In 2002, most of SPPC's non-utility generation came from QFs. See Energy Supply in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for additional information.
RISK MANAGEMENT
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
LOAD AND RESOURCES FORECAST
SPPC's electric customer growth rate was 2.3% in 2002, 1.9% in 2001, and 2.6% in 2000. Annual retail electricity sales were 8.7 million MWh in 2002 and 2001. Annual wholesale electricity sales reached 2.6 million MWh in 2002, which represents a decrease of 36.8% from 2001 wholesale electricity sales of 4.1 million MWh. Overall, annual system electricity sales reached 11.3 million MWh in 2002, which represents a decrease of 12.0% from 2001 system electricity sales of 12.8 million MWh. The 2002 peak electric demand was 1,590 MW. The 2001 peak demand was 1,529 MW.
The projections shown below are forecasts of the load to be provided to all of SPPC's current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to SPPC loads due to the passage of AB 661 by the 2001 Nevada Legislature which allows commercial and governmental customers with an average demand greater than one MW to select other energy supplies. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB 661 in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation. The forecast includes an assumption that normal weather (based on 20-year averages) will occur. Other uncertainties to the forecast include abnormal weather, failure of the local economy to recover, and customer losses due to AB 661. SPPC continues to provide energy through generation and purchased power to meet both summer and winter peak loads. SPPC's total system capability and peak loads for 2002, and the forecast for summer peak demand through 2004 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:
(1) Value is net of losses and includes committed short-term firm block purchases. Values shown represent purchases within existing transmission system limits. No economy (non-firm) energy purchases occurred during the 2002 peak, only firm power purchases.
(2) The system peak shown for 2002 occurred on July 10, 2002, at 5:00 p.m.
SPPC plans its system capacity needs in accordance with the WECC reliability criteria, which recommends planning reserves in excess of required operating reserves. The "Additional Required" represents the additional, uncommitted capacity needed in order to maintain adequate reserve margin consistent with the WECC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2004 to the extent available.
GENERATION
The following is a list of SPPC's share of generation plants including the MW summer net capacity, the type and fuel used to generate, and the year(s) that the unit(s) was (were) installed.
(1) SPPC is the operator and owns an undivided 50% interest in the Valmy plant. Idaho Power Company owns the remainder. SPPC owns 100% of all of its remaining electric generation plants.
(2) Pinon is part of the Pinon Pine Integrated Coal Gasification Combined Cycle power plant. This project was part of the Department of Energy's Clean Coal Demonstration Program. Although the coal gasification portion of the facility is inactive, the combined cycle units have been operating on natural gas since 1996. See Note 21, Pinon Pine, to the Notes to Financial Statements.
(3) The combined cycle at Pinon consists of one combustion turbine and one steam turbine. Pinon is located at the Tracy Generating Station.
(4) The four hydroelectric generating units, with a total capacity of 8.7 MW, were to be included in the sale of SPPC's water business in June 2001. The California Legislature has passed a law exempting the hydro plants from the prohibition against generation divestiture. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies and SPPC must supplement the application with a certified environmental document.
PURCHASED POWER
SPPC continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2002, SPPC experienced favorable market energy prices when compared with the previous four years. The decrease is reflective of FERC price cap regulation, which decreased electricity costs throughout the western United States.
During 2002, SPPC experienced difficulty purchasing power in western energy markets due to counterparties' credit concerns with SPPC when its credit rating dropped below investment grade. With only a handful of counterparties willing to enter into agreements, SPPC found it necessary to 1) contract with energy marketers to transact on SPPC's behalf, and 2) negotiate special payment arrangements to satisfy credit concerns.
If SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements and is unable to obtain power through other means, SPPC's business, operations and financial condition would be materially adversely affected and could make it difficult for SPPC to continue to provide reliable service to its customers or to operate outside of bankruptcy.
SPPC is a member of the Northwest Power Pool and Western Systems Power Pool. These pools have provided SPPC further access to reserves and spot market power, respectively, in the Pacific Northwest and Southwest. In turn, SPPC's generation facilities provide a backup source for other pool members who rely heavily on hydroelectric systems.
SPPC purchases hydroelectric and thermal generation spot market energy, by the hour, based upon economics and system import limits. Also purchased during peak load periods is firm energy as required to supply load and maintain adequate operating reserve margins. As off-system energy costs increase, SPPC supplies a higher percentage of its native load utilizing its fossil fuel generation.
Currently, SPPC has contracted for a total of 75 MW of long-term firm purchased power from PacifiCorp. SPPC's firm purchase power contract is from June 1989 to February 28, 2009 and contains a 70% minimum purchase obligation.
According to PURPA, SPPC is obligated under certain conditions to purchase the output produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. As of December 31, 2002, SPPC had a total of 109 MW of maximum contractual firm capacity under 15 contracts with QFs. SPPC had contracts with three of the 15 projects at variable short-term avoided cost rates. All QF contracts currently delivering power to SPPC at long-term rates have been approved by either the PUCN or the CPUC, and have QF status as approved by the FERC. One long-term QF contract terminates in 2006, one terminates in 2039, and the remaining terminate between 2014 and 2022.
Energy purchased by SPPC from QF contracts continues to provide useful diversity for SPPC in meeting its peak load. All the QFs from which SPPC makes firm purchases are either geothermal, hydroelectric or biomass.
The actual QF firm capacity output under contract was 62 MW during the summer of 2002. The actual QF output for all non-utility generator deliveries during the summer 2002 peak was 263 MW.
NPC also executed five power purchase agreements related to the purchase of renewable energy under the terms of which NPC sells the power associated with the renewable energy contracts located in northern Nevada to SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in SPPC's service
territory, NPC will receive "Product" (Product is a defined term in the PPA that includes all Renewable Energy Credits "RECs" and energy supplied by the developer) from the renewable supplier at a delivery point on SPPC's transmission system and then NPC will immediately resell the energy to SPPC under the terms and conditions of a "Related PPA" (defined term in the original PPA). NPC will retain the RECs to comply with the requirements of SB 372, Nevada's renewable portfolio law.
SPPC entered into a solar PPA with Duke Solar from the same facility located in NPC's service territory. NPC executed an additional Related PPA for this facility. For SPPC's solar PPA, SPPC will receive Product from the renewable supplier at a delivery point on NPC's transmission system and then SPPC will immediately resell the energy to NPC under the terms and conditions of the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to purchase 32 GWh of energy under the terms of the Related PPA.
The terms for both SPPC and NPC's solar PPAs are 20 years.
TRANSMISSION
SPPC's existing transmission lines extend some 300 miles from the crest of the Sierra Nevada in eastern California, northeast to the Nevada-Idaho border at Jackpot, Nevada, about 160 miles from Reno northwest to Alturas, California, and 250 miles from the Reno area south to Tonopah, Nevada. A 230 kV transmission line connects SPPC to facilities near the Utah-Nevada state line, which in turn interconnects SPPC to Utah Power facilities. A 345 kV transmission line connects SPPC to Idaho Power facilities at the Idaho-Nevada state line. A 345 kV line connects SPPC to the Bonneville Power Administration's facilities near Alturas, California.
SPPC also has two 120 kV lines and one 60 kV line that interconnect with Pacific Gas & Electric on the west side of SPPC's system at Donner Summit, California. Two 60 kV transmission ties allow wheeling of up to 14 MW of power from the Beowawe Geothermal Project, which is located within SPPC's service area, to Southern California Edison. These two minor interties are available for use during emergency conditions affecting either party. The transmission intertie system provides access to regional energy sources.
The Falcon to Gonder Project is a 180-mile 345 kV line connecting SPPC's Falcon Substation to Mt. Wheeler Power's Gonder Substation. The Falcon to Gonder Project improves system import and export capabilities and enables SPPC to provide transmission service between Idaho, Utah, and the northwest. The Final Environmental Impact Statement was released in December 2001. Federal permitting was completed in July 2002. Construction started March 3, 2003 with an expected in-service date of May 2004. Total project costs incurred through December 31, 2002, were $32.8 million. Actual costs incurred in 2002 were $21.0 million. Estimated costs for 2003 are $46.5 million.
See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of regional transmission issues.
FUEL AVAILABILITY
SPPC's 2002 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of coal, gas and oil for energy generation per MMBtu for the years 1998-2002, along with the percentage contribution to total fuel requirements, are as follows:
For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
SPPC fully satisfied all volume requirements under a long-term contract with Black Butte Coal Company for coal shipments to Valmy, which terminated in February 2002.
SPPC's long-term coal contract with Canyon Fuel Company, LLC (Canyon), which provides coal for Valmy from Canyon's SUFCO mine in Central Utah, expires on June 30, 2003. The coal supply agreement for Valmy has been replaced with a new contract from Arch Coal for deliveries through December 31, 2006. The current owner of the SUFCO mine is Arch Coal, Inc., which acquired ARCO Coal (the previous owner of the Canyon properties, including SUFCO) on June 1, 1998.
During 2002, two short-term agreements for the purchase of spot market coal were in place. The source of this coal is the Uinta Basin of Utah. These spot market purchases supplement base volume requirements under SPPC's long-term coal contracts at a cost approximately one-half that of contract coal.
As of December 31, 2002, Valmy's coal inventory level was 257,740 tons, or approximately 45 days of consumption at 100% capacity. Inventory levels were increased to allow for economically priced supplies under contract to be delivered prior to the expiration of those supply arrangements.
During 2002, transportation of coal to Valmy was provided by the Union Pacific Railroad (UP) under a contract that will expire December 31, 2004.
During 2002, SPPC operated the Pinon Pine facility exclusively on natural gas. No coal was purchased in 2002 for synthetic gas production in the plant's coal gasification facility.
SPPC meets its needs for residual oil for generation through purchases on the spot market. The actual residual oil inventory level was 325,334 barrels as of December 31, 2002, which is equal to a 14-day supply at full load operation.
NATURAL GAS BUSINESS
SPPC's natural gas business consists of operating the local distribution company (LDC) for the Reno/Sparks metropolitan area and procuring gas for electrical power generation at the Tracy and Ft. Churchill
plants. The LDC accounted for $149.8 million in 2002 operating revenues or 13.9% of SPPC's revenues from continuing operations. Growth in SPPC's LDC service territory continues to be strong. Customer meter count growth during 2002 was approximately 3.7%. SPPC's total customer gas meter count increased by 4,520 to 126,382 meters by the end of 2002.
Growth in all sectors is expected to continue due to the fact that new real estate developments in SPPC's distribution service area are under construction and planned for the near future. SPPC's forecast for growth in the number of LDC customers in 2003 is 4,800 meters.
SPPC's natural gas LDC business is subject to competition from other suppliers and other forms of energy available to its customers. Large customers with fuel switching capability compare natural gas prices on an interruptible basis to alternative energy source prices. Additionally, large customers have the ability to secure their own gas supplies. As of March 13, 2003, there are 11 large customers securing their own supplies. These customers have a combined firm distribution load of 3,665 Dth per day. Three additional customers have announced intentions to begin securing their own supplies in mid 2003. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own supply.
To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with over a dozen Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. Annual contracts totaled approximately 65,000 Dth per day. The winter period contracts totaled approximately 50,000 Dth per day, and the summer period contracts totaled approximately 9,000 Dth per day.
SPPC's firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington and liquefied natural gas (LNG) storage from a facility located near Lovelock, Nevada. The contract for LNG facility operated by Paiute Pipeline Company terminated on February 28, 2003. The Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies. A peaking transaction to Southwest Gas terminated on the same date.
In November 1996 SPPC entered an agreement to sell winter seasonal peaking capacity supplies to another company over a seven-year period. The contract provides for the payment to SPPC of a monthly reservation charge, reimbursement of pipeline capacity charges during the winter, and a volumetric commodity charge based on the market price for natural gas. SPPC was able to enter into this agreement due to the ability of its power plants to utilize alternative fuels and its power importation option. The obligation to provide peaking supply terminated on February 28, 2003 coincident with the termination of the LNG contract and therefore no additional resources are required to meet Sierra load obligations.
Following is a summary of SPPC's transportation and storage portfolio (as of December 31, 2002). Firm transportation capacity on the Northwest/Paiute system exists to serve primarily the LDC. Firm transportation capacity on the Pacific Gas & Electric Gas Transmission Northwest (PGT)/Tuscarora system exists primarily to serve SPPC's electric generating plants. Storage capacity is generally used for the peaking requirements of the LDC.
Transportation Capacity
Total LDC Dth supply requirements in 2001 and 2002 were 14.26 million Dth and 14.57 million Dth, respectively. Electric generating fuel requirements for 2001 and 2002 were 28.9 million Dth and 23.7 million Dth, respectively.
In December 2002, the PUCN released its order regarding SPPC's Purchase Gas Adjustment filing made on July 1, 2002 and the new rates became effective January 1, 2003. An average residential customer received a decrease in their rates of approximately 3%.
As of December 31, 2002, SPPC owned and operated 1,693 miles of three-inch equivalent natural gas distribution piping, 91 miles of which were added in 2002. Two significant projects were completed to improve distribution system's capacity in two high growth areas in south Reno where 5,600 feet of 18 inch main was installed and in northern Sparks where 4,531 feet of 8 inch main was installed.
SALE OF WATER BUSINESS
In June 2001, SPPC closed the sale of its water business to the TMWA for $341 million. SPPC recorded a $25.8 million gain on the sale, net of income taxes of $18.2 million. Pursuant to a stipulation entered into in connection with the sale and approved by the PUCN, SPPC was required to refund to customers $21.5 million of the proceeds from the sale. The refund was credited on the electric bills of SPPC's former water customers over a fifteen-month period ended November 2002.
Under a service contract with TMWA, SPPC provided customer service and billing services to TMWA until August 2002. SPPC continues to provide meter-reading services under a one-year service contract renewable in one-year increments by TMWA through 2008. On September 24, 2002, California Assembly Bill 1235 was approved which amended previous California legislation that prevented until 2006 private utilities from selling any power plants that provide energy to California customers. Transfer of the four hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the CPUC. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. Not included in the sale were certain properties along the Truckee River related to the hydroelectric facilities and in California at Independence Lake. SPPC continues to own these properties with the intent of possible future sale. For further discussion of this item, see Generation Divestiture below.
REGULATION AND RATE PROCEEDINGS
See Regulation and Rate Proceedings in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
GENERATION DIVESTITURE (NPC AND SPPC)
As a condition to its approval of the merger between SPR and NPC, the PUCN required the Utilities to file a Divestiture Plan for the sale of their electric generation assets. The PUCN approved a revised Divestiture Plan stipulation in February 2000. In May 2000, an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000, the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison.
In addition, SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an amendment, AB 1235, to AB 6 that would allow SPPC to complete the sale of the four hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric Unit is conditioned on the completion of the reconstruction of the Farad dam and flume or assignment of SPPC insurance claim for reconstruction of the dam. The Farad Reconstruction Project is currently in the permitting phase with permits expected by mid-2003.
The sales agreements for the six bundles provided that they terminate eighteen months after their execution unless the parties agreed to an earlier termination. The parties could have extended the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which rendered the contracts impossible to perform, the Utilities engaged in discussions with the buyers of the generation assets regarding the formal termination of the sales agreements and the related energy buyback contracts and interconnection agreements. Those discussions ended without agreement to mutually terminate; however, all the contracts have now terminated in accordance with the contract provisions. As of December 31, 2002, the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2 million at SPPC in order to prepare for the sale of generation assets. The Utilities requested recovery of these costs in each Utility's respective general rate case filings with the PUCN. The PUCN delayed recovery of the divestiture costs to a future rate case request but did grant a carrying charge on the costs until such time as recovery is allowed. A further discussion of the Regulation and Rate Proceedings is included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation.
ENVIRONMENT (SPR, NPC AND SPPC)
As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. SPR's Board of Directors has a
comprehensive environmental policy and a separate board committee that oversees NPC's, SPPC's, and SPR's corporate performance and achievements related to the environment.
NEVADA POWER COMPANY
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units respectively. The estimated cost of new controls is $1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million.
NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005.
NPC is currently evaluating and analyzing all of its options with regard to the Mohave project.
In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated at $15 million.
At the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required NPC to submit a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in April 2003 at an estimated cost of $150,000.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan, which was approved in
June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC will spend $789,000 to line existing ponds. This project was started in 2002 and is expected to be completed in the first quarter 2003.
In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000 NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. To date, EPA has not issued additional requests for further information.
NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4.8 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond.
SIERRA PACIFIC POWER COMPANY
In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through December 31, 2002. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites.
LANDS OF SIERRA
LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contamination resulting from an underground fuel tank that has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. The Lahontan Regional Water Quality Control Board has approved closure without additional remediation pending a one-year monitoring period. Final closure is anticipated in December 2003.
OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES
TUSCARORA GAS PIPELINE COMPANY
TGPC was formed as a wholly owned subsidiary of SPR in 1993 for the purpose of entering into a partnership with a wholly owned subsidiary of TransCanada PipeLines, Ltd., headquartered in Calgary, Alberta, Canada. The partnership, Tuscarora Gas Transmission Company (Tuscarora) was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding gas market in Reno, northern Nevada, and northeastern California. In late 1995, Tuscarora completed the construction of its 229-mile pipeline system and began commercial operations on December 1, 1995. Tuscarora takes custody of its customers' gas near Malin, Oregon at a pipeline interconnect with PG&E Gas Transmission Northwest (PGT), the upstream pipeline. Upon custody transfer, Tuscarora transports its shippers' gas to various delivery points along the Tuscarora system as prescribed by its customers. PGT is a major interstate natural gas pipeline extending from the U.S./Canadian border, at a point near Bonners Ferry, Idaho to the Oregon/California border. The PGT system provides Tuscarora customers access to Canadian natural gas reserves in the Western Canadian Sedimentary basin, one of the largest natural gas reserve basins in North America.
As an interstate natural gas pipeline, Tuscarora provides only transportation service to its customers. SPPC was the largest customer at the start of commercial operations and continues to be Tuscarora's largest customer contributing 92% of gross revenues in 2002.
In 2000, Tuscarora constructed a 14.2-mile pipeline lateral, establishing a new city gate for the SPPC distribution system. The lateral was completed and placed in service January 29, 2001, providing SPPC with an additional 10,000 Dth per day of firm transportation capacity in January 2001 and 5,661 Dth per day in November 2001. Also in 2000, Tuscarora surveyed shipper interest in an expanded Tuscarora system and determined that there was a significant need for additional transportation capacity. By late year 2000, Tuscarora executed Precedent Agreements for new expansion capacity were obtained from four customers including SPPC (11,412 Dth/day), Morgan Stanley (20,000 Dth/day), Southwest Gas Corporation (24,500 Dth/day) and Duke Energy North America (Duke) (40,000 Dth/day).
In January 2001, Tuscarora launched its 2002 Expansion Project on the strength of those binding agreements. On January 30, 2002, Tuscarora received its Certificate of Public Convenience and Necessity from the FERC authorizing Tuscarora to construct and operate the 2002 Expansion Project. At that time, Tuscarora requested that all expansion shippers execute Transportation Service Agreements (TSA) in accordance with the provisions of the Precedent Agreements. It became apparent to Tuscarora at that time that Duke would not be in a position to execute a TSA because their proposed generation plant, for which their portion of the expansion capacity would be used, was being delayed by at least one year due to conditions in the energy market.
On February 25, 2002, Tuscarora filed to amend its FERC certificate authorization to allow phasing the construction of facilities to accommodate the Duke delay. The FERC subsequently approved the amendment whereby Tuscarora could construct sufficient facilities to serve the non-Duke related (Phase 1) expansion facilities in year 2002 and construct the Duke related (Phase 2) expansion facilities in year 2003. On May 8, 2002, Duke notified Tuscarora that it was canceling its proposed generation plant indefinitely and therefore it was terminating its Precedent Agreement with Tuscarora to avoid further exposure to expansion related costs. This action by Duke effectively reduced the expansion subscription from an original capacity requirement of 95,912 Dth/day to 55,912 Dth/day, reflecting the loss of the Duke capacity amount of 40,000 Dth/day. Tuscarora and Duke subsequently arrived at a termination fee and payment of that fee was made on January 8, 2003. Construction of the Phase 1 non-Duke related facilities was completed in late November 2002 and the facilities were placed into service on December 1, 2002. Those Phase 1 facilities included construction of two 6,000 horsepower (site rated) compressor stations located near the towns of Canby and Susanville, California
and 10.5 miles of 20-inch pipeline located in Washoe County, Nevada. Phase 1 facilities also established a new Tuscarora interconnect with the Paiute Pipeline Company located near Wadsworth, Nevada and included the installation of a 600 horsepower booster station at the Paiute interconnect site.
Tuscarora has been seeking, without success, shipper interest in the Duke portion of the expansion capacity and has not yet filed for a certificate amendment to remove Phase 2 facilities from the expansion project. That amendment is scheduled to be filed with the FERC by the end of March 2003. Had Phase 2 facilities been constructed, they would have consisted of one 6,000 horsepower compression station located near Likely, California and 3.5 miles of 20-inch pipeline that would have extended service from the Paiute Pipeline interconnect to the location of the proposed Duke generation plant located near Wadsworth, Nevada. The expansion project increased Tuscarora's system capacity by approximately 51% and improved the overall reliability of the natural gas transportation system in the region.
In May 2001, Tuscarora completed construction of approximately 3,520-feet of pipeline lateral to serve an existing 360 MW plant located east of Reno, Nevada near SPPC's Tracy Power Plant, and in September 2001 Tuscarora completed construction of a 10.8-mile pipeline lateral to serve two new customers located in California; the City of Susanville and the California Department of Corrections High Desert facility.
For a discussion of TGPC's results of operations, refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
SIERRA PACIFIC COMMUNICATIONS
SPC was created to examine and pursue telecommunications opportunities that leverage SPPC's existing skills of installing and deploying pipe and wire infrastructure. SPC presently has fiber optic assets deployed in the cities of Reno and Las Vegas, which it is currently marketing.
Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The assets are currently under construction and are scheduled for completion in June 2003.
On September 11, 2002, SPC entered into an agreement to sell to a telecommunications carrier for $20 million the Sacramento to Salt Lake City conduit acquired from Touch America, and will convey all rights to the conduit when construction is completed in June 2003.
For a discussion of the legal proceedings affecting SPC refer to Item 3, Legal Proceedings.
For a discussion of SPC's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
E-THREE
e-three was organized in October 1996 as an unregulated, wholly owned subsidiary of SPR. It provides comprehensive energy and other business solutions in commercial and industrial markets. This is accomplished by offering a variety of energy-related products and services to increase customers' productivity and profits and improve the quality of the indoor environment. These products and services include: technology and efficiency improvements to lighting, heating, ventilation and air-conditioning equipment; installation or retrofit of controls
and power quality systems; energy performance contracting; end-use services; and ongoing energy monitoring and verification services.
In September 1998, e-three and NEICO, a wholly owned subsidiary of NPC, formed e-three Customer Energy Solutions, LLC, a Nevada limited liability company, for the purpose of selling and implementing energy-related performance contracts and similar energy services in southern Nevada. e-three Custom Energy Solutions, LLC's primary focus for its sales activities is in the commercial and industrial markets.
In October 1998, e-three acquired Independent Energy Consulting, Inc. (IEC), a California based company, in an exchange of SPR stock for all of IEC's stock. IEC provides energy procurement management, third party auditing, performance contract consulting and strategic energy planning in the industrial and commercial markets.
In mid 2000, e-three Custom Energy Solutions, LLC completed the construction of a chilled water cooling plant in the downtown area of Las Vegas. The plant is owned by e-three Custom Energy Solutions, LLC and supplies the indoor air-cooling requirements for a number of businesses in its immediate vicinity.
For a discussion of e-three's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
SIERRA PACIFIC ENERGY COMPANY
SPE was formed to market a package of technology and energy-related products and services in Nevada. SPE filed an application with the PUCN to be licensed as an Alternative Seller of Electricity in the state of Nevada. SPE has withdrawn its application with the PUCN and dissolved its retail energy marketing efforts. SPE continues to manage several long term commitments entered into prior to its withdrawal from the retail energy marketing effort.
For a discussion of SPE's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
LANDS OF SIERRA
LOS was organized in 1964 to develop and manage SPPC's non-utility property in Nevada and California. These properties previously included retail, industrial, office and residential sites, timberland, and other properties. Remaining properties include land in Nevada and California. SPR has decided to focus on its core energy business. In keeping with this strategy, LOS continues to sell its remaining properties.
For a discussion of LOS' results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
SEGMENT FINANCIAL INFORMATION
For certain financial information concerning SPR and the Utilities business segments, see Note 18, Segment Information, in Notes to Financial Statements.
GENERAL - EMPLOYEES (ALL)
SPR and its subsidiaries had 3,194 employees as of December 31, 2002, of which 1,745 were employed by NPC and 1,336 were employed by SPPC.
NPC's current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 57% of NPC's workforce, was renegotiated in February 2002 and is in effect until February 1, 2005. The three-year contract provides for a 3% general wage increase for bargaining unit employees effective February 2, 2002, with 3% increases in 2003 and 2004. In addition, the contract provides for participation by bargaining unit employees in the incentive compensation program.
SPPC's current contract with the IBEW Local No. 1245, which represents approximately 63% of SPPC's workforce, was renegotiated in December 2002 and is in effect until December 31, 2005. The three-year contract provides for a 3% general wage increase for bargaining unit employees beginning January 13, 2003, with 3.25% and 3.75% increases in 2004 and 2005, respectively. In addition, the contract provides for participation by bargaining unit employees in the incentive compensation program.
GENERAL - FRANCHISES (NPC AND SPPC)
The Utilities have nonexclusive local franchises or revocable permits to carry on their business in the localities in which their respective operations are conducted in Nevada and California. The franchise and other governmental requirements of some of the cities and counties in which the Utilities operate provide for payments based on gross revenues. During 2001, the state of Nevada also passed a law requiring public utilities to collect from their customers a fee based on consumption. This universal energy charge is to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2002, the Utilities collected $70.8 million in franchise or other fees based on gross revenues. They collected $8.7 million in universal energy charges based on consumption. They also paid and recorded as an expense $0.5 million of fees based on net profits. The Utilities' non-exclusive local franchises or revocable permits are as follows:
(1) Currently attempting to renegotiate.
(2) Water rights and obligations under the franchise agreements were assumed by TMWA in June 2001 upon the sale of SPPC's water business.
(3) As part of the thirty-year Carson City franchise agreement signed in 1982, either side could request that the agreement be renegotiated on the tenth or twentieth anniversaries. Carson City exercised this option in 2002 and a new thirty-year franchise agreement was signed. As part of the agreement, SPPC agreed to be subject to Carson City's Business License Code for utilities, which has a fee of 2.5% of gross electric revenues received from customers within the consolidated municipality of Carson City, which increased by .5%.
The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates.
GENERAL - RESEARCH AND DEVELOPMENT (ALL)
SPR, through its NPC and SPPC subsidiaries, participates in several utility associations, including the Electric Power Research Institute.
SPR has invested in Nth Power Technologies (Nth), a venture capital fund that invests in developing technology companies. Nth has made several investments that may result in SPR strengthening its market position and developing new products and services.
ITEM 2.
ITEM 2. PROPERTIES
The general character of SPR's, NPC's, and SPPC's principal facilities is discussed in Item 1 - Business.
Substantially all of NPC's utility plant is subject to the lien of the Indenture of Mortgage, dated October 1, 1953, and supplemental indentures thereto among NPC and Deutsche Bank Trust Company Americas, securing NPC's outstanding first mortgage bonds.
Additionally, all of NPC's property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between NPC and the Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of the Indenture of Mortgage mentioned above.
Substantially all of SPPC's utility plant is subject to the lien of the Indenture of Mortgage, dated December 1, 1940, and supplemental indentures thereto between SPPC and State Street Bank and Trust, and Gerald R. Wheeler, as trustees, securing SPPC's outstanding first mortgage bonds.
Additionally, all of SPPC's property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between SPPC and the Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of the Indenture of Mortgage mentioned above.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In 2000, Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR, and Touch America (formerly Montana Power), formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line between Salt Lake City, Utah, and Sacramento, California. The conduits included in the line are to be sold to AT&T, PF Net Corporation, and STA. Construction is expected to be completed in the second quarter of 2003. The project sustained significant cost overruns and several complaints and mechanics liens have been filed by several contractors and subcontractors, including Williams Communications LLC, Bayport Pipeline Company, and Mastec North America. In September 2002, SPC conveyed its membership interest in STA to Touch America and obtained an indemnity for any liabilities associated with STA, all in exchange for
title to several fibers in the line and a $35 million promissory note. Several of the mechanics lienors have named SPC as the owner of the project and Bayport Pipeline has suggested it may amend its complaint to name SPC. See Note 9, Long-Term Debt, in Notes to Financial Statements, for additional information.
SPPC owns a 345 kV transmission line that connects SPPC to the facilities of the Bonneville Power Administration (BPA) near Alturas, California. The Transmission Agency of Northern California (TANC) initiated proceedings in the United States District Court for the Eastern District of California and the United States Court of Appeals for the Ninth Circuit, in each case alleging that BPA's construction of a small portion of the Alturas Intertie violated the Northwest Power Preference Act and is requesting an injunction prohibiting operation of the Alturas Intertie. The case before the Eastern District was dismissed for lack of jurisdiction. The case before the Ninth Circuit was dismissed for TANC's failure to prosecute. In December 1999, TANC filed suit in the Superior Court of the State of California, Sacramento County, seeking an injunction against operation of the Alturas Intertie based on numerous allegations under state law, including inverse condemnation, trespass, private nuisance, and conversion. That case was removed to Federal Court and dismissed by the trial court. The dismissal was affirmed by the Ninth Circuit Court of Appeals, and TANC has now filed a writ of certiorari with the United States Supreme Court. Management believes the final outcome of the appeal is not likely to have a material adverse effect on SPPC's financial position or results of operation.
Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings in Item 7). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.
On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposits as ordered. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively, pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. The Utilities are unable to predict the outcome of these
motions. A decision adverse to the Utilities on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.
On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction.
Subsequently, NPC filed a complaint against MSCG on March 26, 2003, in the United States District Court, District of Nevada, alleging that (1) MSCG's demand was wrongful and constituted a breach of the Agreement, (2) MSCG failed to exercise reasonable discretion with respect to its demand, (3) the notice of termination was improperly served and in violation of the Agreement, and (4) MSCG failed to deliver the power as required under the Agreement. NPC is asking for declaratory relief, attorneys' fees and costs of suit and other relief as the Court deems appropriate.
On September 30, 2002, plaintiffs Stephen A. Gordon and Gail M. Gordon filed a lawsuit in the District Court for Clark County, Nevada, seeking class action status for themselves and all shareholders of SPR against SPR and all of its directors for an alleged breach of fiduciary duty in failing to meaningfully evaluate and consider an alleged offer from the Southern Nevada Water Authority (SNWA) to purchase Nevada Power Company. The suit seeks extraordinary relief in the form of an injunction requiring the directors to carefully evaluate and consider such offer, formation of a special stockholders committee to ensure fair and adequate evaluation procedures, and for unspecified damages and/or punitive damages in the event the SNWA withdraws its alleged offer before it can be carefully evaluated. SPR intends to vigorously defend the suit. No answer or responsive pleading has yet been required nor have plaintiffs moved for class certification. On September 30, 2002, plaintiff John Anderson filed a virtually identical lawsuit seeking the same relief. On March 21, 2003, plaintiffs' counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph. The Company believes that the cases are without merit and plans to file motions to dismiss in the second quarter 2003.
On October 21, 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth District Court for Clark County, Nevada, against NPC for fraud and misrepresentation for allegedly overcharging a certain class of customers for energy delivered over the past several years. Plaintiffs allege that NPC fraudulently placed its meters and measured energy delivered at a point prior to passing through transformers during which process a certain amount of energy is dissipated as heat, instead of placing the meters after they pass through the transformer. NPC's motion to dismiss on jurisdictional grounds was denied and NPC is filing a writ before the Nevada Supreme Court, which is being joined in by the PUCN, which agrees with NPC that it has exclusive jurisdiction over the suit. NPC denies that the placement of the meters was fraudulent and alleges that placement of the meters was mandated by either or both customer request or applicable tariff.
On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed and served a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which was consolidated in the Superior Court of the State of California. Plaintiffs in that case seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there is liability, it should spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides demurrers filed by all the defendants.
On May 3, 2002 and July 3, 2002, respectively, Reliant Resources and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002 and July 30, 2002, Reliant Resources and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement
(WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. To date only Idaho has requested mediation of the contracts, which should be completed by the end of second quarter. NPC alleges that Idaho and Reliant Resources were participants in market manipulation in the West and therefore are not entitled to termination payments under the contract.
In August 2002, El Paso Merchant Energy (EPME) terminated contracts for energy it had delivered to NPC under a program that called for delayed payment of the full contract price. In October 2002, EPME asserted a claim against NPC for $19 million in damages representing the approximate amount unpaid under the contracts. NPC alleges that EPME's termination resulted in net payments due to NPC under the WSPP liquidated damages provision as and for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. Both claims are subject to mandatory mediation under the WSPP, but neither party has requested mediation at the present time.
Refer to Regulation and Rate Proceedings in Item 7.
See Environment in Item 1, Business, for information on environmental proceedings.
SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS (SPR)
SPR's Common Stock is traded on the New York Stock Exchange (symbol SRP). The dividends paid per share and high and low sale prices of the Common Stock in the consolidated transaction reporting system in "The Dow Jones News Retrieval Service" for 2002 and 2001 are as follows:
Number of Security Holders:
Dividends are considered periodically by SPR's Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, SPR's financial conditions and other matters within the discretion of the Board. The Board declared the most recent dividend on SPR's Common Stock on February 6, 2002. Since that time, the Board has determined not to pay a dividend on SPR's Common Stock. The Board will continue to review the factors described above on a periodic basis to determine if and when it would be prudent to declare a dividend on SPR's Common Stock. There is no guarantee or assurance that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for SPR and Note 13, Notes to Financial Statements, Dividend Restrictions, for a description of the restrictions on NPC's and SPPC's ability to pay dividends to SPR.
EQUITY COMPENSATION PLAN INFORMATION
(1) SPPC established an Employee Stock Purchase Plan effective June 1, 1963 for the purpose of providing eligible employees with the opportunity to become stockholders of that corporation. In conjunction with SPR becoming the owner of all of SPPC's outstanding common stock, the Plan was amended to reflect that the sponsor of the Plan and the issuer of the stock to be purchased under the Plan would henceforth be SPR. Under SPR's Employee Stock Purchase Plan, eligible employees of SPR and any of its subsidiaries may save regularly by payroll deductions and twice each year use their savings to purchase SPR's Common Stock.
(2) The Executive Long-Term Incentive Plan (the "LTIP") provides for the granting of stock options (both "nonqualified" and "qualified"), stock appreciation rights ("SAR's"), restricted stock performance units, performance shares and bonus stock to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of factors that may affect the future financial condition and results of operations of SPR, NPC, and SPPC.
SIERRA PACIFIC RESOURCES
The July 28, 1999 merger between SPR and NPC was treated for accounting purposes as a reverse acquisition and deemed to have occurred on August 1, 1999. As a result, for financial reporting and accounting purposes, NPC was considered the acquiring entity under Accounting Principles Board Opinion No. 16, Business Combinations, even though SPR became the legal parent of NPC. Because of this accounting treatment, for the year ended December 31, 1999, the table below reflects twelve months of information for NPC and five months of information for SPR and its pre-merger subsidiaries, and for the year ended December 31, 1998, reflects information for NPC only.
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
The table below, for the year ended December 31, 1998, includes information for SPPC's water business disposed of in 2001.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THE INFORMATION IN THIS FORM 10-K INCLUDES FORWARD-LOOKING STATEMENTS WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. THESE FORWARD-LOOKING STATEMENTS RELATE TO ANTICIPATED FINANCIAL PERFORMANCE, MANAGEMENT'S PLANS AND OBJECTIVES FOR FUTURE OPERATIONS, BUSINESS PROSPECTS, OUTCOME OF REGULATORY PROCEEDINGS, MARKET CONDITIONS, AND OTHER MATTERS. WORDS SUCH AS "ANTICIPATE," "BELIEVE," "ESTIMATE," "EXPECT," "INTEND," "PLAN," AND "OBJECTIVE" AND OTHER SIMILAR EXPRESSIONS IDENTIFY THOSE STATEMENTS THAT ARE FORWARD-LOOKING. THESE STATEMENTS ARE BASED ON MANAGEMENT'S BELIEFS AND ASSUMPTIONS AND ON INFORMATION CURRENTLY AVAILABLE TO MANAGEMENT. ACTUAL RESULTS COULD DIFFER MATERIALLY FROM THOSE CONTEMPLATED BY THE FORWARD-LOOKING STATEMENTS. IN ADDITION TO ANY ASSUMPTIONS AND OTHER FACTORS REFERRED TO SPECIFICALLY IN CONNECTION WITH SUCH STATEMENTS, FACTORS THAT COULD CAUSE THE ACTUAL RESULTS OF SIERRA PACIFIC RESOURCES (SPR), NEVADA POWER COMPANY (NPC), OR SIERRA PACIFIC POWER COMPANY (SPPC) TO DIFFER MATERIALLY FROM THOSE CONTEMPLATED IN ANY FORWARD-LOOKING STATEMENT INCLUDE, AMONG OTHERS, THE FOLLOWING:
(1) UNFAVORABLE RULINGS IN RATE CASES PREVIOUSLY FILED, CURRENTLY PENDING AND TO BE FILED BY NPC AND SPPC (THE UTILITIES) WITH THE PUBLIC UTILITIES COMMISSION OF NEVADA (PUCN), INCLUDING THE PERIODIC APPLICATIONS TO RECOVER COSTS FOR FUEL AND PURCHASED POWER THAT HAVE BEEN RECORDED BY THE UTILITIES IN THEIR DEFERRED ENERGY ACCOUNTS, AND DEFERRED NATURAL GAS RECORDED BY SPPC FOR ITS GAS DISTRIBUTION BUSINESS;
(2) THE ABILITY OF SPR, NPC, AND SPPC TO ACCESS THE CAPITAL MARKETS TO SUPPORT THEIR REQUIREMENTS FOR WORKING CAPITAL, INCLUDING AMOUNTS NECESSARY TO FINANCE DEFERRED ENERGY COSTS, CONSTRUCTION COSTS, AND THE REPAYMENT OF MATURING DEBT, PARTICULARLY IN THE EVENT OF ADDITIONAL UNFAVORABLE RULINGS BY THE PUCN, A FURTHER DOWNGRADE OF THE CURRENT DEBT RATINGS OF SPR, NPC, OR SPPC, AND/OR ADVERSE DEVELOPMENTS WITH RESPECT TO NPC'S OR SPPC'S POWER AND FUEL SUPPLIERS;
(3) WHETHER NPC'S ABILITY TO PAY SPR DIVIDENDS WILL BE RESTORED IN THE NEAR FUTURE, AND WHETHER SPPC WILL BE ABLE TO CONTINUE TO PAY SPR DIVIDENDS UNDER THE TERMS OF SPPC'S FINANCING AGREEMENTS AND/OR RESTATED ARTICLES OF INCORPORATION;
(4) WHETHER THE PUCN WILL ISSUE FAVORABLE ORDERS IN A TIMELY MANNER TO PERMIT THE UTILITIES TO BORROW MONEY AND ISSUE ADDITIONAL SECURITIES TO FINANCE THE UTILITIES' OPERATIONS AND TO PURCHASE POWER AND FUEL NECESSARY TO SERVE THEIR RESPECTIVE CUSTOMERS;
(5) WHETHER SUPPLIERS, SUCH AS ENRON, WHICH HAVE TERMINATED THEIR POWER SUPPLY CONTRACTS WITH NPC AND/OR SPPC WILL BE SUCCESSFUL IN PURSUING THEIR CLAIMS AGAINST THE UTILITIES FOR LIQUIDATED DAMAGES UNDER THEIR POWER SUPPLY CONTRACTS, AND WHETHER ENRON WILL BE SUCCESSFUL IN ITS LAWSUIT AGAINST NPC AND SPPC;
(6) WHETHER SPR, NPC, AND SPPC WILL BE ABLE TO MAINTAIN SUFFICIENT STABILITY WITH RESPECT TO THEIR LIQUIDITY AND RELATIONSHIPS WITH SUPPLIERS;
(7) WHETHER CURRENT SUPPLIERS OF PURCHASED POWER, NATURAL GAS, OR FUEL TO NPC OR SPPC WILL CONTINUE TO DO BUSINESS WITH NPC OR SPPC OR WILL TERMINATE THEIR CONTRACTS AND SEEK LIQUIDATED DAMAGES FROM THE RESPECTIVE UTILITY;
(8) WHETHER THE UTILITIES WILL NEED TO PURCHASE ADDITIONAL POWER ON THE SPOT MARKET TO MEET UNANTICIPATED POWER DEMANDS (FOR EXAMPLE, DUE TO UNSEASONABLY HOT WEATHER) AND WHETHER
SUPPLIERS WILL BE WILLING TO SELL SUCH POWER TO THE UTILITIES IN LIGHT OF THEIR WEAKENED FINANCIAL CONDITION;
(9) WHETHER SPPC WILL BE ABLE TO MAKE THE GASIFIER FACILITY AT THE PINON PINE POWER PROJECT OPERATIONAL AND, IN ANY EVENT, WHETHER SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER THE COSTS OF THE GASIFIER IN A FUTURE GENERAL RATE CASE;
(10) WHETHER NPC AND SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER GOODWILL AND OTHER MERGER COSTS RECORDED IN CONNECTION WITH THE 1999 MERGER BETWEEN SPR AND NPC IN A FUTURE GENERAL RATE CASE;
(11) WHOLESALE MARKET CONDITIONS, INCLUDING AVAILABILITY OF POWER ON THE SPOT MARKET, WHICH AFFECT THE PRICES THE UTILITIES HAVE TO PAY FOR POWER AS WELL AS THE PRICES AT WHICH THE UTILITIES CAN SELL ANY EXCESS POWER;
(12) THE OUTCOME OF THE UTILITIES' PENDING LAWSUITS IN NEVADA STATE COURT SEEKING TO REVERSE PORTIONS OF THE PUCN'S ORDERS DENYING THE RECOVERY OF DEFERRED ENERGY COSTS, INCLUDING THE OUTCOME OF PETITIONS FILED BY THE BUREAU OF CONSUMER PROTECTION OF THE NEVADA ATTORNEY GENERAL'S OFFICE SEEKING ADDITIONAL DISALLOWANCES;
(13) WHETHER THE UTILITIES WILL BE ABLE, EITHER THROUGH FEDERAL ENERGY REGULATORY COMMISSION (FERC) PROCEEDINGS OR NEGOTIATION, TO OBTAIN LOWER PRICES ON THEIR LONGER-TERM PURCHASED POWER CONTRACTS ENTERED INTO DURING 2000 AND 2001 THAT ARE PRICED ABOVE CURRENT MARKET PRICES FOR ELECTRICITY;
(14) THE EFFECT THAT ANY FUTURE TERRORIST ATTACKS, WARS OR THREATS OF WAR MAY HAVE ON THE TOURISM AND GAMING INDUSTRIES IN NEVADA, PARTICULARLY IN LAS VEGAS, AS WELL AS ON THE ECONOMY IN GENERAL;
(15) UNSEASONABLE WEATHER AND OTHER NATURAL PHENOMENA, WHICH CAN HAVE POTENTIALLY SERIOUS IMPACTS ON THE UTILITIES' ABILITY TO PROCURE ADEQUATE SUPPLIES OF FUEL OR PURCHASED POWER TO SERVE THEIR RESPECTIVE CUSTOMERS AND ON THE COST OF PROCURING SUCH SUPPLIES;
(16) INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL GROWTH IN THE SERVICE TERRITORIES OF THE UTILITIES;
(17) THE LOSS OF ANY SIGNIFICANT CUSTOMERS;
(18) THE EFFECT OF EXISTING OR FUTURE NEVADA, CALIFORNIA, OR FEDERAL LEGISLATION OR REGULATIONS AFFECTING ELECTRIC INDUSTRY RESTRUCTURING, INCLUDING LAWS OR REGULATIONS WHICH COULD ALLOW ADDITIONAL CUSTOMERS TO CHOOSE NEW ELECTRICITY SUPPLIERS OR CHANGE THE CONDITIONS UNDER WHICH THEY MAY DO SO;
(19) CHANGES IN THE BUSINESS OF MAJOR CUSTOMERS, INCLUDING THOSE ENGAGED IN GOLD MINING OR GAMING, WHICH MAY RESULT IN CHANGES IN THE DEMAND FOR SERVICES OF THE UTILITIES, INCLUDING THE EFFECT ON THE NEVADA GAMING INDUSTRY OF THE OPENING OF ADDITIONAL INDIAN GAMING ESTABLISHMENTS IN CALIFORNIA AND OTHER STATES;
(20) CHANGES IN ENVIRONMENTAL REGULATIONS, TAX, OR ACCOUNTING MATTERS OR OTHER LAWS AND REGULATIONS TO WHICH THE UTILITIES ARE SUBJECT;
(21) FUTURE ECONOMIC CONDITIONS, INCLUDING INFLATION OR DEFLATION RATES AND MONETARY POLICY;
(22) FINANCIAL MARKET CONDITIONS, INCLUDING CHANGES IN AVAILABILITY OF CAPITAL OR INTEREST RATE FLUCTUATIONS;
(23) UNUSUAL OR UNANTICIPATED CHANGES IN NORMAL BUSINESS OPERATIONS, INCLUDING UNUSUAL MAINTENANCE OR REPAIRS; AND
(24) EMPLOYEE WORKFORCE FACTORS, INCLUDING CHANGES IN COLLECTIVE BARGAINING UNIT AGREEMENTS, STRIKES, OR WORK STOPPAGES.
OTHER FACTORS AND ASSUMPTIONS NOT IDENTIFIED ABOVE MAY ALSO HAVE BEEN INVOLVED IN DERIVING THESE FORWARD-LOOKING STATEMENTS, AND THE FAILURE OF THOSE OTHER ASSUMPTIONS TO BE REALIZED, AS WELL AS OTHER FACTORS, MAY ALSO CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED. SPR, NPC, AND SPPC ASSUME NO OBLIGATION TO UPDATE FORWARD-LOOKING STATEMENTS TO REFLECT ACTUAL RESULTS, CHANGES IN ASSUMPTIONS, OR CHANGES IN OTHER FACTORS AFFECTING FORWARD-LOOKING STATEMENTS.
CRITICAL ACCOUNTING POLICIES
The following items represent critical accounting policies that under different conditions or using different assumptions could have a material effect on the financial condition, liquidity and capital resources of SPR and the Utilities:
REGULATORY ACCOUNTING
The Utilities' rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the California Public Utility Commission (CPUC) and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers.
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1 in Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge or expensed in current period earnings.
Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, Accounting for Generation Divestiture Costs, Impairment of Long-Lived Assets, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below.
DEFERRED ENERGY ACCOUNTING
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369). The provisions of AB 369, which are described in greater detail in Regulation and Rate Proceedings, later, include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances.
The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity as well as changes in fuel costs incurred to generate electricity. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies, and Commodity Price Risk in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for a discussion of the Utilities' commodity risk management program. As discussed above, deferred energy accounting facilitates the recovery of costs incurred to procure fuel and purchased power for SPPC and NPC.
As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Nevada Power Company 2001 Deferred Energy Case, on November 30, 2001, NPC filed an application with the PUCN seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, disallowing $434 million of deferred purchased fuel and power costs, and allowing NPC to collect the remaining $478 million over three years beginning April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges, the two major national rating agencies immediately downgraded the credit rating on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April), and the market price of SPR's common stock fell substantially.
As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, SPPC filed an application with the PUCN seeking to establish a DEAA rate to clear its deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. On May 28, 2002, the PUCN issued its decision on SPPC's deferred energy application, disallowing $53 million of deferred purchased fuel and power costs, and allowing SPPC to collect the remaining $150 million over three years beginning June 1, 2002. As a result of this decision, SPPC wrote off $58 million of disallowed deferred energy costs and related carrying charges.
Both Utilities have continued to be entitled under AB 369 to utilize deferred energy accounting for their electric operations. Because of contracts entered into during the Western energy crisis in 2001 to assure adequate supplies of electricity for their customers, the Utilities incurred fuel and purchased power costs in excess of amounts they were permitted to recover in current rates. As a result, during 2002 both Utilities continued to record additional amounts in their deferral of energy costs accounts.
On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.
Intervenors filed their direct testimony on March 7, 2003 calling for disallowances between approximately $83 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Some Intervenors' testimony, in the current case, argue in favor of this disallowance based on the last Deferred order but did not quantify their proposals and in some cases would be additive to the ranges stated above. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue.
While all Intervenors call for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period.
On January 14, 2003, SPPC filed an application with the PUCN seeking to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.
A significant disallowance in either or both of these deferred energy rate cases or in future cases to be filed by either Utility would have a material adverse affect on the future financial position, results of operations, and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. See Regulation and Rate Proceedings, later, for additional discussion of the regulatory process underway to recover these deferred costs.
If not for deferred energy accounting during 2001 and 2002, SPR's, NPC's and SPPC's results of operations, financial condition, liquidity and capital resources would have been materially adversely affected. For example, without the current deferrals permitted by the deferred energy accounting provisions of AB 369, the reported net losses of SPR, NPC, and SPPC for 2002 of ($307.5) million, ($235.1) million, and ($17.9) million would have been (net of income tax) reported as net losses (including the write-offs resulting from the disallowances discussed above) of ($495.9) million, ($379.7) million and ($61.6) million, respectively. Similarly, without the deferred energy accounting provisions of AB 369, the 2001 reported net income of SPR, NPC and SPPC of $56.7 million, $63.4 million and $45.9 million would have been (net of income tax) reported as net losses of ($715.4) million, ($573.6) million and ($89.1) million, respectively.
ACCOUNTING FOR GOODWILL AND MERGER COSTS
The order issued by the PUCN in December 1998 approving the merger of SPR and NPC directed both NPC and SPPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order specifically directed both Utilities to defer merger transaction costs, transition costs and goodwill costs for
a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings.
Costs deferred as a result of the PUCN order were $331.2 million of goodwill and $62.2 million in other merger costs as of December 31, 2002. The deferred other merger costs consist of $40.5 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains.
On October 1, 2001, and November 30, 2001, NPC and SPPC, respectively, filed applications with the PUCN for general rate increases that included, among other items, requests to recover deferred merger costs, including goodwill. In its decisions dated March 27, 2002, and May 28, 2002, for NPC and SPPC, respectively the PUCN decided not to make any determination on the recovery of merger costs until general rate cases are filed with test years ending on or after December 31, 2002. However, the PUCN did instruct the Utilities to continue to recognize these costs as deferred assets without carrying charges.
The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases that are required to be filed in 2003. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial condition, results of operations and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy.
ACCOUNTING FOR GENERATION DIVESTITURE COSTS
As a condition to its approval of the merger between SPR and NPC, the Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture Plan stipulation for the sale of the Utilities' generation assets. In May 2000 an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000, the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an exemption to AB 6 that would allow SPPC to complete the sale of the hydroelectric units to TMWA subject to review and approval of the sale by the CPUC.
The sales agreements for the six bundles provided that they terminate eighteen months after their execution, and all of the agreements have now terminated in accordance with their respective provisions. As of December 31, 2002, NPC and SPPC had incurred costs of approximately $20.1 million and $12.2 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001 each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002 the PUCN delayed recovery of divestiture costs to future rate case requests but did grant a carrying charge
on the costs until such time as recovery is allowed. To the extent that the Utilities are not permitted to recover any portion of these costs in future rates, the disallowed costs and related carrying charges would be required to be written off in current period earnings.
IMPAIRMENT OF LONG-LIVED ASSETS
SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist.
As discussed in more detail in Note 21 of Notes to Financial Statements, Pinon Pine, SPPC owns a combined cycle generation facility, a post-gasification facility, and, through its wholly owned subsidiaries, owns a gasifier that are collectively referred to as the Pinon Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in June 1998. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $100 million as of December 31, 2002.
To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001 SPPC retained an independent engineering consulting firm to complete a comprehensive study of the Pinon Pine gasification plant. SPPC received a final report of the study in November 2002. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC's and SPR's financial condition and results of operations.
ACCOUNTING FOR DERIVATIVES AND HEDGING ACTIVITIES
Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge.
In order to manage loads, resources and energy price risk, the Utilities buy fuel and power under forward contracts. In addition to forward fuel and power purchase contracts, the Utilities also use options and swaps to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133. The risk management assets and liabilities recorded in the balance sheets of the Utilities and SPR are primarily comprised of the fair value of these forward fuel and power purchase contracts and other energy related derivative instruments.
Fuel and purchased power costs are subject to deferred energy accounting. Accordingly, the energy related risk management assets and liabilities and the corresponding unrealized gains and losses (changes in fair value) are offset with a regulatory asset or liability rather than recognized in the statements of operations and comprehensive income. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized if they are currently recoverable or deferred if they are recoverable or payable through future rates.
The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model which incorporates assumptions such as the underlying commodity's forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments.
At December 31, 2002, the fair value of the derivatives resulted in the recording of $30 million, $29 million, and $1 million in risk management assets and $74 million, $30 million, and $44 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. Net risk management regulatory assets of $45 million, $2 million, and $44 million were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively at December 31, 2002.
SPR and the Utilities have other non-energy related derivative instruments such as interest rate swaps. The transition adjustment related to these types of derivative instruments resulting from the adoption of SFAS No. 133 was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income. Additionally, the changes in fair values of these non-energy related derivatives are also reported in Other comprehensive income until the related transactions are settled or terminate, at which time the amounts are reclassified into earnings. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003, of which $7.3 million was reclassified into earnings during the twelve-month period ended December 31, 2002.
ENVIRONMENTAL CONTINGENCIES
SPR and its subsidiaries are subject to federal, state and local regulations governing air and water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air and water quality, solid, and hazardous and toxic waste.
SPR and its subsidiaries are subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating, and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with laws relating to power plant emissions. In addition, SPR or its subsidiaries may be a responsible party for environmental clean up at a site identified by a regulatory body. The management of SPR and its subsidiaries cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. SPR and its subsidiaries accrue for environmental costs only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs.
Note 17 of Notes to Financial Statements, Commitments and Contingencies, discusses the environmental matters of SPR and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which SPR or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of SPR and its subsidiaries.
LITIGATION CONTINGENCIES
Note 17 of Notes to Financial Statements, Commitments and Contingencies, discusses the significant legal matters of SPR and its subsidiaries. SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have, a significant impact on its financial position or results of operations.
DEFINED BENEFIT PLANS AND OTHER POSTRETIREMENT PLANS
As further explained in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR maintains a pension plan as well as other postretirement benefit plans that provide health and life insurance for retired employees. All employees are eligible for these benefits if they reach retirement age while still working for SPR or its subsidiaries. These costs are determined in accordance with the provisions of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and ultimately collected in rates billed to customers. The amounts funded are then used to meet benefit payments to plan participants. SPR contributed $41.1 million and $13.8 million to its pension plan, and $0.2 million and $0.7 million to the other postretirement benefits plan in 2002 and 2001, respectively. Due to the sharp decline in United States equity markets since the third quarter of 2000, the value of a significant portion of the assets held in the plans' trusts to satisfy the obligations of the plans has decreased significantly. As a result, additional contributions may be required in the future to meet the requirements of the plan to pay benefits to plan participants.
PENSION PLANS
SPR's reported costs of providing non-contributory defined pension benefits (described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
For example, pension costs are impacted by actual employee demographics (including age and employment periods), the level of contributions SPR makes to the plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
In accordance with SFAS No. 87, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. For the twelve months ended December 31, 2002, 2001, and 2000, SPR recorded pension benefit expense of approximately $22.5 million, $14.2 million, and $12.5 million, respectively, in accordance with the provisions of SFAS No. 87. Actual payments of benefits made to retirees for the twelve months ended September 30, 2002 and 2001, were $30.0 million and $36.4 million, respectively.
SPR has made no changes to pension plan provisions in 2002, 2001, and 2000 that have had any significant impact on recorded pension amounts. As further described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR has revised the discount rate in 2002 as compared to 2001 and 2000. This change did not have a significant impact on reported pension costs in 2002.
SPR's pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased
pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected benefit obligation (PrBO) and the reported annual pension cost on the income statement (PeC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by the Moody's Investors Service, Inc. (Moody's) Aa composite bond index.
In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Plan assets earned $51.1 million in 2000 and lost $39.3 million and $23.1 million in 2001 and 2002, respectively.
As a result of SPR's plan asset returns at September 30, 2002, SPR was required to recognize an additional minimum liability in the amount of $89.6 million, as prescribed by SFAS No. 87. The liability was recorded as a reduction to common equity through a charge to Accumulated Other Comprehensive Income, and did not affect net income for 2002. The charge to Accumulated Other Comprehensive Income will be restored through common equity in future periods to the extent fair value of trust assets exceeds the accumulated benefit obligation.
Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.
OTHER POSTRETIREMENT BENEFITS
SPR's reported costs of providing other postretirement benefits (described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
For example, other postretirement benefit costs are impacted by actual employee demographics (including age and employment periods), the level of contributions made to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plan may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs.
For the twelve months ended December 31, 2002, 2001, and 2000, SPR recorded other postretirement benefit expense of approximately $3.1 million, $2.5 million, and $2.6 million, respectively, in accordance with
the provisions of SFAS No. 106. Actual payments of benefits made to retirees for the twelve months ended September 30, 2002, and 2001, were $6.9 million and $4.6 million, respectively.
SPR has made no changes to other postretirement benefit plan provisions in 2002, 2001, and 2000 that have had any significant impact on recorded benefit plan amounts. As further described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR has revised the discount rate in 2002 as compared to 2001 and 2000. This change did not have a significant impact on reported other postretirement benefit costs in 2002. However, in determining the other postretirement benefit obligation and related cost, these assumptions can change from period to period, and such changes could result in material changes to such amounts.
SPR's other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded other postretirement benefit costs.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected accumulated other postretirement benefit obligation (APBO) and the reported annual other postretirement benefit cost on the income statement (PBC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by Moody's Aa composite bond index.
In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of the SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Plan assets increased in value $17.3 million in 2000 and lost $15.8 million and $6.8 million in 2001 and 2002, respectively.
Also, other postretirement benefit cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.
COST CAPITALIZATION POLICIES
The Utilities continue to devote substantial resources in 2003 on the Centennial Transmission project at NPC and the Falcon to Gonder Transmission project at SPPC. In addition, certain operating units of the Utilities are charged with maintaining, repairing and replacing components of generation, transmission and distribution systems both on a scheduled basis and on an as-needed basis. As described in Note 1 of Notes to
Financial Statements, Summary of Significant Accounting Policies, the cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed or retired, their cost, plus removal or disposal costs less salvage, is charged to accumulated depreciation. Certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity as prescribed by Generally Accepted Accounting Principles (GAAP) and the FERC's Uniform System of Accounts.
The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC). The level of indirect construction overhead costs capitalized by the Utilities is based upon real-time construction activity. Accordingly, payroll and other costs capitalized will fluctuate based upon seasonal construction activities and the deployment of resources to those efforts. During periods of higher maintenance levels, these payroll and other costs will not be capitalized. As such, operating income could be impacted by the manner in which payroll and related costs are deployed. However, the total cash flow of the Utilities is not impacted by the allocation of these costs to various construction or maintenance activities.
In 2002, the Utilities capitalized approximately $5.2 million of AFUDC as a result of construction activity financed primarily by their debt. This amount is a non-cash component reflected in the Consolidated Statements of Operations and has no impact on the operating cash flow. Recognition of AFUDC as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices permit the Utility to earn a fair return on, and recover in rates, all capital costs charged for Utility services.
DEPRECIATION EXPENSE
The Utilities have a significant investment in electric plant. SPPC also has an investment in gas distribution plant. Depreciable assets of generation, transmission and distribution operations represent approximately 92% of the Utilities' investment in utility plant. As described in Note 1 to Notes to Financial Statements, Summary of Significant Accounting Policies, the Utilities depreciate these assets utilizing a composite rate, which currently includes a component for net negative salvage. These assets are depreciated on a straight-line basis over the remaining useful life of the related assets, which approximates the anticipated physical lives of these assets in most cases. The Nevada Administrative Code requires the Utilities to provide a depreciation study every four years in order to substantiate the remaining physical lives of their investment in utility plant. Adjustments to the estimated depreciable lives of the Utilities' plant are recorded on a prospective basis, as prescribed by GAAP and the FERC's Uniform System of Accounts.
Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC and, in the case of SPPC, the CPUC, which also approves any changes the Utilities may make to depreciation rates utilized for this property. Because the Utilities' periodic depreciation expense is included as a component of the revenue requirement utilized in the development of the Utilities' tariff rates, revenue reflects collection of the recognized depreciation expense. Accordingly, the impact of depreciation on net income is not significant. However, operating cash flows are positively affected by the amount of depreciation collected in rates, since depreciation expense is not a current cash outlay for the Utilities.
ASSET RETIREMENT OBLIGATIONS
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities
due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003.
Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost.
Management's methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and, mass asset properties that are replaced or retired frequently would be considered normal maintenance.
Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Management has determined that the present value of NPC's Navajo Asset Retirement Obligation will not have a material effect on the financial position or results of operations of SPR or NPC. SPPC has no significant asset retirement obligations.
The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems.
STOCK COMPENSATION PLANS
In December 2002, the FASB released SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. Pursuant to those updated disclosure requirements, SPR has included the following discussion on the stock compensation plans. For additional information on SPR's stock compensation plans, see Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies, and Note 15, Stock Compensation Plans.
At December 31, 2002, SPR had several stock-based compensation plans. SPR applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. SPR has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock Based Compensation, and its related amendment(s). Had compensation cost for SPR's nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the provisions of SFAS No. 123, SPR's income applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):
UNBILLED RECEIVABLES
Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities' current tariffs. Customer accounts receivable as of December 31, 2002, include unbilled receivables of $60 million and $63 million for NPC and SPPC, respectively. Customer accounts receivable as of December 31, 2001, include unbilled receivables of $49 million and $63 million for NPC and SPPC, respectively.
PROVISION FOR UNCOLLECTIBLE ACCOUNTS
The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The adequacy of these reserves will vary to the extent that future collections differ from past experience.
MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS
As discussed in the results of operations sections that follow, operating results for the year ended December 31, 2002, were severely affected by the PUCN's March 29, 2002, decision in NPC's deferred energy
rate case to disallow $434 million of deferred purchased fuel and power costs. The PUCN concluded that NPC was imprudent in entering into certain transactions and also imprudent in not entering into other transactions: in particular, that NPC should have purchased 25% of its projected 2001 load in 1999 when prices were lower, and that it purchased 3% too much supply for summer 2001 and should have sold the excess at an earlier date. NPC has appealed this decision to the First Judicial District Court of Nevada. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. As a result of this disallowance, NPC wrote off approximately $465 million of deferred energy costs and related carrying charges. In addition, the decision of the PUCN on May 28, 2002, in SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001, had a significant negative impact on the results of operations of SPR and SPPC for the year ended December 31, 2002. The PUCN concluded that SPPC was imprudent for buying too much power for summer 2001, and for failing to buy 33% of its total summer 2001 supplies on an index price instead of a firm price. SPPC has appealed this decision to the First Judicial District Court of Nevada and arguments are scheduled to be heard in October 2003. As a result of this disallowance, SPPC wrote off approximately $58 million of deferred energy costs and related carrying charges. The discussion below provides the context in which these decisions were made.
In an effort to mitigate the effects of higher fuel and purchased power costs that developed in the western United States in 2000, the Utilities entered into the Global Settlement with the PUCN in July 2000 which established a mechanism that initiated incremental rate increases for each Utility. Cumulative electric rate increases under the Global Settlement were $127 million and $65 million per year for NPC and SPPC, respectively.
However, because the rate adjustment mechanism of the Global Settlement was subject to certain caps and could not keep pace with the continued escalation of fuel and purchased power prices, on January 29, 2001, the Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN. The CEP included a request for emergency rate increases (CEP Riders). On March 1, 2001, the PUCN permitted the requested CEP Riders to go into effect subject to later review. The CEP Riders provided further rate increases of $210 million and $104 million per year, respectively, for NPC and SPPC.
Notwithstanding the increases under the Global Settlement and the CEP Riders, the Utilities' revenues for fuel and purchased power recovery continued to be less than the related expenses. Accordingly, the Utilities sought additional relief pursuant to legislation.
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369). The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities until July 2003, the repeal of electric industry restructuring, and beginning March 1, 2001, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. The stated purposes of this emergency legislation included, among others, to control volatility in the price of electricity in the retail market in Nevada and to ensure that the Utilities had the necessary financial resources to provide adequate and reliable electric service under the then present market conditions.
As discussed above in Critical Accounting Policies, deferred energy accounting allows the Utilities an opportunity to recover in future periods that portion of their costs for fuel and purchased power not recovered by current rates and defers to future periods the expense associated with the amounts by which fuel and purchased power costs exceed the costs to be recovered in current rates. Recovery is subject to PUCN review as to prudency and other matters.
AB 369 requires each Utility to file general rate applications and deferred energy applications with the PUCN by specific dates. On November 30, 2001, NPC filed a deferred energy application seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear purchased fuel and power costs of $922 million accumulated between March 1, 2001, and September 30, 2001, and to spread the cost recovery
over a period of not more than three years. On February 1, 2002, SPPC filed a deferred energy application seeking to establish a DEAA rate to clear purchased fuel and power costs of $205 million accumulated between March 1, 2001, and November 30, 2001, and to spread the cost recovery over a period of not more than three years. See Regulation and Rate Proceedings, later, for a discussion of the Utilities' general rate case filings and decisions.
The March 29, 2002, decision of the PUCN on NPC's deferred energy rate case to disallow $434 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, had a significant negative impact on the results of operations of SPR and NPC for the year ended December 31, 2002. The PUCN's decision also caused the two major national rating agencies to issue immediate downgrades of the credit ratings on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April). Following those events, the market price of SPR's common stock fell substantially; NPC and SPPC were obliged within five business days of the downgrades to issue general and refunding mortgage bonds to secure their bank lines of credit; NPC was obliged to obtain a waiver and amendment from its credit facility banks before it was permitted to draw down on the facility; NPC and SPPC were no longer able to issue commercial paper; a number of NPC's power suppliers contacted NPC regarding its ability to pay the purchase price of outstanding contracts; and several power suppliers, including a subsidiary of Enron Corp., terminated their power supply agreements with one or both of the Utilities. As discussed later under Regulation and Rate Proceedings, the PUCN's March 29, 2002, decision on NPC's deferred energy application is being challenged by NPC in a lawsuit filed in the First District Court of Nevada. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances.
The May 28, 2002, decision of the PUCN on SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001, also had a significant negative impact on the results of operations of SPR and SPPC for the year ended December 31, 2002. The PUCN's decision on SPPC's deferred energy application is being challenged by SPPC in a lawsuit filed August 22, 2002, in Nevada state court, which is discussed later under Regulation and Rate Proceedings, and arguments are scheduled to be heard in October 2003. The BCP of the Nevada Attorney General's Office has since filed a petition in SPPC's state action seeking additional disallowances.
On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On January 14, 2003, SPPC filed an application with the PUCN seeking to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. See "Critical Accounting Policies--Deferred Energy Accounting" above for more detail.
A significant disallowance in either or both of these deferred energy rate cases or in future cases to be filed by either Utility could further weaken the financial condition, liquidity, and capital resources of SPR, NPC, and SPPC. In particular, such a decision or decisions could cause further downgrades of debt securities by the rating agencies, could make it impracticable to access the capital markets, and could cause additional power suppliers to terminate purchased power contracts and seek liquidated damages. Under such circumstances, it could be difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy.
SIERRA PACIFIC RESOURCES
RESULTS OF OPERATIONS
SPR incurred a net loss of ($307.5) million for the year ended December 31, 2002, compared to net income of $56.7 million in 2001, and a net loss of ($39.8) million in 2000. SPR's operating results for 2002 reflect the write-off of $527 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's decisions in NPC's and SPPC's deferred energy rate cases to disallow $434 million and $57 million, respectively, of deferred purchased power, fuel, and gas costs.
On March 15, 2002, SPR paid $20.6 million in common stock dividends. NPC declared and paid a common stock dividend of $10 million to its parent, SPR, in the first quarter of 2002. During 2002 SPPC paid common stock dividends of $44.9 million to its parent, SPR, and $3.9 million in dividends to holders of its preferred stock. NPC and SPPC each received a capital contribution of $10 million from SPR in March 2002.
ANALYSIS OF CASH FLOWS
SPR's consolidated net cash flows improved in 2002 compared to 2001, resulting from an increase in cash flows from operating activities offset in part by decreases in cash flows from investing and financing activities. Although SPR recorded a net loss during 2002, compared to net income in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs at the utilities for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Also, cash flows from operating activities in the current year reflect the receipt of an income tax refund. Cash flows from investing activities decreased in 2002 because 2001 investing activities included cash provided from the sale of the assets of SPPC's water business. Also, cash flows from investing activities decreased because of additional cash utilized for construction activities during 2002 compared to 2001. Cash flows from financing activities were lower in 2002 because of decreases in net long-term debt issued, decreases in short-term borrowings and reduced proceeds from the sale of common stock.
SPR's consolidated net cash flows during 2001 were comparable to 2000. An increase in net cash flows used for operating activities was offset by a decrease in cash used for investing activities and an increase in cash provided from financing activities. The increase in cash used in operating activities resulted substantially from the payment of higher energy and natural gas costs. The decrease in cash used for investing activities resulted from the sale of SPPC's water business. The increase in cash provided from financing activities resulted from a reduction in net retirements of short-term debt and proceeds from the sale of common stock. Cash provided by financing activities was substantially utilized for the payment of higher energy costs in 2001. See Note 7, Common Stock and Other Paid-in Capital and Note 12 Short-Term Borrowings, of Notes to Financial Statements for detailed financing information.
LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)
SPR, on a stand-alone basis, had cash and cash equivalents of approximately $1.5 million at December 31, 2002, and approximately $179.3 million at February 28, 2003.
SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and the restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult for SPR to operate outside of bankruptcy.
DIVIDENDS FROM SUBSIDIARIES
Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below.
o NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $237 million as of December 31, 2002), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. There can be no assurance that any such consent could be obtained or that any first mortgage bonds could be redeemed prior to their stated maturity. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock, although other restrictions set forth below would limit the amount of any such repurchases or redemptions.
o NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's Premium Income Equity Securities (PIES)) provided that:
o those payments do not exceed $60 million for any one calendar year,
o those payments comply with any regulatory restrictions then applicable to NPC, and
o the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1.
The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment:
o there are no defaults or events of default with respect to the Series E Notes,
o NPC has a ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the payment date of at least 2.0 to 1, and
o the total amount of such dividends is less than:
o the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus
o 100% of NPC's aggregate net cash proceeds from contributions to its common equity capital or the issuance or sale of certain equity or convertible debt securities of NPC, plus
o the lesser of cash return of capital or the initial amount of certain restricted investments, plus
o the fair market value of NPC's investment in certain subsidiaries.
If NPC's Series E Notes are upgraded to investment grade by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc. (S&P), these restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.
o On October 29, 2002, NPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on payments in respect of common stock by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above.
o The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%.
o The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures.
o SPPC's Term Loan Agreement dated October 30, 2002, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of:
o 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus
o the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.
o On October 29, 2002, SPPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above.
o SPPC's Articles of Incorporation contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of
common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock.
o The Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends.
Management intends to seek a modification of the financial covenant, contained in NPC's first mortgage indenture, in the near future. The regulatory limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction.
EFFECTS OF RATE CASE DECISIONS
On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured debt ratings of SPR, NPC and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities' secured debt ratings were downgraded to below investment grade. The downgrades affected SPR's, NPC's and SPPC's liquidity primarily in two principal areas: (1) their respective financing arrangements, and (2) NPC's and SPPC's contracts for fuel, for purchase and sale of electricity and for transportation of natural gas.
Credit Facility. As a result of the ratings downgrades, SPR's ability to access the capital markets to raise funds was severely limited. On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility as a condition to the banks agreeing to an amendment of NPC's former $200 million unsecured revolving credit facility that permitted NPC to draw down funds under that facility. See NPC, Liquidity and Capital Resources, for more information.
Power Supplier Issues. With respect to NPC's and SPPC's contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that NPC and SPPC are required to use as members of the WSPP. The WSPP contract is posted on the WSPP website. These contracts provide that a material adverse change may give rise to a right to request collateral, which, if not provided within 3 business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within 3 business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of February 28, 2003, for all suppliers continuing to provide power under a WSPP agreement was an approximate $17.0 million benefit for NPC and an approximate $7.8 million payment for SPPC.
Following the PUCN decisions, a number of power suppliers requested collateral from the Utilities. On April 4, 2002, the Utilities sent a letter to their suppliers advising them that, assuming the Utilities could access the capital markets for secured debt and no other significant negative developments occurred, the Utilities
expected to be able to honor their obligations under the power supply contracts. However, the Utilities noted that a simultaneous call for 100% mark-to-market collateral in the short-term would likely not be met. On April 24, 2002, the Utilities met with representatives of various suppliers to discuss SPR's and the Utilities' financial situation and plans, and indicated that they intended to propose extended payment terms for the above-market portions of NPC's existing power contracts. Such extended payment terms were proposed to NPC's suppliers in a letter dated May 2, 2002, in which NPC proposed paying less than contract prices, but more than market prices plus interest, for the period May 1 to September 15, 2002, and paying any balances remaining prior to December 2003. NPC also agreed to extend the suppliers' rights under the WSPP agreement. As of October 29, 2002, NPC paid all remaining outstanding balances owed to its continuing suppliers.
In early May of 2002, Enron Power Marketing Inc. (Enron), Morgan Stanley Capital Group Inc. (MSCG), Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC and SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon the Utilities' alleged failure to provide adequate assurance of their performance under the WSPP agreement to any of their suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, claims for liquidated damages against the Utilities under the terminated power supply contracts.
Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.
On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposits as ordered. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively, pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. The Utilities are unable to predict the outcome of the motions. A decision adverse to the Utilities on Enron's motion for
partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity and could make it difficult to continue to operate outside of bankruptcy.
On June 10, 2002, Duke Energy Trading and Marketing (Duke) entered into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill the Utilities' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002, Duke was paid the full amount of the deferred payments.
On September 5, 2002, MSCG initiated an arbitration pursuant to the arbitration provisions in various power supply contract terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction.
On September 30, 2002, El Paso Merchant Energy Group (EPME) notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million that was owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC.
Gas Supplier Issues. With respect to the purchase and sale of natural gas, NPC and SPPC use several types of contracts. Standard industry sponsored agreements include:
o the Gas Industry Standards Board (GISB) agreement which is used for physical gas transactions,
o the North American Energy Standards Board (NAESB) agreement which is used for physical gas transactions,
o the Gas EDI Base Contract for Short Term Sale and Purchase of Natural Gas which is also used for physical gas transactions,
o the International Swap Dealers Association (ISDA) agreement which is used for financial gas transactions.
Alternatively, the gas transactions might be governed by a non-standard bilateral master agreement negotiated between the parties, or by the confirmation associated with the transaction. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes.
Gas transmission services are provided under the FERC Gas Tariff or a custom agreement. These contracts require the entities to establish and maintain creditworthiness to obtain service. These contracts are
subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. To date, a letter of credit has been provided to one of SPPC's gas suppliers.
Construction Projects. In response to the decisions by the PUCN in NPC's rate cases, SPR implemented certain measures that positively impacted cash flow by $101.4 million in 2002. Two major transmission construction projects, the Centennial Plan and the Falcon to Gonder Project, were delayed for a total 2002 capital preservation impact of $71.9 million. The delay in NPC's Centennial Plan had an impact of $38.4 million and the delay of SPPC's Falcon to Gonder Project had an impact of $33.5 million. An additional $29.5 million was reduced from the Utilities' 2002 capital budgets by curtailing or delaying other projects.
FEDERAL TAX REFUND
In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The remaining income tax losses of $281.9 million as of December 31, 2002 may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income. The carryforward period for net operating losses incurred is 20 years, and as such the losses incurred in the years ended December 31, 2000, 2001, and 2002 will expire in 2020, 2021, and 2022, respectively.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, NPC and SPPC established accounts receivable purchase facilities of up to $125 million and $75 million, respectively, which expire on August 28, 2003 unless either NPC or SPPC has activated its respective facility before that date, in which case such facility will be automatically extended to, and will expire on, October 28, 2003. If NPC or SPPC elect to activate their receivables purchase facilities, they will sell all of their accounts receivable generated from the sale of electricity and natural gas to customers to their newly created bankruptcy remote special purpose subsidiaries. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiaries will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facilities contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, each Utilities' receivables purchase facility may terminate in the event that the Utility or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for the Utility and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, each Utility's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of the Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain obligations as sellers and servicers under the receivables purchase facilities. NPC and SPPC intend to use their accounts receivables purchase facilities as back-up liquidity facilities and do not plan to activate these facilities in the foreseeable future.
CROSS DEFAULT PROVISIONS
Certain financing agreements of SPR and the Utilities contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of
SPR and the Utilities to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPR or the Utilities may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPR's and the Utilities' various financing agreements are briefly summarized below:
o The indenture pursuant to which SPR issued its 7.25% Convertible Notes due 2010 provides for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable;
o NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs;
o The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders;
o NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively;
o SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs;
o SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and
o SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively.
PENSION PLAN MATTERS
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, SPR and the Utilities contributed a total of $24 million to meet their funding obligations under the plan. At the present time, SPR and the Utilities do not expect that any near term funding obligation will have a material adverse effect on their liquidity.
FINANCING TRANSACTIONS
In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1.30 million shares of its common stock, in two privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933.
On February 5, 2003, SPR issued 13.66 million shares of common stock in exchange for a total of 2,095,650 of its PIES in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933.
On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes have been used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. The remaining portion of the net proceeds will be used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003 at maturity and for general corporate purposes. The Convertible Notes were issued with registration rights.
The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR's common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.20 (the last reported sale price of SPR's common stock on March 17, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $137 million. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt.
The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control.
Currently, SPR (on a stand-alone basis) has a substantial amount of debt and other obligations including, but not limited to: $133 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR intends to pay off the remaining principal balance of its Floating Rate Notes due April 20, 2003 with cash currently on hand.
EFFECT OF HOLDING COMPANY STRUCTURE
Due to the holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors and preferred stockholders. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC
and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC's preferred trust security holders and SPPC's preferred stockholders. As of December 31, 2002, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.
CONSTRUCTION EXPENDITURES AND FINANCING (SPR CONSOLIDATED)
The table below provides SPR's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
SPR's consolidated cash construction expenditures for 2003 through 2007 are estimated to be $1.6 billion. Construction expenditures for 2003 are projected to be $344 million and are expected to be financed by internally generated funds, including the recovery of deferred energy at the Utilities. It is anticipated that no capital contributions from SPR will be used to fund construction expenditures at the Utilities.
Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on the Utilities' currently filed deferred energy rate cases and the full recovery of such deferred energy amounts over three years, no additional disallowances related to the Utilities' appeals of their prior deferred energy cases and no adverse decision in the lawsuit filed by Enron against the Utilities seeking $200 million and $87 million in termination payments from NPC and SPPC, respectively. Material disallowances of currently-filed or previously-filed deferred energy costs or a decision adverse to the Utilities with respect to the Enron lawsuit would have a material adverse effect on SPR's and the Utilities' financial condition and future results of operations, and could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding the Utilities' recently filed deferred energy rate cases and prior deferred energy rate cases and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties.
In the event that SPR's and/or the Utilities' financial conditions worsen, they may be unable to finance their construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating the Utilities' accounts receivable purchase facilities to provide additional liquidity. For additional information regarding the accounts receivable purchase facilities, see Liquidity and Capital Resources. Each of the Utilities may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur for either of the Utilities, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for the Utilities or SPR to access the capital markets for any such financing needs.
CONTRACTUAL OBLIGATIONS (SPR CONSOLIDATED)
The table below provides SPR's contractual obligations on a consolidated basis (except as otherwise indicated), not including estimated construction expenditures described above, as of December 31, 2002, that SPR expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):
CAPITAL STRUCTURE (SPR CONSOLIDATED)
On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC's $200 million unsecured revolving credit facility, discussed in Nevada Power Company, Liquidity and Capital Resources.
SPR's actual capital structure on a consolidated basis (except as otherwise indicated) at December 31, 2002, and 2001 was as follows (dollars in thousands):
(1) Including current maturities of long-term debt and $200 million of SPR holding company debt.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC incurred a net loss of ($235.1) million in 2002 compared to net income of $63.4 million in 2001 and a net loss of ($7.9) million in 2000. NPC's operating results for 2002 reflect the write-off of approximately $465 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's March 29, 2002, decision in NPC's deferred energy rate case to disallow $434 million of deferred purchased fuel and power costs. The PUCN's decision is being challenged by NPC in a lawsuit filed in Nevada state court.
In the first quarter of 2002 NPC paid $10 million in dividends on its common stock to its parent, SPR, all of which was reinvested in NPC as a contribution to capital. No other dividend payments or capital contributions occurred in 2002. Currently, NPC is restricted from paying dividends to SPR under the terms of certain financing agreements and a recent order of the PUCN. See Liquidity and Capital Resources for a discussion of these restrictions.
The causes for significant changes in specific lines comprising the results of operations for NPC for the respective years ended are provided below (dollars in thousands except for amounts per unit):
ELECTRIC OPERATING REVENUE
(1) Primarily wholesale, as discussed below
NPC's retail revenues increased in 2002 primarily due to a combination of customer growth and a net rate increase resulting from NPC's General Rate and Deferred Energy Cases (see Regulation and Rates Proceedings, later). The number of residential, commercial, and industrial customers increased over 2001 by 4.9%, 5.7 % and 2.1%, respectively. Commercial and industrial growth is attributable to the opening of several new schools, shopping centers, and casinos in the Las Vegas area. Effective April 1, 2002, the PUCN authorized an increase in energy related rates that are used to recover current and previously incurred fuel and purchased power costs. In addition to that rate increase, the PUCN also granted NPC the authority to increase its energy recovery rate by one cent per kilowatt-hour for the month of June 2002 only. This one-time increase in rates generated approximately $16 million which was used to accelerate the recovery of previously incurred fuel and purchased power costs. The decrease in the 2002 Other revenues was primarily due to the lower sales resulting from a reduction in transactions entered into for hedging purposes and the optimization of purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
NPC's retail revenues increased in 2001 due to a combination of customer growth and rate increases resulting from the Global Settlement and Comprehensive Energy Plan (see Regulation and Rates Proceedings, later). The number of residential, commercial, and industrial customers increased over the prior year by 4.8%, 4.4% and 6.5%, respectively. Substantially all of the increase in the Other electric revenues was due to the sale of wholesale electric power to other utilities. NPC's increase in wholesale sales compared to 2000 was a result of market conditions and NPC's power procurement activities. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
PURCHASED POWER
(1) Not including contract termination costs, discussed below
NPC's purchased power costs were significantly lower in 2002 compared to 2001 due to substantial decreases in prices and volumes. Per unit costs of power decreased 50.0% primarily due to lower Short-Term Firm energy prices. These price decreases were the result of a less volatile energy market. The overall decrease in the cost of purchased power was offset, in part, by a $228 million reserve provision recorded for terminated contracts. See Liquidity and Capital Resources, later, for a discussion of these terminated power contracts. Volumes purchased decreased by 33.0% as a result of a reduction in hedging activities due to a change in risk management activities and energy supply strategies described later in Energy Supply. Purchases associated with risk management activities, which are included in Short-Term Firm energy, decreased significantly in both volume and price in 2002. Wholesale sales associated with risk management activities decreased in volume by approximately 58%. Risk management activities include transactions entered into for hedging purposes and to optimize purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
Purchased power costs were higher in 2001 as compared to 2000 due to a 99.5% increase in the volume purchased and an increase in the per unit cost of power of 126%. Purchased power costs were higher primarily due to higher Short-Term Firm energy prices. These price increases were the result of much higher fuel costs, combined with increased demand and limited power supplies.
FUEL FOR POWER GENERATION
NPC's 2002 fuel expense decreased 30% compared to 2001 primarily due to a substantial decrease in natural gas prices. This was slightly offset by an increase in coal prices and an overall increase in MWhs generated. In 2001, NPC's fuel expense increased over 50.9% compared to 2000 primarily due to a substantial increase in natural gas prices, offset in part by decreased generation late in 2001 when the cost of purchased power was more economical than generation.
DEFERRAL OF ENERGY COSTS - NET
The change in Deferral of energy costs-electric-net for the twelve months ended December 31, 2002, compared to the same period in the prior year, reflects the amortization in 2002 of prior deferred costs pursuant to the PUCN's decision on NPC's deferred energy rate case, which resulted in increased rates beginning April 1, 2002, and the one-time rate increase of $0.01 per kilowatt-hour for the month of June 2002. The amortization was offset, in part, by the recording of current year deferrals of electric energy costs, reflecting the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. Deferral of energy costs-electric-net also reflects the deferral in the second and fourth quarter of 2002 of approximately $228 million for contract termination costs as described in more detail in Note 17 of Notes to Financial Statements, Commitments and Contingencies. Deferred energy costs disallowed reflects the second quarter write-off of $434 million of electric deferred energy costs incurred in the seven months ended September 30, 2001, that were disallowed by the PUCN in its March 29, 2002 decision on NPC's deferred energy rate case.
NPC recorded Deferral of energy costs-electric-net in 2001 due to the implementation of deferred energy accounting beginning March 1, 2001. The amounts reflect the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. Deferral of energy costs-electric-net for 2000 represent energy costs that had been deferred in prior periods and were then recovered in 2000 as a result of deferred energy rate increases granted in 1999.
See Critical Accounting Policies, earlier, and Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies for more information regarding deferred energy accounting.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC for NPC is higher in 2002 compared to 2001 because of an increase in construction work-in-progress (CWIP) and the adjustments in 2001 to amounts assigned to specific components of facilities that were
completed in different periods. This increase was offset by a small decrease in the AFUDC rate compared to 2001 due to an increase in short-term debt. In 2001, AFUDC is lower compared to 2000 because of adjustments to amounts assigned to specific components of facilities that were completed in different periods.
OTHER (INCOME) AND EXPENSES
The decrease in Other operating expense for 2002 reflects $10.0 million of reserve provisions which were established in 2001 for retail uncollectible accounts in NPC's service territory and $12.6 million for uncollectible amounts associated with the California Power Exchange, which NPC continues to pursue for collection. Additional factors that resulted in lower Other operating expenses during 2002 include the reversal of a $6 million reserve originally established in 2001 pursuant to the PUCN order for costs associated with the conclusion of electric industry restructuring. NPC had no 2002 short-term incentive plan expense compared to $5.5 million in 2001. Increases in Other operating expense during 2002 include $14.7 million in legal and advisory fees associated with liquidity issues and the consequences of the PUCN's deferred energy rate case decision. Additional increases in Other operating expense in 2002 included $12.1 million related to collection for and write-off of uncollectible accounts.
Other operating expense increased in 2001 compared to 2000 due to a $16.6 million larger addition to the provision for uncollectible customer accounts than in 2000, reflecting the impact of the weakening economy and disruption to the leisure travel industry after September 11, 2001. Other operating expense also increased due to the addition of $12.6 million to the uncollectible provision related to receivables from the California Power Exchange (PX) and California's Independent System Operator (ISO).
The level of NPC's maintenance and repair expenses fluctuates primarily upon the scheduling, magnitude, and number of generation unit overhauls at NPC's generating stations. As a result of an outage delay at Reid-Gardner and deferred outage at Clark Station, maintenance costs were decreased by $6.1 million in 2002. These decreases were partially offset by miscellaneous increases at Mohave and Navajo totaling $1.4 million. Maintenance expense for 2001 increased from the prior year as a result of increased outage work at Reid-Gardner, additional expenditures for repairs and outages at Clark Station and increased work at Mohave.
An increase in the computer depreciation rate pursuant to a PUCN order and additions to plant-in-service were the primary cause of NPC's increase in depreciation and amortization expense in 2002 compared to 2001. Depreciation and amortization were also higher in 2001 than 2000 due to an increase in plant-in-service.
As a result of net losses recognized during 2002 and 2000, NPC recorded an income tax benefit for those years. As a result of net income for 2001, NPC incurred income tax expense. See Note 10 of Notes to Financial Statements, Taxes, for additional information regarding the computation of income taxes.
NPC's interest charges on long-term debt increased in 2002 compared to 2001 due to additional issuances of long-term debt at higher interest rates during 2002 and to the payment of a full year of interest on $100 million of long-term debt issued throughout 2001. In 2002, NPC redeemed $15 million in debt and issued additional debt of $250 million. For 2001 compared to 2000, NPC's increased interest charges were attributable to the issuance of $700 million of long-term debt mentioned above. See Note 9 of Notes to Financial Statements, Long-Term Debt for additional information regarding long-term debt.
NPC's interest charges-other increased in 2002 compared to 2001 due primarily to interest on extended payments to fuel and power suppliers resulting from renegotiated purchased power and fuel contracts. Increased credit facility fees also contributed to the increase in 2002 over the prior year (Refer to Liquidity and Capital Resources for further discussion of power and fuel contracts and the credit facilities). Interest charges-other for the year 2001 were comparable to 2000.
NPC's interest accrued on deferred energy decreased during 2002, compared to 2001 due to a significant decline in the related deferred fuel and purchased power balances. For the period 2001 compared to 2000, the increase in these carrying charges was attributable to the related increases in deferred fuel and purchased power balances. (Refer to Regulation and Rate Proceedings for further discussion of deferred energy accounting issues).
NPC's other income for the year 2002 decreased from 2001 due, primarily, to an expense adjustment related to sale of SO2 emission allowances ordered by the PUCN. Other income for the year 2001 was comparable to 2000. For the year 2001 compared to 2000, the decrease was primarily attributable to the classification, in 2001, of lease revenues as operating income, while in 2000 these revenues were classified as non-operating.
NPC's other expense increased in 2002 compared to 2001 due primarily to costs associated with NPC's contribution to a group opposed to the inclusion of an Electric Utility Advisory Question to the November 2002 general election ballot. NPC also incurred increased costs for assistance programs, corporate advertising, and miscellaneous customer information activities. For the year 2001, compared to 2000, NPC's other expense increased, as a result of increased expenditures to its low-income energy assistance programs.
Income Taxes - Other Income and Expense decreased in 2002 as a result of lower other income and expense than 2001 primarily due to lower accrued interest on deferred energy costs. The increase from 2000 to 2001 was also caused by the corresponding increase in other income and expense from 2000 to 2001.
ANALYSIS OF CASH FLOWS
NPC's net cash flows improved in 2002 compared to 2001, resulting from an increase in cash flows from operating activities offset in part by decreases in cash flows from investing and financing activities. Although NPC recorded a substantial loss for 2002, compared to net income in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Cash flows from operating activities in the current year also reflect the receipt of an income tax refund. Cash flows from investing activities decreased because of additional cash utilized for construction activities during 2002 compared to 2001. Cash flows from financing activities were lower because of decreases in net long-term debt issued, decreases in short-term borrowings and less cash invested by NPC's parent, SPR, during 2002.
NPC's net cash flows decreased in 2001 compared to 2000. The net decrease in cash resulted from a significant increase in cash flows used in operating activities combined with cash used in investing activities
both partially offset by an increase in cash provided by external financing sources. The increase in cash flows used in operating activities resulted substantially from the payment of significantly higher energy costs during 2001. Net cash used in investing activities was comparable between 2001 and 2000. Net cash provided by financing activities was higher in 2001 as a result of cash provided by the issuance of short-term and long-term debt, as described in Note 9 Long-Term Debt and Note 12 Short-Term Borrowings of the Notes to Financial Statements, and additional capital contributions from SPR. Cash provided by financing activities was substantially utilized for the payment of higher energy costs in 2001.
LIQUIDITY AND CAPITAL RESOURCES
NPC had cash and cash equivalents of approximately $95 million at December 31, 2002, and approximately $96 million at February 28, 2003.
As discussed in Construction Expenditures and Financing and Capital Structure that follow, NPC anticipates external capital requirements for construction costs and for the repayment of maturing long-term debt during 2003 totaling approximately $578 million, which NPC expects to finance with internally generated funds, including the recovery of deferred energy, and the issuance of debt.
NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets, and could adversely affect NPC's ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing could have a material adverse effect on NPC's financial condition and liquidity, and could make it difficult for NPC to continue to operate outside of bankruptcy.
EFFECT OF RATE CASE DECISIONS
On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. As a result of these downgrades, NPC's ability to access the capital markets to raise funds were severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to NPC also became severely limited.
Commercial Paper and Credit Facilities. In connection with the credit downgrades by S&P and Moody's, NPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time, NPC had a commercial paper balance outstanding of $198.9 million, with a weighted average interest rate of 2.52%. Since NPC was no longer able to issue its commercial paper, it paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. NPC does not expect to have direct access to the commercial paper market for the foreseeable future.
NPC's $200 million unsecured revolving credit facility was also affected by the decision in the deferred energy rate case. Following the announcement of that decision, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 3, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent as security for the credit facility.
This facility was paid in full and terminated on October 30, 2002 with proceeds from the issuance of NPC's $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009.
Power Supplier Issues. Historically, NPC has purchased a significant portion of the power that it sells to its customers from power suppliers. As discussed under Sierra Pacific Resources, Liquidity and Capital Resources, following the PUCN's decision on March 29, 2002 in NPC's deferred energy rate case, a number of power suppliers requested collateral from NPC under the WSPP standard contract. NPC informed such suppliers that a simultaneous call for 100% mark-to-market collateral in the short term would likely not be met and proposed extended payment terms for the above-market portions of NPC's existing power contracts. Although several power suppliers terminated their contacts with NPC (as discussed below), the remaining suppliers accepted the deferred payments, which were paid in full by October 29, 2002.
In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon NPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted a claim for liquidated damages under the terminated power supply contracts.
Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million against NPC for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to NPC. NPC has denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. NPC filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.
On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million for energy delivered by Enron in April 2002, for which NPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. NPC made the deposit as ordered. The bankruptcy court denied NPC's motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied NPC's motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC to post $200 million pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion to dismiss NPC's counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) NPC's motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss NPC's counterclaims is set for hearing on April 3, 2003. NPC is unable to predict the outcome of the motions. A decision adverse to NPC on Enron's motion for partial summary judgment,
or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on NPC's financial condition and liquidity and could make it difficult for NPC to continue to operate outside of bankruptcy.
On June 10, 2002, Duke entered into an agreement with NPC, SPR and SPPC to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill NPC's customers' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002, Duke was paid the full amount of the deferred payments.
On September 5, 2002, MSCG initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contracts claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction.
On September 30, 2002, EPME notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC.
If NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers or to continue to operate outside of bankruptcy.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless NPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the
event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, NPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of NPC. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described below. SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the receivables purchase facility.
NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond.
NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond.
MORTGAGE INDENTURES
NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of December 31, 2002, $372.5 million of NPC's first mortgage bonds were outstanding. NPC agreed in connection with its Series E Notes that it would not issue any more first mortgage bonds.
NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2002, $870 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage Bonds, and/or (3) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. As of December 31, 2002, NPC had the capacity to issue approximately $1.04 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in the Series E Notes limits NPC ability to issue additional General and Refunding Mortgage Bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility.
NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture.
PUCN ORDER
On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037 which requires that until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42%
equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%.
On July 3, 2002, the BCP of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt.
FINANCING TRANSACTIONS AND COVENANTS
On October 25, 2002, NPC redeemed its 7 5/8% Series L, First Mortgage Bonds due November 1, 2002, in the aggregate principal amount of $15 million.
On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of $235.6 million. The Series E Notes were issued with registration rights. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes.
The Series E Notes limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series E Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC's investment in certain subsidiaries.
The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers.
If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.
Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series
E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. The Series E Notes will mature October 15, 2009.
CROSS DEFAULT PROVISIONS
Certain financing agreements of NPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of NPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, NPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in NPC's various financing agreements are briefly summarized below:
o NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs;
o The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders; and
o NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively.
PENSION PLAN MATTERS
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the measurement date, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, NPC contributed a total of $13.05 million to meet its funding obligations under the plan. At the present time, NPC does not expect that any near term funding obligation will have a material adverse effect on its liquidity.
CONSTRUCTION EXPENDITURES AND FINANCING
The table below provides NPC's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
NPC's estimated cash construction expenditures for 2003 through 2007 are $1.068 billion. Construction expenditures for 2003 are projected to be $223 million and are expected to be financed by internally generated funds, including the recovery of deferred energy.
Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on NPC's currently filed deferred energy rate case and the full recovery of such deferred energy amounts over three years, no additional disallowances related to NPC's appeal of its prior deferred energy case and no adverse decision in the lawsuit filed by Enron against NPC seeking $200 million in termination payments. Material disallowances of currently-filed or previously-filed deferred energy costs or an adverse decision with respect to the Enron lawsuit would have a material adverse effect on NPC's financial condition and future results of operations and could cause additional downgrades of its securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding NPC's recently filed deferred energy rate case and prior deferred energy rate case and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties.
In the event that NPC's financial condition worsens, it may be unable to finance its construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating its accounts receivables purchase facility to provide additional liquidity. For additional information regarding the accounts receivables purchase facility, see Liquidity and Capital Resources. NPC may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of $125 million of its General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for NPC to access the capital markets for any such financing needs.
CONTRACTUAL OBLIGATIONS
The table below provides NPC's consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2002, that NPC expects to satisfy through a
combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):
CAPITAL STRUCTURE
As of December 31, 2002, NPC had no short-term debt outstanding.
On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial purchaser of all of the variable rate revolving notes.
NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of a $125 million General and Refunding Mortgage Bond. See Liquidity and Capital Resources for additional information regarding the terms and conditions of the accounts receivable purchase facility.
NPC's actual consolidated capital structure at December 31, 2002, and 2001 was as follows (dollars in thousands):
(1) Including current maturities of long-term debt.
OTHER MATTERS
On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002, general election ballot which asked voters in a non-binding initiative whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." The Company and various private entities and public interest groups strongly opposed the measure. Although passing by a 57% majority, this was substantially below the level of support indicated in early polls. No bills related to this issue were introduced in the 2003 Nevada legislative session.
On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiations of definitive agreements to acquire NPC in some undetermined way (stock purchase or all or some of its assets) and to assume some unspecified amount of indebtedness, at a purchase price subject to adjustment at SNWA's discretion at the conclusion of negotiations and due diligence. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal, SNWA's lack of utility management experience, and ambiguity in the proposal. SPR was served a complaint by a shareholder seeking class action status to require SPR to enter into negotiations. See Legal Proceedings for further details.
SIERRA PACIFIC POWER COMPANY
RESULTS OF OPERATIONS
SPPC incurred a net loss from continuing operations of ($14.0) million in 2002, compared to net income of $22.7 million in 2001, and a net loss of ($4.1) million in 2000. SPPC's operating results for 2002 reflect the write-off of approximately $58 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's May 28, 2002, decision in SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs. The PUCN's decision is being challenged by SPPC in a lawsuit filed in Nevada state court.
During 2002, SPPC paid $44.9 million in common stock dividends to its parent, SPR, $10 million of which was reinvested in SPPC as a contribution to capital. SPPC also paid $3.9 million in dividends to holders of its preferred stock.
SPPC closed the sale of its water utility business in June 2001. Accordingly, the water business is reported as a discontinued operation and the continuing operating results have been reclassified to report separately the net results of operations from the water business.
The components of gross margin are (dollars in thousands):
The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit):
ELECTRIC OPERATING REVENUES
(1) Primarily wholesale, as discussed below
SPPC's retail revenues were higher in 2002 primarily as a result of a net rate increase resulting from SPPC's general rate and deferred energy cases (refer to Regulation and Rates Proceedings, later). Effective June 1, 2002, the PUCN authorized an increase in SPPC's energy related rates that are used to recover current and previously incurred fuel and purchased power costs. The decrease in 2002 Other revenues was primarily due to the lower sales resulting from a reduction in transactions entered into for hedging purposes and the optimization of purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
The increase in SPPC's 2001 retail revenues was primarily due to rate increases resulting from the Global Settlement and Comprehensive Energy Plan (refer to Regulation and Rate Proceedings, later). These increases in rates were used to recover fuel and purchased power costs. Substantially all of the increase in Other electric revenues was due to the sale of wholesale electric power to other utilities. SPPC's increase in
wholesale sales compared to 2000 was a result of market conditions and SPPC's power procurement activities. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
GAS OPERATING REVENUES
2002 retail gas revenues were significantly higher than the prior year primarily due to a rate increase resulting from SPPC's purchased gas adjustment filing. Effective November 5, 2001, the PUCN authorized this increase in energy related rates that are used to recover current and previously incurred purchased gas. Other gas revenues were significantly lower in 2002, due to lower wholesale prices and sales.
Gas revenues rose in 2001, as compared to 2000 primarily due to the fact that the PUCN allowed SPPC to implement two gas rate increases. These increases were the result of higher gas costs that SPPC incurred. Revenues were also higher due to increases of 5.0%, 3.1% and 10.6%, respectively, in residential, commercial and industrial customers. Other revenues were higher due to an increase in wholesale gas sales.
PURCHASED POWER
(1) Not including contract termination costs, discussed below
Purchased power costs decreased dramatically in 2002 due to overall purchase power prices decreasing by 52.9%. These price decreases were the result of a less volatile energy market. The overall decrease in the cost of purchased power was offset in part by an $86.8 million reserve provision recorded in the second quarter for terminated contracts. Purchased power costs also reflect a 40% decrease in wholesale sales activity. Purchases associated with risk management activities, which include transactions entered into for hedging purposes
and to optimize purchased power costs, are included in the purchased power amounts. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies.
Purchased power costs were higher in 2001 than 2000 primarily because prices per MWh were double that of the prior year and purchased power was relied on to accommodate increased system load. Purchased power costs were also higher during 2001 due to hedging activities in response to higher purchased power prices.
FUEL FOR POWER GENERATION
Fuel for power generation costs decreased 49.7% in 2002 as compared to 2001 due primarily to decreased natural gas prices and, to a lesser extent, to lower system load requirements.
Fuel for generation costs in 2001 were higher than 2000 due to higher gas prices and an increase in volumes purchased to accommodate greater system load.
GAS PURCHASED FOR RESALE
The cost of gas purchased for resale decreased in 2002 as compared to 2001 primarily as a result of lower unit prices more than offsetting an increase in quantities. The significant gas price decreases are consistent with the increase in availability. Although there was a lower demand by retail customers as a result of warmer weather, SPPC sold more volume to wholesale customers causing the increase in quantities.
As compared to 2000, the cost of gas purchased for resale increased in 2001 because a decrease in quantities of gas purchased was more than offset by large increases in unit prices. The decrease in quantities purchased was the result of increased plant consumption of gas, thereby decreasing the availability of gas for wholesale activities. The higher unit prices were attributable to increased demand for gas in the Pacific Northwest and additional transportation fees.
DEFERRAL OF ENERGY COSTS - NET
The change in Deferred energy costs-electric-net for the twelve months ended December 31, 2002, compared to the same period the prior year, reflects the amortization in 2002 of prior deferred costs pursuant to the PUCN's decision on SPPC's deferred energy rate case, which resulted in increased rates beginning June 1, 2002. The amortization was offset in part by the recording of current year deferrals of electric energy costs, reflecting the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. Deferral of energy costs-net also reflects the deferral in the second quarter of 2002 of approximately $82 million for contract termination costs and the second quarter 2002 write-off of $53 million of electric deferred energy costs incurred in the nine months ended November 30, 2001, that were disallowed by the PUCN in their May 28, 2002, decision on SPPC's deferred energy rate case. See more detail in Note 17 of Notes to Financial Statements, Commitments and Contingencies.
In January 2000, after the expiration of a rate freeze that was in effect from 1997 through 1999, SPPC began deferring natural gas costs in excess of that allowed in the tariff for its gas local distribution company (LDC). In 2001, the deferral increased in 2001 due to higher gas costs incurred by SPPC. The significant change from 2001 is attributed to lower gas costs in 2002 combined with the recovery of fuel and purchased power costs through current rates, which exceeded the actual fuel and purchase power costs. Deferred energy costs disallowed reflects a write-off of $4 million in gas costs, incurred in the twelve months ended April 2002, that were disallowed by the PUCN in their December 23, 2002 decision on SPPC's Purchase Gas Adjustment rate case.
See Critical Accounting Policies, earlier, and Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies for more information regarding deferred energy accounting.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC for SPPC is higher in 2002 compared to 2001 due to an increase in construction work-in-progress (CWIP) and because AFUDC in 2001 reflected an adjustment to refine amounts assigned to specific components of facilities that were completed in different periods. This increase was offset in part by a decrease in the AFUDC rate. AFUDC is lower in 2001 compared to 2000 because of adjustments to amounts assigned to
specific components of facilities that were completed in different periods offset by an increase in the AFUDC rate.
OTHER (INCOME) AND EXPENSES
The decrease in Other operating expense for 2002 reflects $8.6 million of reserve provisions which were established in 2001 for retail uncollectible accounts in SPPC's service territory and uncollectible amounts associated with the California Power Exchange. Additional factors that resulted in lower Other operating expenses during 2002 include the reversal of a $7.0 million reserve originally established in 2001 pursuant to the PUCN order for costs associated with the conclusion of electric industry restructuring. SPPC had no 2002 short-term incentive plan expense compared to $4.2 million in 2001. Increases in Other operating expense during 2002 include $9.0 million in legal and advisory fees associated with liquidity issues and the consequences of the PUCN's deferred energy rate case decision.
Other operating expense increased in 2001 compared to 2000 due to a $7 million larger addition to the provision for uncollectible customer accounts than in 2000, and a $3.5 million reserve provision established as a result of AB 369. Additionally, there were increased expenses related to the start-up of the Pinon Gasifier in 2001.
Maintenance costs in 2001 were higher due to additional turbine repairs and no major overhauls in 2000 at Valmy. There was also a shift from divestiture in 2000 to maintenance activities in 2001 at Tracy as well as unplanned maintenance on the diesel generators.
Depreciation and amortization were higher in 2002 than 2001 due to an increase in plant-in-service and an increase to depreciation of $1.8 million to reflect an adjustment to depreciation rates related to combustion turbines. These increases were offset in part by a PUCN-ordered reduction in depreciation rates that was implemented June 1, 2002. Depreciation and amortization were also higher in 2001 than 2000 due to an increase in plant-in-service.
As a result of net losses from continuing operations recognized during 2002 and 2000, SPPC recorded an income tax benefit for those years. Due to net income from continuing operations, SPPC recorded income tax expense for 2001.
SPPC's Interest charges on long-term debt increased in 2002 compared to 2001 due to additional issuances of long-term debt at higher interest rates and to the payment of a full year of interest on $320 million of long-term debt issued in May 2001. In 2002, SPPC redeemed approximately $4 million in debt and issued additional debt of $100 million. For 2001 compared to 2000, SPPC's increased interest charges were attributable to the issuance of $320 million of long-term debt.
SPPC's Interest charges-other increased in 2002 compared to 2001 due to interest on extended payments to fuel and power suppliers resulting from renegotiated purchased power and fuel contracts, interest on short term notes, and credit facility fees (refer to Liquidity and Capital Resources for further discussion of power and fuel contracts and the credit facilities). SPPC's interest charges-other decreased in 2001 compared to 2000 due to a decrease in commercial paper balances in 2001.
SPPC's interest accrued on deferred energy decreased in 2002, compared to 2001 due to a decline in carrying charges on deferral of fuel and purchased power balances in 2002 as compared to 2001. For 2001, the increase over 2000 was due to the increases in deferred fuel and purchased power balances pursuant to AB 369. (Refer to Regulation and Rate Proceedings for discussion of deferred energy issues).
SPPC's Other income for 2002 compared to 2001 increased due to increased interest and dividend income and gains on disposition of property. For 2001 as compared to 2000 the decrease was attributable to reductions in lease revenues, interest and dividend income, and miscellaneous gains on dispositions of property.
SPPC's Other expense increased in 2002 compared to 2001 due primarily to increased expenditures to its low-income energy assistance programs. For 2001 as compared to 2000 Other expense increased due to increased expenses attributable to SPPC's subsidiaries, and by costs relating to SPPC's divestiture of its water business.
Net tax expense on other income and expense increased in 2002 over 2001 because in 2001 certain benefits related to sale of the water utility business were recorded in other income and expense. These benefits were the result of the true-up of the 2000 tax return recorded in 2001.
In 2001, a net tax benefit was recorded due to the net excess of other expenses over other income for the year.
DISCONTINUED OPERATIONS
SPPC closed the sale of its water utility business in 2001. Accordingly, the water business is reported as a discontinued operation. Income from operations of the water business decreased in 2001 compared to 2000 as a result of the sale of the water business in June 2001, prior to the seasonal increase in revenues resulting from higher water send-out.
ANALYSIS OF CASH FLOWS
SPPC's net cash flows improved in 2002 compared to 2001, resulting primarily from an increase in cash flows from operating activities offset in part by a decrease in cash flows from investing activities. Although SPPC recorded a net loss during 2002 compared to net income in 2001 the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Also, cash flows from operating activities in the current year reflect the receipt of an income tax refund. Cash flows from investing activities decreased in 2002 because 2001 investing activities included cash provided from the sale of the assets of SPPC's water business. Cash flows from financing activities during 2002 were comparable to 2001.
SPPC's net cash flows during 2001 were comparable to 2000. For 2001, an increase in net cash flows from investing activities was substantially offset by a decrease in net cash flows from operating activities. The increase in net cash flows from investing activities resulted from the sale of the assets of SPPC's water business. The decrease in cash flows from operating activities resulted substantially from the payment of significantly higher energy and resale natural gas costs. These uses of cash flows were partially offset by a decrease in accounts payable in 2001. The decrease in cash flows from financing activities was due to reduced reliance on commercial paper in 2001 and the retirement of preferred stock as described in Note 8 of Notes to the Financial Statements, Preferred Stock and Preferred Trust Securities, offset in part by capital contributions from SPR.
LIQUIDITY AND CAPITAL RESOURCES
SPPC had cash and cash equivalents of approximately $88.9 million at December 31, 2002, and approximately $104.2 million at February 28, 2003.
As discussed in Construction Expenditures and Financing and Capital Structure, SPPC anticipates having capital requirements for construction costs and for the repayment of maturing long-term debt during 2003 totaling approximately $222 million, which SPPC expects to finance with internally generated funds, including the recovery of deferred energy and the issuance of debt.
SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets and could adversely affect SPPC's ability to continue purchasing power and fuel. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could have a material adverse effect on SPPC's financial condition and liquidity, and could make it difficult to continue to operate outside of bankruptcy.
EFFECT OF RATE CASE DECISIONS
On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. The decision of the PUCN on May 29, 2002, on SPPC's deferred energy application to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001, did not result in any further downgrades of SPPC's securities. As a result of the downgrades, SPPC's ability to access the capital markets to raise funds is severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to SPPC also became severely limited.
Commercial Paper and Credit Facilities. In connection with the credit ratings downgrades referenced above, SPPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time, SPPC had a commercial paper balance outstanding of $47.7 million with a weighted average interest rate of 2.49%. SPPC paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. SPPC does not expect to have direct access to the commercial paper market for the foreseeable future.
SPPC's $150 million unsecured revolving credit facility was also affected by the downgrade in SPPC's credit rating. Under this facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to
secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility. As of May 10, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, maintaining a cash balance at SPPC. This facility was paid in full and terminated on October 31, 2002 with available cash and proceeds from SPPC's $100 million Term Loan Facility.
Power Supplier Issues. Historically, SPPC has purchased a significant portion of the power that it sells to its customers from power suppliers. As discussed under Sierra Pacific Resources, Liquidity and Capital Resources, following the PUCN's decision on March 29, 2002 in NPC's deferred energy rate case, a number of power suppliers requested collateral from SPPC and NPC under the WSPP standard contract. Both SPPC and NPC informed such suppliers that a simultaneous call for 100% mark-to-market collateral in the short term would likely not be met. Several power suppliers terminated their contacts with SPPC (as discussed above).
In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon SPPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, a claim for liquidated damages under the terminated power supply contracts.
Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $93 million against SPPC for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to SPPC. SPPC has denied liability on numerous grounds, including deceit and misrepresentation in the inducement, (including, but not limited to, misrepresentation as to Enron's ability to perform) and for fraud, unfair trade practices, and market manipulation. SPPC filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' 206 actions at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.
On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $6.7 million for energy delivered by Enron in April 2002, for which SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The bankruptcy court denied SPPC's motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied SPPC's motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require SPPC to post $87 million pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion to dismiss SPPC's counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) SPPC's motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss SPPC's counterclaims is
set for hearing on April 3, 2003. SPPC is unable to predict the outcome of the motions. A decision adverse to SPPC on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPPC's financial condition and liquidity and would make it difficult to continue to operate outside of bankruptcy.
If SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, SPPC's business, operations and financial condition will be materially adversely affected and could make it difficult for SPPC to provide reliable service to its customers or to continue to operate outside of bankruptcy.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless SPPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and natural gas to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In additional to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, SPPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of SPPC. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described below. SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the receivables purchase facility.
SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond.
SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond.
MORTGAGE INDENTURES
SPPC's First Mortgage Indenture creates a first priority lien on substantially all of SPPC's properties in Nevada and California. As of December 31, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding. SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds.
SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2002, $420 million of SPPC's General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds, and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. At December 31, 2002, SPPC had the capacity to issue approximately $427 million of additional General and Refunding Mortgage securities. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility.
SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture.
FINANCING TRANSACTIONS AND COVENANTS
On May 23, 2002, SPPC satisfied its obligations with respect to its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended.
On October 30, 2002, SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a Series B General and Refunding Mortgage Bond. SPPC's Term Loan Agreement limits the amount of
dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively.
The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment plus (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.
SPPC's Term Loan Agreement requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. As of December 31, 2002, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005.
SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001 in the aggregate principal amount of $80 million, will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest.
CROSS DEFAULT PROVISIONS
Certain financing agreements of SPPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPPC's various financing agreements are briefly summarized below:
o SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs;
o SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and
o SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively.
PENSION PLAN MATTERS
SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, SPPC contributed a total of $10.53 million to meet its funding obligations under the plan. At the present time, SPPC does not expect that any near term funding obligation will have a material adverse effect on its liquidity.
CONSTRUCTION EXPENDITURES AND FINANCING
The table below provides SPPC's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
SPPC's estimated cash construction expenditures for 2003 through 2007 are $483 million. Construction expenditures for 2003 are projected to be $121 million and are expected to be financed by internally generated funds, including the recovery of deferred energy at the Utilities.
Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on SPPC's currently filed deferred energy rate case and the full recovery of such deferred energy amounts over three years, no additional disallowances related to SPPC's appeal of its prior deferred energy case and no adverse decision in the lawsuit filed by Enron against SPPC seeking $87 million in termination payments. Material disallowances of currently-filed or previously-filed deferred energy costs or an adverse decision with respect to the Enron lawsuit would have a material adverse effect on SPPC's financial condition and future results of operations and could cause additional downgrades of its securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding SPPC's recently filed deferred energy rate case and prior deferred energy rate case and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties.
In the event that SPPC's financial condition worsens, it may be unable to finance its construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating its accounts receivables purchase facility to provide additional liquidity. For additional information regarding the accounts receivables purchase facility, see Liquidity and Capital Resources. SPPC may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of $75 million of its General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for SPPC to access the capital markets for any such financing needs.
CONTRACTUAL OBLIGATIONS
The table below provides SPPC's contractual obligations, not including estimated construction expenditures described above, as of December 31, 2002, that SPPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):
CAPITAL STRUCTURE
As of December 31, 2002, SPPC had no short-term debt outstanding.
On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will in turn sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial purchaser of all of the variable rate revolving notes.
SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. See Liquidity and Capital Resources for additional information regarding the terms and conditions of the accounts receivable purchase facility.
SPPC's actual capital structure at December 31, 2002, and 2001 was as follows (dollars in thousands):
(1) Including current maturities of long-term debt.
ENERGY SUPPLY (NPC AND SPPC)
The energy supply function at the Utilities encompasses the reliable and efficient operation of the Utilities' owned generation, the procurement of all fuels and purchased power, and resource optimization (i.e., physical and economic dispatch). The Utilities have undertaken a rigorous review of the energy supply function and have implemented policy, planning and organizational changes to address the dramatic changes that have and are occurring in the energy industry.
The structure of the western wholesale energy market has seen dramatic changes in recent months. Significant amongst these are the collapse of the energy trading model and the merchant energy sector, which has resulted in reduced liquidity in the traded spot and forward markets for standard products. In addition, a credit crisis in the broader energy sector has resulted in a series of cancellations of new generation projects; putting intermediate term capacity margins in the broader region and within both Utilities' sub-region in jeopardy.
The Utilities also face energy supply challenges for their respective load control areas. There is the potential for continued price volatility in each Utility's service territory, particularly during peak periods. A greater dependence on gas-fired generation in the service territory subjects power prices to gas price volatilities. Both Utilities face load obligation uncertainty due to the potential for customer switching. Counterparties in these areas have significant credit difficulties, representing credit risk to the Utilities. Finally, each Utility's own credit situation can have an impact on its ability to enter into transactions.
In response to these energy supply challenges, the Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk-management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Utilities will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.
ENERGY SUPPLY PLANNING
Within the energy supply planning process, there are three key components covering different time frames:
(1) the PUCN-approved long-term integrated resource plan has a twenty-year year planning horizon;
(2) the energy supply plan, which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio parameters within which intermediate term resource requirements will be met, has a one to three year planning horizon; and
(3) tactical execution activities with a one-month to twelve-month focus.
The energy supply plan will operate in conjunction with the PUCN-approved twenty-year integrated resource plan. It will serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plan calls for executing contracts of duration of more than three years, the plan will require PUCN approval as part of the integrated resource planning process.
In developing energy supply plans and implementing on those plans, management guidelines followed by the Utilities include:
o Maintaining an energy supply plan that balances costs, risks, price volatility, reliability and predictability of supply.
o Investigating feasible commercial options to implement against the energy supply plan.
o Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction.
o Implementing the approved energy supply plan in a manner that manages ratepayer risk in terms of reliability, volatility and cost.
o Monitoring the portfolio against evolving market conditions and managing the resource optimization options.
o Ensuring simple, transparent and well-documented decisions and execution processes.
ENERGY RISK MANAGEMENT AND CONTROL
The Utilities' efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by a Board of Directors' revised and approved Enterprise Risk Management and Control Policy. That policy created the Enterprise Risk Oversight Committee (EROC) and made that committee responsible for the overall policy direction of the Utilities' risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies including the Energy Supply Risk Management and Control Policy.
The Utilities' commodity risk management program establishes a control framework based on existing commercial practices. The program creates predefined risk limits and delineates management responsibilities and organizational relationships. The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities' commercial activities. The program's control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation's compliance with portfolio and credit limits.
The Utilities, through the purchase and sale of financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with energy supply plans approved by the Chief Executive Officer and the EROC.
REGULATORY ISSUES
The Utilities' long-term integrated resource plans are filed with the PUCN for approval every three years. Nevada law provides that resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. The Utilities resource plans will be filed with the PUCN on July 1, 2003 and 2004 for NPC and SPPC, respectively. Between resource plan filings, the Utilities are required to seek PUCN approval for power purchases with terms of three years or greater by filing amendments to prior resource plan filings.
The Utilities will also seek regulatory input and acknowledgement of intermediate term energy supply plans. The Utilities feel this is necessary to ensure that the appropriate levels of risks are being mitigated at reasonable costs, the appropriate levels of risks are being retained in the portfolio, and decisions to manage risks with best available information at the point in time when decisions are made are subject to reasonable mechanisms for rate recovery.
INTERMEDIATE TERM ENERGY SUPPLY PLANS
The Utilities are in the process of developing and implementing their intermediate term energy supply plans. Those plans cover the years 2003 through 2005 and require Enterprise Risk Oversight Committee and the CEO approval prior to implementation. The energy supply plans will operate within the framework of the PUCN-approved twenty-year integrated resource plans. They serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plans call for the execution of contracts of duration of more than three years, an amended resource plan will be prepared and submitted for PUCN approval. The energy supply plans will be updated at least annually.
NPC's energy supply plan has been approved internally and was filed with the PUCN on January 31, 2003 for informational purposes. SPPC's plan is in the final stages of development and also will be filed with the PUCN for informational purposes. Key features of NPC's plan are:
o Weigh the intermediate-term portfolio mix heavily towards peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to gas prices), to meet the following requirements:
o Optimize the tradeoff between overall fuel and purchase power cost and market price risk.
o Pursue in-region capacity to enhance long-term regional reliability.
o Represent the set of transactions/products available in the market.
o Reduce credit risk--in a market with weak counter-party financials.
o Procure to match the difficult load profile, to the extent possible.
o Hedge the gas price risk exposure in the fuel portfolio through the purchase of call options.
o Manage off-peak and shoulder month energy price risk through ongoing intermediate and short-term optimization activities (e.g., optimizing the dispatch of NPC generation and/or buying directly from the market).
SPPC's energy supply plan will have many of the same features of NPC's plan with respect to managing fuel and purchased power cost and risk exposure, but SPPC's plan is being specifically tailored to its load obligation and the energy supply characteristics of its sub-region.
Both of the energy supply plans represent a change in procurement strategy from previous years. The strategy now focuses on executing contracts for power deliveries to the Utilities' physical points of delivery. In previous years, the Utilities used hedges to reduce price and commodity risk for future purchases by executing power contracts at so-called "liquid" trading points. A typical hedge transaction involved the purchase of power at one of the major trading hubs where prices were highly correlated with a physical delivery point to the Utility. The hedged purchase was either delivered to the Utilities' service territories to service their customers or, if the hedged purchase was not needed to fulfill power requirements, resold in the liquid market. With the significant drop in liquidity in wholesale markets, the Utilities have changed their procurement strategy to focus on power deliveries to the Utilities' physical points of delivery.
RECENT PROCUREMENT ACTIVITIES
As part of the implementation of NPC's energy supply plan, NPC in January 2003 entered into long-term purchase agreements with three companies - Panda Gila River LP, Calpine Energy Services and Mirant Americas Energy Marketing LP.
The agreement with Panda Gila River LP provides 200 megawatts of power to be delivered from Gila River Power Station in Gila Bend, Arizona, during the summer months of 2003, 2004 and 2005. Panda Gila River LP is a joint venture between TECO Power Services Corporation and Panda Energy International, Inc.
Currently under construction, the 2,145-megawatt facility will come on line in four phases, starting in the spring of 2003.
Calpine Energy Services, a wholly-owned subsidiary of Calpine Corporation, has agreed to deliver 100 MW of energy between the hours of 9 a.m. and midnight and 50 MW of energy from 1 a.m. to 8 a.m., seven days a week from June 1, 2003 through May 31, 2006. Energy will be delivered from Calpine's South Point Energy Center. All three contracts, Panda, Calpine, and Mirant, involve energy deliveries to NPC's control area.
The arrangement with Mirant involves three separate agreements under which Mirant will provide a total of 325 MW of capacity and energy to NPC. Each agreement identifies specific delivery dates ranging from May of 2003 and continuing through April of 2008. A majority of the energy (225 MW) will be delivered from the Apex facility located in Las Vegas.
Those agreements are subject to PUCN approval and were filed by NPC with the PUCN on January 24, 2003.
In a separate development, NPC also signed an agreement with Reliant for a total of 400 MW to be delivered the summer of 2003 only. Because this is a short-term contract, it is not subject to advance approval by the PUCN.
SHORT-TERM RESOURCE OPTIMIZATION STRATEGY
The Utilities' short-term resource optimization strategy involves both day-ahead (next day through the end of the current month) and real-time (next hour through the end of the current day) activities that require buying, selling and scheduling power resources to determine the most economical way to produce or procure the power resources needed to meet the retail customer load. After connecting generation units to the system, the Utilities dispatch the generation output based on the comparative economics of generation versus spot-market purchase opportunities and determine the amount of excess capacity, which is then sold on the wholesale market, or the amount of deficiency capacity, which must be procured on an hourly basis.
The day-ahead resource optimization begins with an analysis of projected loads and existing resources. Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. Any deficiency in the projected operating reserve for the next day, after consideration of available internal generation resources, is met by additional firm purchased power resources. The day-of resource optimization involves minimizing system production costs each hour by either changing the generation output or buying needed power and/or selling excess power in the wholesale market. Any sale of excess power priced above the incremental cost of producing such power reduces the net production cost of operating the electrical system and thereby benefits the end use customer. The Utilities endeavor to reduce the electrical systems' net production cost by selling the available excess power resources.
Real-time resource optimization requires an hourly determination of whether to run generation or purchase power in order to achieve the lowest production costs by calculating the projected incremental or detrimental cost of generation required to meet the forecast load in comparison to obtaining power in the wholesale power market. In the event that committed generators suffer a forced outage that is expected to last through the remaining monthly period, the operating cost of the next available generation resource is compared to purchase power options to determine the lowest cost option.
RESULTS OF OPERATIONS - SPR (HOLDING COMPANY) AND OTHER SUBSIDIARIES
TUSCARORA GAS PIPELINE COMPANY
TGPC, a wholly owned subsidiary of SPR, contributed $3.3 million in net income for the twelve months ended December 31, 2002, $2.6 million in net income for the twelve months ended December 31, 2001, and $2.1 million in net income for the twelve months ended December 31, 2000.
SIERRA PACIFIC COMMUNICATIONS
SPC, a wholly owned subsidiary of SPR, incurred a net loss of ($5.9) million for the twelve months ended December 31, 2002, a net loss of ($2.9) million for the twelve months ended December 31, 2001, and a net loss of ($989,000) for the twelve months ended December 31, 2000. SPC's increased loss for the twelve months ended December 31, 2002, was due to interest charges and other costs associated with its exit from Sierra Touch America LLC, including the $2.3 million write-off of an uncollectible receivable. For additional information see Note 9 of Notes to Financial Statements, Long-Term Debt.
e-THREE
e-three, a wholly owned subsidiary of SPR, incurred a net loss of ($1.2) million for the twelve months ended December 31, 2002, contributed $666,000 of net income for the twelve months ended December 31, 2001, and contributed $338,000 of net income for the twelve months ended December 31, 2000. e-three's loss for the twelve months ended December 31, 2002, is due primarily to a significant reduction in revenues attributable to a general decline in e-three's primary market and a transitional goodwill impairment charge of approximately $1.5 million.
SIERRA PACIFIC ENERGY COMPANY
SPE, a wholly owned subsidiary of SPR, incurred a net loss of ($295,000) for the twelve months ended December 31, 2002, a net loss of ($335,000) for the twelve months ended December 31, 2001, and a net loss of ($4.5) million for the twelve months ended December 31, 2000.
LANDS OF SIERRA
LOS, a wholly owned subsidiary of SPR, contributed net income of $128,000 for the twelve months ended December 31, 2002, net income of $281,000 for the twelve months ended December 31, 2001, and net income of $191,000 for the twelve months ended December 31, 2000.
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
The holding company's operating results included approximately $71.5 million, $55.8 million, and $44.5 million of interest costs for the twelve months ended December 31, 2002, 2001, and 2000, respectively, that resulted primarily from merger related financing. The holding company's operating results for the twelve months ended December 31, 2001, also reflect a charge of $22 million in connection with SPR's terminated plans to purchase Portland General Electric Company, including approximately $7.5 million representing a termination payment for shared expenses.
REGULATION AND RATE PROCEEDINGS
The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the California Public Utility Commission (CPUC) with respect to rates, standards of service, siting of and necessity for, generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit integrated resource plans to the PUCN for approval.
Under federal law, the Utilities and Tuscarora Gas Pipeline Company (TGPC) are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities' sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.
As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.
As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air quality, water pollution, solid, hazardous and toxic waste. SPR's Board of Directors has a comprehensive environmental policy and separate board committee that oversees NPC, SPPC, and SPR's corporate performance and achievements related to the environment.
NEVADA LEGISLATION
On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities, the repeal of electric industry restructuring, and a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. The stated purposes of this emergency legislation were, among others, to control volatility in the price of electricity in the retail market in Nevada, and to ensure that the Utilities have the necessary financial resources to provide adequate and reliable electric service under present market conditions. To achieve these purposes, AB 369 allows the Utilities to recover in future periods their current costs for wholesale power and fuel, which have risen dramatically over the past year. Deferred energy accounting has the effect of delaying additional rate increases to consumers while, at the same time, providing a method for the Utilities to recover their increased costs for fuel and purchased power. After the initial 2001 general rate applications described below under Nevada Matters, each Utility will be required to file future general rate applications at least every 24 months. Set forth below is a summary of key provisions of AB 369.
GENERATION DIVESTITURE MORATORIUM
AB 369 prohibits all divestiture of generation assets by electric utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN permission to sell one or more generation assets with the sale to be effective on or after July 1, 2003. The PUCN may approve the request to divest only if it finds the transaction to be in the public interest. The PUCN may base its approval of the request upon such terms, conditions, or modifications as it deems appropriate.
AB 369 directs the PUCN to take all steps necessary to obtain federal approval for the prohibition on divestiture and to vacate any of its own orders that had previously approved generation divestiture transactions.
DEFERRED ENERGY ACCOUNTING
AB 369 required the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel. See Note 3 of Notes to Financial Statements, Regulatory Actions, for a discussion of the deferred energy accounting provisions of AB 369.
RESTRICTIONS ON MERGERS AND ACQUISITIONS
AB 369 imposes certain restrictions on mergers and acquisitions involving Nevada electric utilities. In particular, the PUCN may not approve a merger or acquisition involving an electric utility unless the utility complies with the generation divestiture provisions of AB 369.
In addition, AB 369 includes provisions that would have significantly affected the required regulatory approvals for the proposed acquisition of PGE from Enron. On April 26, 2001, Enron and SPR terminated, by mutual agreement, the proposed purchase and sale of PGE.
AB 369 also provides that if an electric utility holding company acquires an interest in an out-of-state public utility prior to July 1, 2003, each electric utility in which the holding company holds a controlling interest shall not be entitled to the benefit of deferred energy accounting. Thus, in the event that SPR acquires an out-of-state public utility, NPC and SPPC would lose the ability to utilize deferred energy accounting.
REPEAL OF ELECTRIC INDUSTRY RESTRUCTURING
AB 369 repeals all statutes authorizing retail competition in Nevada's electric utility industry and voids any license issued to an alternative seller in connection with retail electric competition.
OTHER LEGISLATION
SB 372, which increased renewable energy portfolio requirements, was enacted in the 2001 Nevada legislative session. Renewable resources include biomass, wind, solar, and geothermal projects. In 2003, the Utilities will be required to purchase 5% of their energy from renewable resources. These requirements increase to 15% by 2013. Prior law capped renewable energy requirements at 1%. Currently, SPPC obtains approximately 9% of its energy from renewable resources, while NPC obtains less than one percent from renewables. SB 372 requires the PUCN to establish standards for renewable energy contracts, including prices and other terms and conditions. If sufficient renewable energy contracts that meet PUCN standards are not available, the Utilities will not be required to meet the portfolio requirements. All renewable energy contracts meeting PUCN standards will be recoverable in the deferred energy accounts.
The 2001 Nevada legislature passed another key piece of legislation for the Nevada energy industry, AB 661. AB 661 allows commercial and governmental customers with an average demand greater than one MW to select new energy suppliers. A more detailed explanation appears in the section Customers File under AB 661. AB 661 also contains new electric and gas energy surcharges for low-income assistance and weatherization programs. These surcharges are recoverable directly from customers as separate line items on their bills with the Utilities remitting collected surcharges to the PUCN. Various state agencies administer the disposition of the funds.
NEVADA MATTERS
NEVADA POWER COMPANY 2001 GENERAL RATE CASE
On October 1, 2001, NPC filed an application with the PUCN, as required by law, seeking an electric general rate increase. On December 21, 2001, NPC filed a certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, or an overall 1.7% rate increase. The application also sought a return on common equity (ROE) for NPC's total electric operations of 12.25% and an overall rate of return (ROR) of 9.30%.
On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adjustments increasing accumulated depreciation by $6.7 million, and the inclusion of approximately $5 million of revenues related to SO2 Allowances. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case. NPC was not granted a carrying charge on these deferred costs. NPC plans to renew its request to recover these costs in its next general rate case, which will be filed by the fourth quarter 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.
On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. The PUCN modified its original order reversing the adjustment to accumulated depreciation of $6.7 million, and decreased the SO2 allowance revenue amortization to $3.2 million per year. Revised rates for these changes went into effect on June 1, 2002.
NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE
On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law. The application sought to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.
On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision.
NPC's lawsuit requests that the District Court reverse portions of the PUCN's order and remand the matter to the PUCN with direction that the PUCN authorize NPC to immediately establish rates that would allow NPC to recover its entire deferred energy balance of $922 million, with a carrying charge, over three years. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. NPC is not able to predict the outcome of a decision in this matter.
Various interveners in NPC's deferred energy case before the PUCN filed petitions with the PUCN for reconsideration of the PUCN's order, seeking additional disallowances of between $12.8 million and
$488 million. On May 24, 2002, the PUCN issued an order denying any further disallowances and granted NPC the authority to increase the deferred energy cost recovery charge for the month of June 2002 by one cent per kilowatt-hour. This increase accelerated the recovery of the deferred balance by approximately $16 million for the month of June 2002 only. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances.
NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE
On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. A hearing is scheduled to begin on April 7, 2003 and a ruling is required by May 15, 2003.
Intervenors filed their direct testimony on March 7, calling for disallowances between approximately $83 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Some Intervenors' testimony, in the current case, argue in favor of this disallowance based on the last Deferred order but did not quantify their proposals and in some cases would be additive to the ranges stated above. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue.
While all Intervenors call for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period.
NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS
On November 14, 2002, NPC filed an application with the PUCN seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, NPC requested a one-year recovery of approximately $1.9 million. This would result in an average 0.12% increase in present rates. NPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2002 deferred energy case discussed above. NPC subsequently negotiated a settlement agreement with the intervenors (PUCN Staff and Bureau of Consumer Protection), which is expected to be approved by the PUCN coincident with its 2002 Deferred Energy ruling. With the exception of a small disallowance ($14,673), the agreement called for approval of NPC's request for cost recovery.
SIERRA PACIFIC POWER COMPANY 2001 GENERAL RATE CASE
On November 30, 2001, as required by law, SPPC filed an application with the PUCN seeking an electric general rate increase. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of $15.9 million representing an overall 2.4% rate increase. The application also sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%.
On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case, and SPPC was not granted a carrying charge on these deferred costs. SPPC is currently planning to renew its request to recover these costs in a general rate case to be filed by the fourth quarter of 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.
Various parties to the case had filed petitions for reconsideration of the order. On July 18, 2002, the PUCN issued a final decision on the petitions for reconsideration, clarifying issues contained in its original order. As a result of the clarifications, SPPC was ordered to change the total annual electric revenue decrease from $15.3 million to $15.8 million.
On August 19, 2002, Barrick Goldstrike Mines (Barrick) filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision. A stipulation of the parties was subsequently approved by the PUCN. In accordance with the stipulation, SPPC has reduced the electric service rates charged to Barrick and is accruing the reductions in a deferred account as a regulatory asset. The stipulation calls for a review of the subject rates during the next general rate case and a pass through of the deferred costs to either Barrick or other customers.
SIERRA PACIFIC POWER COMPANY 2002 DEFERRED ENERGY CASE
On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs.
On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges.
On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing has been scheduled for October 2003.
On August 22, 2002, the BCP from the Nevada Attorney General's Office also filed a lawsuit in the First District Court of Nevada seeking to set aside the decision of the PUCN so that SPPC is not authorized to reflect in rates any costs for fuel and purchased power which may have been imprudently incurred. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in these matters.
SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE
On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and
November 30, 2002. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003.
SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS
On January 14, 2003, SPPC filed with the PUCN an application seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, SPPC requested a one-year recovery of approximately $0.9 million. This would result in an average 0.12% increase in present rates. SPPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2003 deferred energy case discussed above.
CUSTOMERS FILE UNDER AB 661 (NPC, SPPC)
Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001, allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide transmission, distribution, metering and billing services to such customers. AB 661 requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the Utility. These regulations place certain limits upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities. AB 661 permitted customers to file applications with the PUCN beginning in the fourth quarter of 2001, and customers could begin to receive service from new suppliers by mid-2002.
On January 10, 2002, Barrick, an approximately 130 MW SPPC customer, filed a notice of intent with the PUCN indicating their desire to exit the system of SPPC and to purchase energy, capacity and ancillary services from a provider other than SPPC. Barrick has not yet filed a formal application with the PUCN but could do so at any time. Under the law, the earliest departure date would be 180 days after the application is filed.
During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and Park Place Entertainment filed separate applications with the PUCN to exit the system of NPC and to purchase energy, capacity and ancillary services from a provider other than NPC. The loads of these customers aggregate 260 MW on peak. Hearings on the applications of all the customers except Park Place Entertainment were completed on July 19, 2002, and the PUCN issued its decision on July 31, 2002. In its decision, the PUCN approved the applications of these customers to choose an energy supplier other than NPC. The earliest any of these customers could have begun taking energy from an alternative provider was November 1, 2002. If all five customers whose applications were approved had left its system on November 1, 2002, NPC would have incurred an annual estimated loss in revenue of $48 million, which would be offset by an estimated reduction in costs, primarily for fuel and purchased power, of $46 million with the difference being paid by exit fees from the departing customers. These customers would also be responsible for their share of balances in NPC's deferred energy accounts until the time they left and would have continued to pay their share of these balances after they left. For example, if all five customers whose applications were approved had left the system on November 1, 2002, their remaining share of NPC's previously approved deferred energy balance is estimated to have been $27 million.
Additionally, these departing customers would have been responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001, to their date of departure. They also would have remained accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also have benefited from any refunds that might be granted on power contracts under review with the FERC.
A hearing on the application of Park Place Entertainment was held on August 2, 2002, and on August 12, 2002, the PUCN approved the application with terms and conditions similar to those described above for the aforementioned five customers.
All of the customers approved for departure were to address compliance items in their PUCN orders. None of these customers submitted the compliance items required by the PUCN on the required schedule and none of these customers provided official notice of departure. As a result, on February 11, 2003, these applications were closed. All of these customers have submitted new applications requesting a departure date of July 1, 2003. Decisions on these applications are anticipated by the end of the first quarter 2003.
Monte Carlo, Riviera, Imperial Palace, Stratosphere, and Potlach, have also filed applications for departure in June or July of 2003. Decisions on these applications, other than the Riviera and Imperial Palace, are also anticipated by the end of the first quarter 2003.
On January 29, 2003, stipulations on the applications of the Imperial Palace and the Riviera were filed with the PUCN adopting most of the provisions that were previously decided in the PUCN's decision on July 31, 2002 with the exception of how the base tariff general rate (BTGR) and the base tariff energy rate (BTER) effects will be addressed in the computation of the exit fees and the related accounting treatment. On February 3, 2003, the PUCN held hearings on the applications and stipulations. On February 27, 2003, the PUCN issued an order approving the parties' stipulation as filed. Additionally, the PUCN ordered that the BTGR revenue impact associated with these customers leaving the system be addressed in NPC's next general rate case (GRC) following the customers departure and all BTER benefits of these customers leaving the system flow through the deferred energy process and accrue to remaining customers. The amount of BTGR revenues that would be lost as a result of these customers' departing, until NPC files its next GRC, is estimated at $500 thousand annually. The Imperial Palace and the Riviera are still required to pay their share of NPC's previously approved deferred energy balance, which is estimated at $1.7 million at June 1, 2003, their estimated departure date. Additionally, these customers will be responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001 through June 1, 2003, which is currently estimated at $541 thousand. They also will remain accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also benefit from any refunds that might be granted on power contracts under review with the FERC. On March 14, 2003, NPC filed for reconsideration of the February 27, 2003 PUCN order regarding the accounting for and computation of exit fees.
Any customer who departs NPC's system and later decides to return to NPC as their energy provider will be charged for their energy at a rate equivalent to NPC's incremental cost of service. A stipulation regarding the incremental cost of service tariff is currently pending before the PUCN.
NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY
On April 26, 2002, Nevada Power filed with the PUCN an application seeking additional finance authority. In the application, NPC asked for authority to issue secured long-term debt in an aggregate amount not to exceed $450 million through the period ending 2003. On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order requires NPC, if it is able, to issue the $50 million of remaining authorized short-term debt, before it issues any long-term debt authorized by the order. Moreover, the order provides that, if NPC is able to issue short-term
debt at any point prior to September 1, 2002 (whether or not the issuance of short-term debt actually occurs), the amount of long-term debt authorized by the order will be automatically reduced to $250 million. The PUCN order also provides that NPC will bear the burden of demonstrating that any financings undertaken pursuant to the order, including any determination made regarding the length of such commitment, the type of security or rate, is reasonable. Until such time as the Order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC reaches a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect.
On July 3, 2002, the BCP of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt.
ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC)
On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application, SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate (BPGR) and an increase in its Balancing Account Adjustment charge (BAA) by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below.
On December 23, 2002, the PUCN voted to decrease rates for SPPC's natural gas customers by approximately 3% ($3.2 million plus applicable carrying charges). The PUCN noted that the decrease was due primarily to lower gas costs for SPPC and to a disallowance for imprudent hedging practices. The PUCN adjusted SPPC's costs related to fixed floating hedging contracts. The PUCN also disallowed an alleged $0.7 million customer subsidy under an SPPC optional gas tariff. The new BAA is $0.12330 (which includes a three-year amortized BAA of $0.09998 from Docket 01-6050 and the current annual amortized BAA of $0.02332). SPPC had requested a total BAA of $0.15419. A BPGR of $0.61059 per therm was approved, a reduction from the previous BPGR of $0.66480. The new rates were implemented January 1, 2003.
SPPC has filed a petition for reconsideration of the decisions to disallow the $3.2 million hedging costs and the $0.7 million alleged customer subsidy. On February 6, 2003, the PUCN granted the petition for reconsideration and a decision is expected by the end of the first quarter 2003.
LIQUID PETROLEUM GAS COST ADJUSTMENT (SPPC)
On July 1, 2002, SPPC filed an application to adjust rates for its liquid petroleum gas (LPG) distribution company. In the application, SPPC has asked for an increase of $0.04133 to its current LPG rate and a decrease in its BAA by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the annual Purchased Gas Cost Adjustment above.
The LPG and BAA rates were approved December 23, 2002, and resulted in no change in the overall level of rates.
CALIFORNIA MATTERS (SPPC)
RATE STABILIZATION PLAN
SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the CPUC a Rate Stabilization Plan, which includes two phases. Phase One, which was also filed June 29, 2001, is an emergency electric rate increase of $10.2 million annually or 26%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing conference was held, and a procedural order was established. On September 27, 2001, the Administrative Law Judge (ALJ) issued an order stating that no interim or emergency relief could be granted until the end of the "rate freeze" period mandated by the California restructuring law for recovery of stranded costs. In accordance with the ALJ's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. On December 5 and 11, 2001, hearings were held and on January 11, 2002 and January 25, 2002, opening briefs and reply briefs were filed. On July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. The increase of $10 million or 26% is applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance-based, rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually.
On December 19, 2002, SPPC filed an amendment to the Phase Two application reducing the requested increase by $4.1 million to $4.8 million or 9.2% annually. SPPC agreed to make certain changes to the application and file the amendment following discussions with the CPUC Office of Ratepayer Advocates. In February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony proposing to reduce SPPC's request by $3.2 million resulting in a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal testimony. Hearings are scheduled to begin on April 9, 2003, and a decision by the CPUC is expected in late 2003.
CALIFORNIA ASSEMBLY BILL 1235
On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6X) that prevented private utilities from selling any power plants that provide energy to California customers until 2006. AB 1235 was effective September 24, 2002, and provides an exemption for the four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of the sale of its water business in June 2001.
On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies to this proceeding and SPPC must supplement the application with a certified environmental document. SPPC has begun informal discussions with the CPUC on the environmental issues and cannot yet predict the outcome of this proceeding.
FERC MATTERS (NPC, SPPC)
FERC 206 COMPLAINTS
In December 2001, the Utilities filed 10 wholesale purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking to reduce prices of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The Utilities negotiated a settlement with Duke Energy Trading and Marketing, but were unable to reach agreement in bilateral settlement discussions with other respondents.
The Utilities have already paid the full contact price for all power actually delivered by these suppliers, but are contesting claims made by their terminated power suppliers, including Enron.
Hearings concluded on October 24, 2002, and an initial decision was issued by the Administrative Law Judge (ALJ) overseeing the proceedings on December 19, 2002. The ALJ stated that the Utilities' complaints did not meet the public interest standard of proof, which the ALJ believed applied to the reformation of the Utilities' contracts. The Utilities and others, including the PUCN, have filed Briefs on Exception to the ALJ's Initial Order with the FERC. If the initial order is not modified by the ALJ, it will be reviewed by the full FERC in the second quarter of 2003.
On March 26, 2003, the Staff of the FERC (FERC staff) concluded that supply-demand imbalance, flawed market design and inconsistent rules made significant market manipulation possible in the Western states in 2000 and 2001. The FERC has not decided how or if this manipulation impacted NPC's and SPPC's claims.
Additionally, the FERC staff recommended that certain market participants identified in the Cal ISO Report released January 6, 2003, including SPPC, be directed to show cause why their behavior did not constitute gaming in violation of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it was unclear as to the reason SPPC received certain revenues in the amount of $6,391. The total revenues for all companies for which the FERC staff recommended show cause orders is approximately $2.8 million. SPPC was one of the over 30 market participants included in the FERC staff's recommendation. The FERC has not yet decided whether to issue a show cause order to SPPC or to any of the other companies identified by the FERC staff. The FERC staff also recommended that the Cal ISO fully explain the screen that was used to identify the subject transactions and that the information should be made available to the public.
OPEN ACCESS TRANSMISSION TARIFF
On September 27, 2002, the Utilities filed with the FERC a revised Open Access Transmission Tariff (OATT) designated as Docket No ER02-2607-000. The purpose of the filing was to implement changes that are required to implement retail open access in Nevada. The Utilities requested the changes to become effective November 1, 2002, the date retail access was scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature.
On October 11, 2002, the Utilities filed with the FERC, revised rates, terms, and conditions for ancillary services offered in the OATT designated Docket No. ER03-37-000. On November 25, 2002, the FERC suspended the rates in Docket No. ER03-37-000 for a nominal period and made them effective subject to refund on January 1, 2003, as requested by the Utilities.
On November 21, 2002, the FERC suspended the revised OATT in Docket No. ER02-2607-000 for a nominal period, made it effective subject to refund, set certain issues for hearing, and directed the Utilities to
make a compliance filing. The compliance filing was submitted on December 23, 2002. This order additionally established hearing procedures and consolidated the two dockets for hearing. On March 11, 2003, all parties to these dockets reached a settlement in principle regarding all issues. The settlement agreement is expected to be filed with the FERC on or before May 2003.
REGIONAL TRANSMISSION ORGANIZATION
NPC and SPPC are members of the utility groups that are forming a proposed regional transmission organization (RTO West) and a proposed independent transmission company (TransConnect). On March 29, 2002, RTO West submitted to the FERC a Stage II compliance filing and supplemental material, which provided details of the formation of the RTO. RTO West, as proposed, would be a non-profit independent system operator of the regional transmission grid, governed by an independent board of directors. This filing was made in compliance with FERC Order 2000, which required all investor-owned utilities in the United States who own interstate transmission to file a proposal to participate in an RTO or an explanation of efforts and plans to participate in an RTO. On November 13, 2001, TransConnect submitted to the FERC a Stage II compliance filing and supplemental material, which provided details of the formation of the ITC - a member of RTO West. On September 18, 2002, and September 23, 2002, FERC gave conditioned approval for both RTO West and TransConnect phase II filings. Both organizations remain subject to approvals from state regulators and the board of directors of each member company. The current filing utility members of RTO West are NPC, SPPC, Avista Corporation, British Columbia Hydro & Power Authority, Bonneville Power Administration (BPA), Idaho Power Company, The Montana Power Company, PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. The current filing utility members of TransConnect are NPC, SPPC, Avista Corporation, and Portland General Electric.
STANDARD MARKET DESIGN NOPR
On July 31, 2002, the FERC issued a Standard Market Design Notice of Proposed Rulemaking. The FERC's intent is to standardize the practices and policies followed by all jurisdictional entities in the United States. This proposal is currently being reviewed and evaluated by interested parties. The Utilities have submitted comments on this proposed rule.
ALTURAS INTERTIE
Certain Northern California public power groups have challenged SPPC's filing with the FERC of the interconnection and operating agreements related to the Alturas Intertie in December 1998 and January 1999. The California groups alleged that the potential reduction in imports into California constitutes an impairment of reliability and therefore seek to force reductions in use of the Alturas Intertie during peak periods. SPPC (supported by BPA and PacifiCorp) has filed testimony before the FERC that the Alturas Intertie does not adversely affect reliability and that, under the FERC's Order No. 888, customers in Nevada are entitled to compete with customers in California for transmission capacity in the Pacific Northwest on a first-come, first-served basis. The FERC staff has agreed with SPPC's position on this matter.
The matter was tried by an ALJ in April and May 2000. In 2001, the ALJ agreed with SPPC's position, but imposed a limitation on additional transfer capacity created by future upgrades to the system. The ALJ stated allocation of additional transfer capacity would require agreement among the parties. Both sides have appealed this decision to the full FERC.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt and preferred trust securities obligations. As reflected in the tables that follow, the fair market value of SPR's market-sensitive financial instruments declined approximately 8.5% during 2002 as a result of credit rating downgrades by Standard and Poor's and Moody's. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities.
Expected Maturity Date December 31, 2002
Expected Maturity Date December 31, 2001
(1) Weighted average daily rate for months ended December 31, 2002, and 2001.
COMMODITY PRICE RISK
The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity as well as changes in fuel costs incurred to generate electricity. See Energy Supply in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of the Utilities' purchased power procurement strategies.
The Utilities' efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by a Board of Directors' revised and approved Enterprise Risk Management and Control Policy. That policy created the EROC and made that committee responsible for the overall policy direction of the Utilities' risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies including the Energy Supply Risk Management and Control Policy.
The Utilities' commodity risk management program establishes a control framework based on existing commercial practices. The program creates common predefined risk limits and delineates management responsibilities and organizational relationships. The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities' commercial activities. The program's control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation's compliance with portfolio and credit limits.
The Utilities, through the purchase and sale of the financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with approved Energy Supply Plans. The program has provisions for the systematic identification, quantification, evaluation, and
management of the energy risk inherent in the Utilities' operations and for the preparation of periodic reports to document the Utilities' efforts and to comply with legal and regulatory requirements. The Energy Supply Plans include recommended courses of action to be followed during the three-year period covered by the plan and:
o govern the purchase and sale of fuel and wholesale power and the associated transmission or transportation services;
o include assessments of projected loads and resources, assessments of expected market prices, and, evaluations of relevant supply portfolio options available to the Utilities;
o evaluate the risk attributable to those supply portfolio options; and,
o address the use of financial instruments for hedging in conjunction with energy purchases and sales.
Currently, commodity price increases due to changes in market conditions for purchased fuel and power and natural gas are recovered through the deferred energy accounting mechanism, with no anticipated effect on earnings. Commodity price risk is mitigated by the use of long-term fuel supply agreements, long- term purchase power agreements and derivative instruments such as forwards, options and swaps entered into to meet the anticipated fuel and power needs necessary to satisfy the jurisdictional load requirements of the Utilities. However, the Utilities are subject to regulatory risk related to commodity price changes due to the fact that the PUCN may disallow recovery for any of these costs that it considers imprudently incurred.
CREDIT RISK
The Utilities also monitor and manage credit risk with their trading counterparties. As of December 31, 2002, the Utilities had outstanding transactions with over 50 energy and financial services companies. The Utilities credit risk associated with these transactions was approximately $12 million as of December 31, 2002.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Sierra Pacific Resources Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Sierra Pacific Resources and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Resources and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 20 to the consolidated financial statements, during 2002 the Company changed its method of accounting for goodwill to conform to Statement of Accounting Standards No. 142, Accounting for Goodwill.
Deloitte & Touche LLP
Reno, Nevada February 28, 2003
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholder of Nevada Power Company Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Nevada Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Nevada Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
Deloitte & Touche LLP
Reno, Nevada February 28, 2003
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholder of Sierra Pacific Power Company Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Sierra Pacific Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
Deloitte & Touche LLP
Reno, Nevada February 28, 2003
SIERRA PACIFIC RESOURCES CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
NEVADA POWER COMPANY CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (DOLLARS IN THOUSANDS)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and non-utility operations are as follows:
GENERAL
The consolidated financial statements include the accounts of Sierra Pacific Resources (SPR) and its wholly-owned subsidiaries, Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc. (LOS), Sierra Energy Company dba e-three (e-three), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and, Sierra Gas Holding Company (SGHC). NPC and SPPC are referred to together in this report as the Utilities. All significant intercompany balances and intercompany transactions have been eliminated in consolidation.
NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 59% of the consolidated assets of SPR at December 31, 2002. NPC provides electricity to approximately 669,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy's Nevada Test Site in Nye County. The consolidated financial statements of SPR include the accounts of NPC's wholly owned subsidiaries, Nevada Electric Investment Company (NEICO), NVP Capital I, and NVP Capital III.
SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 35% of the consolidated assets of SPR at December 31, 2002. SPPC provides electricity to approximately 318,000 customers in a 50,000 square mile service area including western, central, and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. The consolidated financial statements of SPR include the accounts of SPPC's wholly owned subsidiaries, Pinon Pine Corporation, Pinon Pine Investment Company, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.
The Utilities' accounts for electric operations and SPPC's accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC).
TGPC is a partner in a joint venture that developed, constructed, and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounts for its joint venture interest under the equity method. e-three provides comprehensive energy services in commercial and industrial markets on a regional basis. SPE markets a package of telecommunication products and services. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada.
Certain reclassifications of prior year information have been made for comparative purposes but have not affected previously reported net income or common shareholders' equity.
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure
of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.
MANAGEMENT'S STATEMENT
SIERRA PACIFIC RESOURCES
SPR, on a stand-alone basis, had cash and cash equivalents of approximately $7.4 million at December 31, 2002, and approximately $179.3 million at February 28, 2003.
Currently, SPR has a substantial amount of debt and other obligations including, but not limited to: $133 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR intends to pay off the remaining principal balance of its Floating Rate Notes due April 20, 2003 with cash currently on hand.
SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and a restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult to continue to operate outside of bankruptcy.
See Note 13, Dividend Restrictions for information regarding the dividend restrictions applicable to NPC and SPPC and Note 17, Commitments and Contingencies for additional information regarding uncertainties that could impact the SPR's liquidity and financial condition.
The provisions that currently restrict dividends payable by NPC or SPPC have adversely affected SPR's liquidity and will continue to negatively impact SPR's liquidity until those provisions are no longer in effect. Management intends to seek a modification of the financial covenant contained in NPC's first mortgage indenture in the near future. The regulatory limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction.
Financing Transactions. On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes have been used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million will be used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003 at maturity, and the remaining approximately $65 million will be available for general corporate purposes, including the payment of interest on SPR's other outstanding indebtedness.
The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR's
common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.20 (the last reported sale price of SPR's common stock on March 17, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $137 million. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt.
If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. For further information regarding the terms of the Convertible Notes, see Note 9, Long-Term Debt.
Effect of Holding Company Structure. Due to the holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders and NPC's and SPPC's preferred security holders. As of December 31, 2002, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.
The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.
NEVADA POWER COMPANY
NPC had cash and cash equivalents of approximately $95 million at December 31, 2002, and approximately $96 million at February 28, 2003.
In addition to anticipated capital requirements for construction, NPC has approximately $355 million of debt maturing in 2003. NPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt.
NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on "negative" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets. Furthermore, if NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition
will be adversely affected. Adverse developments with respect to any one or a combination of the foregoing could make it difficult to continue to operate outside of bankruptcy.
NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2002, $870 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage Bonds, and/or (3) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture.
As of December 31, 2002, NPC had the capacity to issue approximately $1.04 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in NPC's Series E Notes limit NPC's ability to issue additional General and Refunding Mortgage Bonds or other debt. See Note 9, Long-Term Debt for information regarding NPC's Series E Notes. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility. See Note 12, Short-Term Borrowings for information regarding NPC's accounts receivable facility. NPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond.
The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.
SIERRA PACIFIC POWER COMPANY
SPPC had cash and cash equivalents of approximately $88.9 million at December 31, 2002, and approximately $104.2 million at February 28, 2003.
In addition to anticipated capital requirements for construction, SPPC has approximately $101 million of debt maturing in 2003. SPPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt.
SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets. Furthermore, if SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, and is unable to obtain power through other means, SPPC's business, operations and financial condition will be adversely affected. Adverse developments with respect to
any one or a combination of the factors and contingencies set forth above could make it difficult to continue to operate outside of bankruptcy.
SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2002, $420 million of SPPC's General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds, and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture.
At December 31, 2002, SPPC had the capacity to issue approximately $427 million of additional General and Refunding Mortgage securities. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. See Note 9, Long-Term Debt for information regarding SPPC's Term Loan Agreement and Note 12, Short-Term Borrowings for information regarding SPPC's accounts receivable facility. SPPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond.
The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above.
REGULATORY ACCOUNTING AND OTHER REGULATORY ASSETS
The Utilities' rates are currently subject to the approval of the PUCN and, in the case of SPPC, rates are also subject to the approval of the California Public Utility Commission (CPUC) and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers.
In addition to the deferral of energy costs discussed below, significant items to which SPR and the Utilities apply regulatory accounting include goodwill and other merger costs resulting from the 1999 merger of SPR and NPC, generation divestiture costs, and the loss on reacquired debt.
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation.
Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and the Utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Utilities' future financial position and results of operations.
Management periodically assesses whether the requirements for application of SFAS No. 71 are satisfied. The provisions of Assembly Bill 369 (AB 369), signed into law in April 2001, include the repeal of all statutes authorizing retail competition in Nevada's electric utility industry. Accordingly, the Utilities continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses.
The following Other regulatory assets were included in the consolidated balance sheets of SPR as of December 31 (dollars in thousands):
(a) See Note 2, Sierra Pacific Resources and Nevada Power Merger, for additional information about the accounting treatment and regulatory recovery of merger costs. Merger goodwill above represents the portion of total goodwill that has been reclassified to a regulatory asset.
DEFERRAL OF ENERGY COSTS
Nevada and California statutes permit regulated utilities to, from time-to-time, adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect of fluctuations in the cost of purchased gas, fuel, and purchased power.
On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369, which are described in greater detail in Note 3, Regulatory Actions, include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.
AB 369 requires the Utilities to file applications to clear their respective deferred energy account balances at least every 12 months and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances.
NPC utilized deferred energy accounting procedures until August 1, 2000, and resumed those procedures on March 1, 2001. SPPC resumed deferred energy accounting procedures for its natural gas operations as of January 1, 2000, and for its electric operations on March 1, 2001.
The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):
(1) Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs.
(2) Amounts related to terminated suppliers are discussed in Note 17, Commitments and Contingencies.
UTILITY PLANT
The cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage, is charged to accumulated depreciation. The cost of current repairs and minor replacements is charged to operating expenses when incurred.
In addition to direct labor and material costs, certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC).
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AND CAPITALIZED INTEREST
As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, with an offsetting credit to "other income" for the portion representing the cost of equity funds and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC's AFUDC rates used during 2002, 2001 and 2000 were 4.72%, 8.32%, and 8.34%, respectively. SPPC's AFUDC rates used during 2002, 2001 and 2000 were 5.54%, 7.97%, and 7.17%, respectively. As specified by the PUCN, certain projects were assigned a lower AFUDC rate due to specific low-interest-rate financings directly associated with those projects.
DEPRECIATION
Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC, which also approves any changes the Utilities may make to depreciation rates utilized for this property. Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC's depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.0%, 2.94%, and 2.76%. SPPC's depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.33%, 3.29%, and 3.25%, respectively.
IMPAIRMENT OF LONG-LIVED ASSETS
SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist.
CASH AND CASH EQUIVALENTS
Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds.
FEDERAL INCOME TAXES AND INVESTMENT TAX CREDITS
SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR's and each subsidiary's respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. Deferred taxes are provided on temporary differences at the statutory income tax rate in effect as of the most recent balance sheet date.
SPR accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated 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.
For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System.
Investment tax credits are no longer available to the Utilities. The deferred investment tax credits are being amortized over the estimated service lives of the related properties.
REVENUES
Operating revenues include billed and unbilled utility revenues. The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed. These unbilled amounts are also included in accounts receivable.
Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities' current tariffs.
STOCK COMPENSATION PLANS
In December 2002, the FASB released SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. At December 31, 2002, SPR had several stock-based compensation plans which are described more fully in Note 15 "Stock Compensation Plans." SPR applies Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. Had compensation cost for SPR's nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the provisions of SFAS No. 123, SPR's income
applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):
RECENT PRONOUNCEMENTS
See Note 20, Change in Accounting for Goodwill, for a discussion of SPR's implementation of SFAS No. 142.
SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003.
Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost.
Management's methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and, mass asset properties that are replaced or retired frequently would be considered normal maintenance.
Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Management has determined that the present value of NPC's Navajo Asset Retirement Obligation will not have a material effect on the financial position or results of operations of SPR or NPC. SPPC has no significant asset retirement obligations.
The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without
land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard provides guidance on the impairment of long-lived assets and for long-lived assets to be disposed of. The standard supersedes the current authoritative literature on impairments as well as disposal of a segment of a business and was adopted January 1, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, the criteria in Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," will now be used to classify those gains and losses. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. A fundamental conclusion reached by the FASB in this statement is that an entity's commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC.
On January 22, 2003, the FASB directed its staff to prepare a draft of SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." The final draft is expected to be issued in March 2003. The statement will establish standards for accounting for financial instruments with characteristics of liabilities, equity, or both. As such, the NPC obligated mandatorily redeemable preferred trust securities may be classified as a liability once SFAS No. 149 goes into effect. The proposed effective date of SFAS No. 149 is July 1, 2003.
In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees," which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of the Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of December 31, 2002, any guarantees of SPR and its subsidiaries were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries to a third party.
NEVADA POWER COMPANY FINANCIAL STATEMENTS
The accompanying NPC consolidated financial statements for the years ended December 31, 2001 and 2000, have been revised to more clearly present stand-alone financial statements that solely reflect the financial position and results of operations of the legal entity, NPC.
The SPR-NPC merger was treated as a reverse acquisition for accounting purposes, as described in Note 2. As a result, for accounting purposes only, NPC was treated as the acquirer and accordingly, as the parent of SPR. Therefore, post-merger 2001 and 2000 financial statements for NPC have been previously presented as if NPC had a deemed equity investment in SPR. In fact, however, the legal relationship between NPC and SPR is the reverse, with SPR being the legal parent and NPC its wholly owned subsidiary. Management understands that in light of this legal structure, it would be appropriate to present NPC financial statements as NPC-only, without showing any equity investment in SPR.
In the reverse acquisition accounting, NPC appropriately recorded the assets and liabilities of SPR and subsidiaries at fair value, following the guidance in Accounting Principles Board Opinion No.16. The assets and liabilities of NPC, as the accounting acquirer, were appropriately not revalued in the combination.
As noted above, the presentation of the consolidated financial statements of NPC for the years ended December 31, 2001 have been revised. The resulting presentation includes only the assets of NPC to which holders of NPC's securities may look for recovery of their investment and only the financial information used in determining NPC's ability to pay dividends, in calculating NPC's ratio of earnings to fixed charges and in determining compliance with NPC's various financing agreements.
Specifically, the effects of the revision were to eliminate the following items in the NPC financial statements (dollars in thousands):
NOTE 2. SIERRA PACIFIC RESOURCES AND NEVADA POWER MERGER
On July 28, 1999, the merger between SPR and NPC was consummated. The merger was accounted for as a reverse purchase under generally accepted accounting principles, with NPC considered the acquiring entity even though SPR is the surviving legal entity. As a result of the acquisition, goodwill of $331.2 million was recognized which represented the total consideration paid to SPR common shareholders less the fair value of SPR's net assets.
The order issued by the PUCN in Docket No. 98-7023 on December 31, 1998 approving the merger of SPR and NPC directed both SPPC and NPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order instructed both utilities to defer merger transaction costs, transition costs and goodwill costs for a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings. Accordingly, goodwill amortization associated with the regulated Utilities has been reclassified to a regulatory asset.
Also deferred as a result of the PUCN order is $62.2 million in other merger costs as of December 31, 2002. These deferred costs consist of $40.5 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains.
On October 1, 2001 and November 30, 2001, NPC and SPPC, respectively, filed applications with the PUCN for general rate increases that included, among other items, a request to recover deferred merger costs, including goodwill. The PUCN in its decisions on March 27, 2002 and May 28, 2002, for NPC and SPPC, respectively, decided not to make any determination on the recovery of merger costs until a general rate case is filed with a test year ending on or after December 31, 2002. However, the PUCN did instruct NPC and SPPC to continue to recognize these costs as deferred costs without carrying charges.
The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases that are required to be filed in 2003. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial condition, results of operations and cash flows of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy.
NOTE 3. REGULATORY ACTIONS
The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for, generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit integrated resource plans to the PUCN for approval.
Under federal law, the Utilities and Tuscarora Gas Pipeline Company (TGPC) are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities' sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.
As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.
As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air quality, water pollution, solid, hazardous and toxic waste. SPR's Board of Directors has a comprehensive environmental policy and separate board committee that oversees NPC, SPPC, and SPR's corporate performance and achievements related to the environment.
DEFERRED ENERGY ACCOUNTING
On April 18, 2001, the Governor of Nevada signed into law AB 369. AB 369 required the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel.
NEVADA POWER COMPANY 2001 GENERAL RATE CASE
On October 1, 2001, NPC filed an application with the PUCN, as required by law, seeking an electric general rate increase. On December 21, 2001, NPC filed a certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, or an overall 1.7% rate increase. The application also sought a return on common equity (ROE) for NPC's total electric operations of 12.25% and an overall rate of return (ROR) of 9.30%.
On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adjustments increasing accumulated depreciation by $6.7 million, and the inclusion of approximately $5 million of revenues related to SO2 Allowances. The PUCN delayed
consideration of recovery of SPR/NPC merger costs until a future rate case. NPC was not granted a carrying charge on these deferred costs. NPC plans to renew its request to recover these costs in its next general rate case, which will be filed by the fourth quarter 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.
On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. The PUCN modified its original order reversing the adjustment to accumulated depreciation of $6.7 million, and decreased the SO2 allowance revenue amortization to $3.2 million per year. Revised rates for these changes went into effect on June 1, 2002.
NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE
On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law. The application sought to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years.
On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision.
NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE
On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. A hearing is scheduled to begin on April 7, 2003 and a ruling is required by May 15, 2003.
SIERRA PACIFIC POWER COMPANY 2001 GENERAL RATE CASE
On November 30, 2001, as required by law, SPPC filed an application with the PUCN seeking an electric general rate increase. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of $15.9 million representing an overall 2.4% rate increase. The application also sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%.
On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case, and SPPC was not granted a carrying charge on these deferred costs. SPPC is currently planning to renew its
request to recover these costs in a general rate case to be filed by the fourth quarter of 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs.
SIERRA PACIFIC POWER COMPANY 2002 DEFERRED ENERGY CASE
On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs.
On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges.
On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing has been scheduled for October 2003.
SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE
On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and November 30, 2002. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003.
ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC)
On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application, SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate and an increase in its Balancing Account Adjustment charge by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below.
On December 23, 2002, the PUCN voted to decrease rates for SPPC's natural gas customers by approximately 3% ($3.2 million plus applicable carrying charges). The PUCN noted that the decrease was due primarily to lower gas costs for SPPC and to a disallowance for imprudent hedging practices. The PUCN adjusted SPPC's costs related to fixed floating hedging contracts. The PUCN also disallowed an alleged $0.7 million customer subsidy under an SPPC optional gas tariff. The new rates were implemented January 1, 2003.
SPPC has filed a petition for reconsideration of the decisions to disallow the $3.2 million hedging costs and the $0.7 million alleged customer subsidy. On February 6, 2003, the PUCN granted the petition for reconsideration and a decision is expected by the end of the first quarter 2003.
NOTE 4. EARNINGS PER SHARE
The following table outlines the calculation for earnings per share (EPS). The difference between Basic EPS and Diluted EPS is due to common stock equivalent shares resulting from stock options, the employee stock purchase plan, performance shares and a non-employee director stock plan. Common stock equivalents were determined using the treasury stock method. Also see Note 7, Common Stock and Other Paid-in Capital.
(1) The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan and Corporate PIES due to conversion prices being higher than market prices at December 31, 2002.
(2) Because of net losses for the years ended December 31, 2000 and 2002, stock equivalents would be anti-dilutive. Accordingly, Diluted EPS for those periods are computed using weighted average number of shares outstanding before dilution.
NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY
Investments in subsidiaries and other property consisted of (dollars in thousands):
SIERRA PACIFIC RESOURCES
NEVADA POWER
SIERRA PACIFIC POWER
NOTE 6. JOINTLY OWNED FACILITIES
At December 31, 2002, SPR owned the following undivided interests in jointly owned electric utility facilities:
The amounts for Navajo and Mohave include NPC's share of transmission systems and general plant equipment and, in the case of Navajo, NPC'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. NPC's share of
operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Statements of Operations.
NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005.
NPC is currently evaluating and analyzing all of its options with regard to the Mohave project.
SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC's share of direct operation and maintenance expenses for Valmy is included in its accompanying Consolidated Statements of Operations.
NOTE 7. COMMON STOCK AND OTHER PAID-IN CAPITAL
On September 21, 1999, the Board of Directors of SPR (the SPR Board) declared a dividend distribution of one right (an SPR Right) for each outstanding share of SPR common stock to shareholders of record at the close of business on October 31, 1999. By issuing the new SPR Rights, the SPR Board extended the benefits and protections afforded to shareholders under the Rights Agreement, dated as of October 31, 1989, which expired on October 31, 1999. Each SPR Right, initially evidenced by and traded with the shares of SPR Common Stock, entitles the registered holder (other than an "Acquiring Person" as defined in the Rights Agreement) to purchase at an exercise price of $75.00, $150.00 worth of common stock at its then-market value, subject to certain conditions and approvals set forth in the Rights Agreement. If, at any time while there is an Acquiring Person, SPR engages in a merger or other business combination transaction or series of related transactions in which the Common Stock is changed or exchanged or 50% or more of its assets or earning power is transferred, each SPR Right (not previously voided by the occurrence of a Flip-in Event, as described in the Rights Agreement) will entitle its holder to purchase, at the SPR Right's then-current Exercise Price, common stock of such Acquiring Person having a calculated value of twice the SPR Right's then-current Exercise Price. The SPR Rights are not exercisable until the Distribution Date and expire on October 31, 2009, unless previously redeemed by SPR. Following an SPR Distribution Date, the SPR Rights will trade separately from the SPR Common Stock and will be evidenced by separate certificates. Until an SPR Right is exercised, the holder thereof will have no rights as a shareholder of SPR, including, without limitation, the right to receive dividends. The purpose of the plan is to help ensure that SPR's shareholders receive fair and equal treatment in the event of any proposed hostile takeover of SPR.
On August 15, 2001, SPR completed a public offering of 23,575,000 shares of its common stock, yielding net proceeds of approximately $340 million, all of which were contributed to NPC as an additional equity investment.
On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate Premium Income Equity Securities (PIES).
Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder's obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes pledged as collateral.
Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations.
The purchase contracts are forward transactions in SPR common stock. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other deferred credits, with a corresponding reduction to Other paid-in capital. See further discussion regarding these senior notes and the purchase contract adjustment payments at Note 9, Long-Term Debt. Upon settlement of a purchase contract, SPR will receive the stated amount of $50 on the purchase contract and will issue the required number of shares of common stock. The stated amount received will be credited to stockholders' equity and allocated between the Common stock and Other paid-in capital accounts.
Prior to the issuance of common stock upon settlement of the purchase contracts, SPR expects that the PIES will be reflected in SPR's earnings per share calculations using the treasury stock method. Under this method, the number of shares of common stock used in calculating earnings per share is deemed to be increased by the excess, if any, of the number of shares of common stock issuable upon settlement of the purchase contracts over the number of shares that could be purchased by SPR in the market at the average closing price during the relevant period using the proceeds receivable upon settlement.
As of December 31, 2002, 3,441,166 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees' Stock Purchase Plan (ESPP), and Executive Long-Term Incentive Plan (ELTIP). The ELTIP for key management employees allows for the issuance of SPR's common shares to key employees through December 31, 2003, which can be earned and issued after December 31, 2003. This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares and bonus stock. SPR also provides an ESPP to all of its employees meeting minimum service requirements. Employees can choose twice each year (offering date) to have up to 15% of their base earnings withheld to purchase SPR common stock. The purchase price of the stock is 90% of the market value on the offering date or 100% of the market price on the execution date, if less. The Non-employee Director Stock Plan provides that a portion of SPR's outside directors' annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance with Accounting Principles Board Opinion Number (APB No.) 25. In addition, in 1996 the Company eliminated its outside director retirement plan and converted the present value of each director's vested retirement benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director's phantom account. The value of these accounts is issued in stock or cash, at the election of the Board, at the time the Director leaves the Board.
The changes in common stock and additional paid-in capital for 2002, 2001 and 2000, are as follows (dollars in thousands):
SUBSEQUENT EVENTS
In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933.
On February 5, 2003, SPR acquired 2,095,650 of its PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933. Of the shares issued in these transactions, 7,565,506 shares represented the then current conversion value of the PIES.
On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually in arrears. SPR may redeem some or all of the notes for cash at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities that are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes.
The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes in shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the trading price of SPR's common stock for a certain period prior to conversion. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval not later than 180 days after the date of issuance of the Convertible Notes for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes.
NOTE 8. PREFERRED STOCK AND PREFERRED TRUST SECURITIES
SIERRA PACIFIC POWER COMPANY
PREFERRED STOCK
SPPC's Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate amount of 11,780,500 shares of preferred stock at any given time.
SPPC's preferred stock is superior to SPPC's common stock with respect to dividend payments (which are cumulative) and liquidation rights.
On January 30, 2003, a dividend of $975,000 ($0.4875 per share) was declared on SPPC's preferred stock. The dividend is payable on March 1, 2003, to holders of record as of February 14, 2003.
The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year:
NEVADA POWER COMPANY
PREFERRED TRUST SECURITIES
On April 2, 1997, NVP Capital I (Trust), a wholly owned subsidiary of NPC, issued 4,754,860, 8.2% preferred trust securities (QUIPS) at $25 per security. NPC owns all of the Series A common securities, 147,058 shares issued by the Trust for $3.7 million. The QUIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the QUIPS and the common securities and using the proceeds thereof to purchase from NPC its 8.2% Junior Subordinated Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March 31, 2046, under certain conditions, in a principal amount of $122.6 million. The sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. Interest payments made by NPC in respect of the QUIPS are sufficient to provide the trust with funds to pay the required cash distribution on the QUIPS and the common securities of the trust. The Series A QUIPS are subject to mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS at maturity or their earlier redemption in an amount equal to the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption. NPC's obligations provide a full and unconditional guarantee of the Trust's obligations under the QUIPS. Financial statements of the Trust are consolidated with NPC's. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC's guarantee of the Trust's obligations is full and unconditional. The $118.9 million in net proceeds was used for general corporate utility purposes and the repayment of short-term debt.
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of Nevada Power Company, issued 2,800,000, 7.75% Cumulative Trust Issued Preferred Securities (TIPS) at $25 per security. NPC owns the entire common securities, 86,598 shares issued by the Trust for $2.2 million. The TIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the TIPS and the common securities and using the proceeds thereof to purchase from NPC its 7.75% Junior Subordinated Deferrable Interest Debentures due September 30, 2038, extendible to September 30, 2047, under certain conditions, in a principal amount of $72.2 million. The sole asset of the Trust is the deferrable interest debentures. Holders of the TIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. Interest payments by NPC in respect of the Junior Subordinated Deferrable Interest Debentures are sufficient to provide the trust with funds to pay the required cash distributions on the TIPS and the common securities of the trust. The TIPS are subject to mandatory redemption, in whole or in part, upon repayment of the deferrable interest debentures at maturity or their earlier redemption in an amount equal to the amount of related deferrable interest debentures maturing or being redeemed. The TIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption. NPC's obligations provide a full and unconditional guarantee of the Trust's obligations under the TIPS. Financial statements of the Trust are consolidated with NPC's. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC's guarantee of the Trust's obligations is full and unconditional. The $70 million in net proceeds was used for general corporate utility purposes including the repayment of short-term debt.
The following table indicates the principal amount and number of shares of NPC preferred trust securities outstanding at December 31 of each year:
SIERRA PACIFIC RESOURCES
SPR has issued neither preferred stock nor preferred trust securities.
NOTE 9. LONG-TERM DEBT
Substantially all utility plant is subject to the liens of NPC's and SPPC's indentures under which their First Mortgage bonds and General and Refunding Mortgage bonds are issued.
NEVADA POWER COMPANY
On May 24, 2001, NPC issued $350 million of its 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of NPC's Indenture of
Mortgage dated as of October 1, 1953. On January 29, 2002, NPC exchanged these bonds for identical bonds, registered under the Securities Act of 1933.
On June 12, 2001, $150 million of NPC's floating rate notes matured and were paid in full.
On August 20, 2001, $100 million of NPC's floating rate notes matured and were paid in full.
On September 20, 2001 and October 15, 2001, NPC issued an aggregate total of $210 million of 6% unsecured notes due September 15, 2003. Interest on the notes is payable on March 15 and September 15 of each year. These notes are not entitled to any sinking fund and are non-callable.
On October 18, 2001, NPC issued $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003.
On May 13, 2000, NPC issued a General and Refunding Mortgage Bond, Series D, due April 15, 2004, in the principal amount of $130 million, for the benefit of the holders of NPC's 6.20% Senior Unsecured Notes, Series B, due April 15, 2004. The Senior Unsecured Notes Indenture required that in the event that NPC issued debt secured by liens on NPC's operating property, in excess of 15% of its Net Tangible Assets or Capitalization (as both terms are defined in the Senior Unsecured Notes Indenture), NPC would equally and ratably secure the Senior Unsecured Notes. NPC triggered this negative pledge covenant on April 23, 2002, when it borrowed certain amounts under its secured credit facility.
On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage Bonds in the aggregate principal amount of $15 million.
On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for net proceeds of $235.6 million. The Series E Notes, which were issued with registration rights, were exchanged for registered notes in January 2003. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes. The Series E Notes will mature October 15, 2009.
As discussed in Note 13, Dividend Restrictions, NPC's Series E Notes limit the amount of dividends that NPC may pay to SPR. The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers.
If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.
Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest.
SIERRA PACIFIC POWER COMPANY
On April 27, 2001, Washoe County, Nevada issued for SPPC's benefit $80 million of Water Facilities Refunding Revenue Bonds, Series 2001, due March 1, 2036. The bonds bear interest at a term rate of 5.75% per annum from their date of issuance to April 30, 2003. Beginning May 1, 2003, the method of determining the interest rate on the bonds may be converted from time to time in accordance with the related Indenture so that such bonds would, thereafter, bear interest at a daily, weekly, flexible, term or auction rate. The bonds were issued to refund $80 million of Washoe County variable rate Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 on April 30, 2001. On June 11, 2001, SPPC completed the sale of its water business assets including the Project financed by the sale of the bonds. Although SPPC no longer owns the Project, SPPC will continue to bear the obligations and payments for the bonds under the terms of the Financing Agreement dated as of March 1, 2001, between SPPC and Washoe County, Nevada. These bonds will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest.
On May 24, 2001, SPPC issued $320 million of its 8.00% General and Refunding Mortgage Bonds, Series A, due June 1, 2008. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of SPPC's Indenture of Mortgage dated as of December 1, 1940. On January 29, 2002, SPPC exchanged these bonds for identical bonds, registered under the Securities Act of 1933.
On June 12, 2001, $200 million of SPPC's floating rate notes matured and were paid in full. The floating rate notes were issued on June 9, 2000, and the net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, and the remaining proceeds were used to reduce the amount of SPPC's commercial paper outstanding under the program established in July 1999.
On December 17, 2001, $17 million of SPPC's MTN Series D matured and were paid in full.
On May 23, 2002, SPPC satisfied its obligations with respect to its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended.
On October 30, 2002 SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a $150 million Series B General and Refunding Mortgage Bond.
As discussed in Note 13, Dividend Restrictions, SPPC's Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. SPPC's Term Loan Agreement also requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) ..600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal
quarter thereafter. As of December 31, 2002, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005.
SIERRA PACIFIC RESOURCES
On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate PIES. Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder's obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes.
Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. See further discussion regarding the forward stock purchase contract at Note 7, Common Stock And Other Paid-In-Capital.
Each holder of Corporate PIES is entitled to receive quarterly payments consisting of purchase contract adjustment payments and interest on the senior unsecured notes. The Corporate PIES have a combined rate of 9.0%, which is comprised of the coupon on the senior note of 7.93% and the stated rate of the purchase contract adjustment payments of 1.07%. Interest on the senior unsecured notes began to accrue on November 16, 2001, and quarterly interest payments will be made each quarter beginning with the first payment, which was made on February 15, 2002. All senior unsecured notes will be remarketed beginning on August 10, 2005, up to and including November 1, 2005, and, if necessary, on November 9, 2005, unless holders of senior notes that are not part of a Corporate PIES elect not to have their senior notes remarketed. Upon remarketing, the interest rate will be reset and the senior notes will accrue interest at the reset rate after the remarketing settlement date. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations. If any senior notes remain outstanding after the Purchase Contract Settlement Date, SPR will pay interest payments on those senior notes until their maturity on November 15, 2007.
Purchase contract adjustment payments will accrue from November 16, 2001. Holders received the first quarterly purchase contract adjustment payments of $0.1323 per unit ($913,000 in aggregate) on February 15, 2002, and will receive payments of $0.1338 per unit ($923,000 in aggregate) for each subsequent quarter. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other Deferred Credits, with a corresponding reduction to Other Paid-in-Capital. As of December 31, 2002, the purchase contract adjustment payment liability was $10.5 million.
On April 20, 2002, $100 million of SPR's floating rate notes matured and were paid in full.
In January 2003, SPR acquired $8,750,000 aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act.
On February 5, 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its
common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act.
On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually. SPR may redeem some or all of the notes at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes. See Note 7, Common Stock and Other Paid-In Capital for additional information regarding the terms of the convertible notes.
The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control. The indenture also provides for an event of default if SPR or any of its significant subsidiaries, including NPC and SPPC, fails to pay any indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable.
SIERRA PACIFIC COMMUNICATIONS
Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The promissory note accrues interest at 8% per annum. The first of twelve monthly payments of $3.3 million will commence on July 31, 2003 and continue until June 30, 2004, at which time all outstanding amounts will be due and payable. The promissory note is secured by all of SPC's assets, and prepayments will shorten the length of the loan, but not reduce the installment payments.
As of December 31, 2002 NPC's, SPPC's and SPR's aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (in thousands of dollars):
The preceding table includes obligations related to the following capital lease obligations.
In 1984, NPC 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. Also, NPC has a purchase power contract with Nevada Sun-Peak Limited Partnership. The contract contains a buyout provision for the facility at the end of the contract term in 2016. The facility is situated on NPC property.
Future cash payments for these leases, combined, as of December 31, 2002, were as follows (dollars in thousands):
NOTE 10. TAXES
SIERRA PACIFIC RESOURCES
The following reflects the composition of taxes on income (in thousands of dollars):
The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):
SPR's balance sheets contain a net regulatory asset of $121.3 million at year-end 2002 and $123.0 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $163.9 million at year-end 2002 and $169.7 million at year-end 2001, due to flow-through of the tax benefits of temporary differences. Offset against these amounts are future revenues to be refunded to customers (a regulatory liability), consisting of $16.5 million at year-end 2002 and $18.7 million at year-end 2001, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $26.2 million at year-end 2002 and $28.0 million at year-end 2001 due to unamortized investment tax credits. 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 the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to SPR. These items reduce rate base and, therefore, are benefits passed through to customers. However, because SPR had a net operating loss for tax purposes in 2001 and 2002, some of this benefit could not be utilized (i.e., deferred energy).
In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The remaining income tax losses of $281.9 million as of December 31, 2002, may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income. The carryforward period for net operating losses incurred
is 20 years, and as such the losses incurred in the years ended 12/31/2000, 2001, and 2002 will expire in 2020, 2021, and 2022 respectively.
For the year 2000, all inter-company income tax related payables and receivables due to/from affiliates were paid in full as of 12/31/2000. For the year 2001, SPR owed the following income-tax related balances to affiliates: SPPC $62.1 million and NPC $18.6 million. For the year 2001, SPR had a receivable from all other subsidiaries of $8.5 million. There were no income tax-related inter-company payables and receivables due to/from affiliates for the year ended December 31, 2002.
The consolidated amount of current and deferred tax expense is allocated among SPR and its subsidiaries on a pro rata basis based on separate company taxable income. Any benefit or detriment associated with the consolidation of the income tax return is also allocated among SPR and its subsidiaries one a pro rata basis based on separate company taxable income.
As a large corporate taxpayer, the SPR consolidated group's tax returns are examined by the Internal Revenue Service on a regular basis. The IRS began an audit of the company's consolidated income tax returns in the third quarter of 2002. The years under examination include the separate company returns for NPC and its subsidiaries for 1997 and 1998 and the consolidated returns for SPR and its subsidiaries for 1997 through 2001. The focus of the examination is the net operating losses generated in 2000 and 2001 and carried back to earlier years. The losses reported in 2000 and 2001 are mainly due to the deductions claimed for purchased fuel and purchase power.
The losses claimed on the tax returns are mainly timing differences, and as such, are not expected to cause a material impact on SPR's, NPC's or SPPC's future income statements if it is determined they are allowable in a subsequent period. No Notices of Proposed Adjustment have been received to date.
NEVADA POWER COMPANY
The following reflects the composition of taxes on income (in thousands of dollars):
The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):
NPC's balance sheets contain a net regulatory asset of $88.8 million at year-end 2002 and $91.3 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a
regulatory asset) of $106.1 million at year-end 2002 and $109.9 million at year-end 2001, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $5.4 million at year-end 2002 and $5.9 million at year-end 2001 due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $11.9 million at year-end 2002 and $12.7 million at year-end 2001 due to unamortized investment tax credits. 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 the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to NPC. These items reduce rate base and, therefore, are benefits passed through to customers. However, because NPC had a net tax operating loss in 2002, some of this benefit could not be utilized (i.e., deferred energy).
SIERRA PACIFIC POWER COMPANY
The following reflects the composition of taxes on income (in thousands of dollars):
The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):
SPPC's balance sheets contain a net regulatory asset of $32.4 million at year-end 2002 and $31.8 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $57.8 million at year-end 2002 and $59.9 million at year-end 2001, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $11.1 million at year-end 2002 and $12.8 million at year-end 2001, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $14.3 million at year-end 2002 and $15.3 million at year-end 2001 due to unamortized investment tax credits. 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 the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to SPPC. These items reduce rate base and, therefore, are benefits passed through to customers. However, because SPPC had a net operating loss for tax purposes in 2001 and 2002 some of this benefit could not be utilized (i.e., deferred energy).
NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The December 31, 2002, carrying amount for cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.
The total fair value of NPC's consolidated long-term debt at December 31, 2002, is estimated to be $1.298 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the
current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.56 billion at December 31, 2001. The estimated fair value of NPC's preferred trust securities is $139.8 million at December 31, 2002. The fair value of NPC's preferred securities was estimated to be $181.5 million at December 31, 2001.
The total fair value of SPPC's consolidated long-term debt at December 31, 2002, is estimated to be $851.5 million (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $946.5 million as of December 31, 2001. SPPC's preferred trust securities were redeemed on November 29, 2001.
The total fair value of SPR's consolidated long-term debt at December 31, 2002, is estimated to be $2.66 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPR for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $3.386 billion as of December 31, 2001. The estimated fair value of SPR's consolidated preferred trust securities is $139.8 million at December 31, 2002. The fair value of SPR's consolidated preferred trust securities was estimated to be $181.5 million at December 31, 2001.
NOTE 12. SHORT-TERM BORROWINGS
SIERRA PACIFIC RESOURCES
On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC's $200 million unsecured revolving credit facility, discussed below.
NEVADA POWER COMPANY
On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. As a result of NPC's rate case decisions (discussed in Note 3, Regulatory Events) and the credit downgrades by S&P and Moody's, which occurred on March 29 and April 1, 2002, respectively, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 3, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent for the credit facility.
As of September 30, 2002, NPC had borrowed the entire $200 million of funds available under its credit facility at an average interest rate of 3.72%.
On October 30, 2002, NPC paid in full and terminated its $200 million credit facility and retired its Series C, General & Refunding Bond which secured the credit facility with the proceeds from the issuance of NPC's $250 million aggregate principal amount of 10 7/8% General and Refunding Notes, Series E, due 2009.
On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purchase subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holding, Inc. will be the sole initial committed
purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with NPC's receivables facility, SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the facility.
NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond.
NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. As of December 31, 2002, this facility has not been activated. NPC does not expect to activate this facility in the foreseeable future.
SIERRA PACIFIC POWER COMPANY
On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. Under this credit facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility.
As of September 30, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, and to maintain a cash balance at SPPC at an average interest rate of 3.69%.
On October 31, 2002, SPPC paid off and terminated its $150 million credit facility and retired its Series B, General & Refunding Bond which secured the credit facility with a combination of cash on hand and proceeds from its $100 million Term Loan Facility.
On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with SPPC's receivables facility, SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the facility.
SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would
secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond.
SPPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. As of December 31, 2002 this facility has not been activated.
NOTE 13. DIVIDEND RESTRICTIONS
Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below.
NEVADA POWER COMPANY
First Mortgage Indenture. NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $237 million as of December 31, 2002), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock.
Series E Notes. NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's Premium Income Equity Securities (PIES)) provided that:
o those payments do not exceed $60 million for any one calendar year,
o those payments comply with any regulatory restrictions then applicable to NPC, and
o the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1.
The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment:
o there are no defaults or events of default with respect to the Series E Notes,
o NPC can meet a fixed charge coverage ratio test, and
o the total amount of such dividends is less than:
o the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus
o 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus
o the lesser of cash return of capital or the initial amount of certain restricted investments, plus
o the fair market value of NPC's investment in certain subsidiaries.
If NPC's Series E Notes are upgraded to investment grade by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc. (S&P), these dividend restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade.
Accounts Receivable Facility. On October 29, 2002, NPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above.
Preferred Trust Securities. The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures.
PUCN Order. The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%.
Federal Power Act. NPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends.
SIERRA PACIFIC POWER COMPANY
Term Loan Agreement. SPPC's Term Loan Agreement dated October 30, 2002, which expires October 31, 2005, limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of:
o (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus
o (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period.
Accounts Receivable Facility. On October 29, 2002, SPPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above.
Articles of Incorporation. SPPC's Articles of Incorporation contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock.
Federal Power Act. SPPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends.
NOTE 14. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS
SPR has pension plans covering substantially all employees. Benefits are based on years of service and the employee's highest compensation for a period prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following table provides a reconciliation of benefit obligations, plan assets and the funded status of the plans; the market related value of the plan assets equals fair value. This reconciliation is based on a September 30 measurement date (dollars in thousands).
Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following:
The weighted-average actuarial assumptions as of the measurement date were as follows:
SPR has assumed a health care cost trend rate of 6% for 2002 and all future years.
Net periodic pension and other postretirement benefit costs include the following components:
The assumed health care cost trend rate has a significant effect on the amounts reported. A one percentage point change in the assumed health care cost trend rate would have had the following effects on 2002 service and interest costs and the accumulated postretirement benefit obligation at year end:
NOTE 15. STOCK COMPENSATION PLANS
At December 31, 2002, Sierra Pacific Resources had several stock-based compensation plans which are described below.
SPR's executive long-term incentive plan for key management employees, which was approved by shareholders on May 16, 1994, provides for the issuance of up to 750,000 of SPR's common shares to key employees through December 31, 2003. On June 19, 2000, shareholders approved an increase of 1,000,000 shares for the executive long-term incentive plan. The plan permits the following types of grants,
separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2002, SPR issued nonqualified stock options, performance shares, and restricted stock under the long-term incentive plan.
NON-QUALIFIED STOCK OPTIONS
Nonqualified stock options granted during 2002 were issued at an option price not less than market value at the date of the grants. The grants awarded in January and December vest to the participants 33% per year over a three year period from the grant date; the remaining grants awarded in 2002, vest to the participants 100% one year from the grant date. All grants may be exercised for a period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares, valued at the current market price, or a combination of both.
A summary of the status of SPR's nonqualified stock option plan as of December 31, 2002, 2001, and 2000, and changes during the year is presented below:
1. The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2002, 2001 and 2000:
The following table summarizes information about nonqualified stock options outstanding at December 31, 2002:
Each participant was granted dividend equivalents for all 1996 and prior nonqualified option grants. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted from the date of grant through the exercise date. Dividend equivalents will be forfeited if options expire unexercised.
PERFORMANCE SHARES
In 2002, 2001 and 2000, SPR granted performance shares in the following numbers and initial values:
The actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three-year performance periods. However, 66,100 shares included in the number granted on January 1, 2001, had a one-year performance period, from January 1 through December 31, 2001. The value of all performance share grants, if earned, will be equal to the market value of SPR's common shares as of the end of the performance periods. SPR, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof. The grant of 66,100 shares on January 1, 2001 would have been paid in SPR stock only, however, this grant has not been approved for payment by SPR Board of Directors.
Simultaneous with the grant of the performance shares above, each participant was granted dividend equivalents. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted throughout the performance period. Additionally, in order for dividend equivalents to be paid on the performance shares, certain financial targets must be met. Dividend equivalents will be forfeited if options expire unexercised.
RESTRICTED STOCK SHARES
In 2002, SPR granted 4,500 restricted stock shares at an average grant price of $6.88 per share. The grants vest over 4 years at 25% per year.
During 2001, SPR granted 13,200 shares of restricted stock at an average grant price of $15.67 per share. The grants vest to the participants over 4 years at 25% per year. In 2002, according to the vesting schedule for each grant, 1,750 shares were issued under these grants.
In 2000, SPR granted 16,000 restricted stock shares at a grant price of $16.00 per share. The grant vests over 4 years with 4,000 shares becoming available in 2002, 4,000 shares in 2003, and 8,000 shares in 2004. In 2002, 4,000 shares were issued under this grant, in accordance with the vesting schedule. There is no performance criteria associated with the restricted stock grants, except for continued employment with SPR or its subsidiaries, and all grants were issued with an entitlement to dividend equivalents.
EMPLOYEE STOCK PURCHASE PLAN
Upon the inception of SPR's employee stock purchase plan, SPR was authorized to issue up to 400,162 shares of common stock to all of its employees with minimum service requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase SPR's common stock. The purchase price of the stock is 90% of the market value on the offering commencement date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan SPR sold 73,321, 33,830 and 46,773 shares to employees in 2002, 2001, and 2000, respectively. For purposes of determining the pro forma disclosure, compensation cost has been estimated for the employees' purchase rights on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for 2002, 2001 and 2000:
NON-EMPLOYEE DIRECTOR STOCK
The annual retainer for non-employee directors is $30,000, and the minimum amount to be paid in SPR stock is $20,000 per director. During 2002, 2001 and 2000, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 18,540, 14,573, and 16,915 shares, and $160,000, $210,000, and $250,000.
NOTE 16. DISCONTINUED OPERATIONS AND DISPOSAL OF LONG-LIVED ASSETS
SALE OF WATER BUSINESS
In June 2001, SPPC closed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of the refund described below and net of income taxes of $18.2 million. Included in the sale were facilities for water storage, supply,
transmission, treatment and distribution, as well as accounts receivable and regulatory assets. Accounts receivable consisted of amounts due from developers for distribution facilities. Regulatory assets consisted primarily of costs incurred in connection with the Truckee River negotiated water settlement. Transfer of hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the CPUC. The sale agreement contemplates a second closing for the hydroelectric facilities to accommodate the CPUC's review of the transaction. See Note 3, Regulatory Actions, for a discussion of California legislative and regulatory developments involving the hydroelectric facilities.
Pursuant to a stipulation entered into in connection with the sale and approved by the PUCN, SPPC was required to hold in trust for refund to customers $21.5 million of the proceeds from the sale. The refund was credited on the electric bills of SPPC's former water customers over a fifteen-month period ending November 2002. Under a service contract with TMWA, SPPC provided customer service and billing services to TMWA until August 2002. SPPC continues to provide meter-reading services under a one-year contract renewable in one-year increments by TMWA through 2008.
Revenues from operations of the water business for the years ended December 31, 2001, and 2000 were $23 million and $57 million, respectively. The net income from operations of the water business, as shown in the Consolidated Statements of Operations of both SPR and SPPC, includes preferred dividends of $200,000 and $401,000 for the years ended December 31, 2001, and 2000, respectively. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying consolidated statements of operations.
ASSET SALES
During 2002, the Utilities began pursuing the sale of several non-essential properties. As a result, on January 15, 2003, NPC sold a parcel of land located on Flamingo Road near the Barbary Coast Casino in Las Vegas, Nevada. NPC received cash proceeds of approximately $18 million for the property and retained an easement and other rights necessary to maintain aerial power lines that cross the property. Also, it was agreed that NPC will receive an additional $2.6 million from the sale if the power lines that cross the property are removed and the other rights are relinquished within a five-year period from the date of the sale. The property had been originally transferred to NPC at no cost. The transaction resulted in a gain of $17.7 million, which will be recognized into revenue over a period of three years consistent with the accounting treatment directed by the PUCN.
On November 11, 2002, SPPC agreed to sell land located in Nevada County and Sierra County, California, commonly referred to as Independence Lake. The sale remains subject to review by a third party who retains certain rights, including water rights, after the sale is completed. Also, the sales agreement includes a due diligence review period of 180 days which allows the buyer to review and accept a variety of matters agreed to by both parties. The buyer may terminate the agreement during the review period by providing written notice or by allowing the review period to expire. The agreed upon sales price is $22 million and the transaction is expected to close, subject to the conditions described, in the second quarter of 2003. The carrying value of the property is approximately $108,000.
NOTE 17. COMMITMENTS AND CONTINGENCIES
PURCHASED POWER
At December 31, 2002, NPC has six long-term contracts for the purchase of electric energy. Expiration of these contracts ranges from 2016 to 2024. SPPC has one long-term contract with an expiration date of 2009. Estimated future commitments under non-cancelable agreements (including agreements with Qualifying Facilities (QF's) as of December 31, 2002 were as follows (dollars in thousands):
According to the regulations under the Public Utility Regulatory Policies Act, the Utilities are obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities. As of December 31, 2002, NPC had a total of 305 MWs of contractual firm capacity under contract with four QFs. The contracts terminate between 2022 and 2024. As of December 31, 2002, SPPC had a total of 109 MWs of maximum contractual firm capacity under 15 contracts with QFs. SPPC also has contracts with three projects at variable short-term avoided cost rates. SPPC's long-term QF contracts terminate between 2006 and 2039.
COAL AND NATURAL GAS
The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2003 to 2027. Estimated future commitments under non-cancelable agreements were as follows (dollars in thousands):
LEASES
SPPC has an operating lease for its corporate headquarters building. The primary term of the lease is 25 years, ending 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years.
SPR's estimated future minimum cash payments, including SPPC's headquarters building, under non-cancelable operating leases as of December 31, 2002, were as follows (dollars in thousands):
SALE OF GENERATION ASSETS
As a condition to its approval of the merger between SPR and NPC, the PUCN required the Utilities to file a Divestiture Plan for the sale of their electric generation assets. The PUCN approved a revised Divestiture Plan stipulation in February 2000. In May 2000, an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000, the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison.
In addition, SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an amendment, AB 1235, AB 6 that would allow SPPC to complete the sale of the four hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric Unit is conditioned on the completion of the reconstruction of the Farad dam and flume or assignment of SPPC insurance claim for reconstruction of the dam. The Farad Reconstruction Project is currently in the permitting phase with permits expected by mid-2003.
The sales agreements for the six bundles provided that they terminate eighteen months after their execution unless the parties agreed to an earlier termination. The parties could have extended the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which rendered the contracts impossible to perform, the Utilities engaged in discussions with the buyers of the generation assets regarding the formal termination of the sales agreements and the related energy buyback contracts and interconnection agreements. Those discussions ended without agreement to mutually terminate; however, all the contracts have now terminated in accordance with the contract provisions. As of December 31, 2002, the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2 million at SPPC in order to prepare for the sale of generation assets. The Utilities requested recovery of these costs in each Utility's respective general rate case filings with the PUCN. The PUCN delayed recovery of the divestiture costs to a future rate case request but did grant a carrying charge on the costs until such time as recovery is allowed.
ENVIRONMENTAL
NEVADA POWER COMPANY
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units respectively. The estimated cost of new controls is $1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million.
NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005.
NPC is currently evaluating and analyzing all of its options with regard to the Mohave project.
In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated at $15 million.
At the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required NPC to submit a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in April 2003 at an estimated cost of $150,000.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan, which was approved in June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC
will spend $789,000 to line existing ponds. This project was started in 2002 and is expected to be completed in the first quarter 2003.
In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000 NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. To date, the EPA has not issued additional requests for further information.
NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4.8 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond.
SIERRA PACIFIC POWER COMPANY
In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through December 31, 2002. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites.
LANDS OF SIERRA
LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contamination resulting from an underground fuel tank that has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. The Lahontan Regional Water Quality Control Board has approved closure without additional remediation pending a one-year monitoring period. Final closure is anticipated in December 2003.
OTHER COMMITMENTS AND CONTINGENCIES
In 2000, Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR, and Touch America (formerly Montana Power), formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line between Salt Lake City, Utah, and Sacramento, California. The conduits included in the line are to be sold to AT&T, PF Net Corporation, and STA. Construction is expected to be completed in the second quarter of 2003. The project sustained significant cost overruns and several complaints and mechanics liens have been filed by several contractors and subcontractors, including Williams Communications LLC, Bayport Pipeline Company, and Mastec North America. In September 2002, SPC conveyed its membership interest in STA to Touch America and obtained an indemnity for any liabilities associated with STA, all in exchange for title to several fibers in the line and a $35 million promissory note. Several of the mechanics lienors have named SPC as the owner of the project and Bayport Pipeline has suggested it may amend its complaint to name SPC. SPPC owns a 345 kV transmission line that connects SPPC to the facilities of the Bonneville Power Administration (BPA) near Alturas, California. The Transmission Agency of Northern California (TANC) initiated proceedings in the United States District Court for the Eastern District of California and the United States Court of Appeals for the Ninth Circuit, in each case alleging that BPA's construction of a small portion of the Alturas Intertie violated the Northwest Power Preference Act and is requesting an injunction prohibiting operation of the Alturas Intertie. The case before the Eastern District was dismissed for lack of jurisdiction. The case before the Ninth Circuit was dismissed for TANC's failure to prosecute. In December 1999, TANC filed suit in the Superior Court of the State of California, Sacramento County, seeking an injunction against operation of the Alturas Intertie based on numerous allegations under state law, including inverse condemnation, trespass, private nuisance, and conversion. That case was removed to Federal Court and dismissed by the trial court. The dismissal was affirmed by the Ninth Circuit Court of Appeals, and TANC has now filed a writ of certiorari with the United States Supreme Court. Management believes the final outcome of the appeal is not likely to have a material adverse effect on SPPC's financial position or results of operation.
Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform) and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC. The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets.
On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposit as required. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May
2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The Utilities are unable to predict the outcome of these motions. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. A decision adverse to the Utilities on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity, and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.
On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses.
On September 30, 2002, plaintiffs Stephen A. Gordon and Gail M. Gordon filed a lawsuit in the District Court for Clark County, Nevada, seeking class action status for themselves and all shareholders of SPR against SPR and all of its directors for an alleged breach of fiduciary duty in failing to meaningfully evaluate and consider an alleged offer from the Southern Nevada Water Authority (SNWA) to purchase NPC. The suit seeks extraordinary relief in the form of an injunction requiring the directors to carefully evaluate and consider such offer, formation of a special stockholders committee to ensure fair and adequate evaluation procedures, and for unspecified damages and/or punitive damages in the event the SNWA withdraws its alleged offer before it can be carefully evaluated. SPR intends to vigorously defend the suit. No answer or responsive pleading has yet been required nor have plaintiffs moved for class certification. On September 30, 2002, plaintiff John Anderson filed a virtually identical lawsuit seeking the same relief. On March 21, 2003, plaintiffs' counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph. SPR believes that the cases are without merit and plans to file motions to dismiss in the second quarter 2003.
On October 21, 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth Judicial District Court for Clark County, Nevada, against NPC for fraud and misrepresentation for allegedly overcharging a certain class of customers for energy delivered over the past several years. Plaintiffs allege that NPC fraudulently placed its meters and measured energy delivered at a point prior to passing through transformers during which process a certain amount of energy is dissipated as heat, instead of placing the meters after they pass through the transformer. NPC's motion to dismiss on jurisdictional grounds was denied and NPC is filing a writ before the Nevada Supreme Court and is being joined in by the PUCN, which agrees with NPC that it has exclusive jurisdiction over the suit. NPC denies that the placement of the meters was fraudulent and alleges that placement of the meters was mandated by either or both customer request or applicable tariff.
On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed and served a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which was consolidated in the Superior Court of the State of California. Plaintiffs in that case seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a
competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there is liability, it should be spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides demurrers filed by all the defendants.
On May 3, 2002 and July 3, 2002, respectively, Reliant Resources and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002 and July 30, 2002, Reliant Resources and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement (WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. To date only Idaho has requested mediation of the contracts, which should be completed by the end of second quarter. SPPC alleges that Idaho and Reliant Resources were participants in market manipulation in the West and therefore are not entitled to termination payments under the contract.
In August 2002, El Paso Merchant Energy (EPME) terminated contracts for energy it had delivered to NPC under a program that called for delayed payment of the full contract price. In October 2002, EPME asserted a claim against NPC for $19 million in damages representing the approximate amount unpaid under the contracts. NPC alleges that EPME's termination resulted in net payments due to NPC under the WSPP liquidated damages provision as and for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. Both claims are subject to mandatory mediation under the WSPP, but neither party has requested mediation at the present time.
In connection with claims by their terminated energy suppliers, the Utilities established reserves, included in their Consolidated Balance Sheets in "Contract termination reserves," totaling approximately $313 million, and pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added approximately $228 million and $82 million, respectively, to their deferred energy balances for recovery in rates in future periods. SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations, or cash flows.
See Notes 3, 5, 6, 7, 8, 9, 12, and 14 for additional commitments and contingencies.
NOTE 18. SEGMENT INFORMATION
SPR operates three business segments (as defined by FASB Statement No. 131, Disclosure about Segments of an Enterprise and Related Information) providing regulated electric and natural gas service. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas services are provided in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.
The net assets and operating results of SPPC's water business, divested in 2001, has been reported as discontinued operations in the financial statements for 2001 and 2000.
Operational information of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies. Inter-segment revenues are not material.
The reconciliation of Capital expenditures for 2000 represents capital expenditures of the discontinued water business. The reconciliation of segment assets at December 31, 2002, 2001, and 2000 to the consolidated total includes the following unallocated amounts:
NOTE 19. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge.
However, in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets and liabilities are established to the extent that such derivative gains and losses are recoverable or payable through future rates. Because of this accounting treatment, the Utilities will not apply hedge accounting to their electricity and natural gas derivatives. SPR and the Utilities have adopted cash flow hedge accounting for other derivative instruments not subject to regulatory treatment. The transition adjustments resulting from adoption of SFAS No. 133 related to the other derivative instruments not subject to regulatory treatment was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income of SPR and the Utilities.
SPR's and the Utilities' objective in using derivatives is to reduce exposure to energy price risk and interest rate risk. Energy price risks result from activities that include the generation, procurement and marketing of power and the procurement and marketing of natural gas. Derivative instruments used to manage energy price risk include forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets.
Derivatives used to manage interest rate risk include interest rate swaps designed to moderate exposure to interest-rate changes and lower the overall cost of borrowing. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003.
At December 31, 2002, the fair value of the derivatives resulted in the recording of $30 million, $29 million and $1 million in risk management assets and $74 million, $30 million and $44 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. Also, $45 million, $2 million and $43 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively at December 31, 2002. In addition, for the twelve months ended December 31, 2002, the unrealized gains and losses resulting from the change in the fair value of derivatives designated and qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such amounts will be reclassified into earnings when the related transactions are
settled or terminate. Accordingly, $7.3 million relating to SPR's terminated interest rate swap was reclassified into earnings during the twelve-month period ended December 31, 2002.
The effects of the adoption of SFAS No. 133 on comprehensive income have been reported in the consolidated statements of comprehensive income.
NOTE 20. CHANGE IN ACCOUNTING FOR GOODWILL (SPR, NPC, SPPC)
SFAS No. 142, adopted by SPR, NPC and SPPC on January 1, 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Upon adoption, SPR ceased amortizing goodwill.
SPR's Consolidated Balance Sheet as of December 31, 2002, includes approximately $306 million of goodwill pertaining to regulated operations resulting from the July 28, 1999 merger between SPR and NPC, net of approximately $19.7 million of amortization that has been deferred as a regulatory asset. The PUCN stipulation approving the merger allows for future recovery of this goodwill in rates charged to customers of SPR's regulated utility subsidiaries, NPC and SPPC, provided that NPC and SPPC demonstrate that merger savings exceed merger costs. The amount and timing of the recovery of this goodwill will be determined by the outcome of general rate cases expected to be filed by the Utilities with the PUCN in late 2003. For additional information, see Note 2, SPR and NPC Merger.
SPR's Consolidated Balance Sheet as of December 31, 2001, included approximately $6.2 million of goodwill related to unregulated operations that are reported under the "All Other" segment in Note 18. SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit's goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was used to determine the fair value of each reporting unit of SPR's unregulated operations. The reporting units included in SPR's unregulated operations evaluated for goodwill impairment were LOS, SPC, TGPC, and "Energy" (a reporting unit consisting of Sierra Energy Company dba e-three and Sierra Pacific Energy Company). As a result of the impairment testing, which included revenue forecasts and appraisal of assets, SPR recorded a transitional goodwill impairment charge of approximately $1.7 million ($1.6 million, net of applicable taxes) as a cumulative effect of a change in accounting principle on SPR's Consolidated Statements of Operations for the twelve months ended December 31, 2002. The goodwill impairment recognized by reporting unit was approximately $131,000, $40,000 and $1.5 million for LOS, SPC and "Energy," respectively. Goodwill assigned to TGPC was determined not to be impaired.
The changes in the carrying amount of goodwill for the twelve-month period ended December 31, 2002 are as follows:
A reconciliation of SPR's previously reported net income (loss) and earnings (loss) per share to the amounts adjusted for the adoption of SFAS No. 142 net of the related income tax effect follows:
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
NOTE 21. PINON PINE (SPR, SPPC)
SPPC, through its wholly owned subsidiaries, Pinon Pine Corp., Pinon Pine Investment Co. and GPSF-B, owns Pinon Pine Company, L.L.C. (the LLC). The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under Section 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier, an SPPC-owned combined cycle generation facility and a post-gasification facility to partially cool and clean the syngas, is referred to collectively as the Pinon Pine Power Project (Pinon Pine). Construction of Pinon Pine was completed in June 1998.
Pinon Pine was co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that expired December 31, 2000. The DOE funded approximately $167 million for construction, operation, and maintenance of the project. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $100 million as of December 31, 2002.
To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001, SPPC retained an independent engineering consulting firm, to complete a comprehensive study of the Pinon Pine gasification plant. The scope of the study included evaluation of the potential modifications required to make the facility operational and reliable using several technology scenarios. The evaluation of each scenario included an estimate of the additional capital expenditures necessary for reliable operation of the facility, and the risks associated with that technology.
SPPC received a final report of the study in November 2002. The results of the study identified a number of potential modifications to the facility each with varying degrees of technical risk and cost. Modifications considered to provide the highest probability for successful operation of the facility generally were also estimated to be the highest cost options. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC's and SPR's financial condition and results of operations.
NOTE 22. SUBSEQUENT EVENTS
See Notes 1, 3, 7, 8, 9, 16 and 17 for discussion of events occurring after December 31, 2002.
NOTE 23. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. Dollars are presented in thousands except per share amounts.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) DIRECTORS
The following is a listing of all the current directors of SPR, NPC, and SPPC, and their ages as of December 31, 2002. There are no family relationships among them. Directors serve three-year terms with three (or four) terms of office expiring at each Annual Meeting, or until their successors have been elected and qualified.
DIRECTORS WHOSE TERMS EXPIRE IN 2003:
Edward P. Bliss, 70
Consultant to Zurich Scudder Investments Co; retired partner, Loomis, Sayles & Company, Inc., an investment counsel firm in Boston, Massachusetts. He is also a Director of Seaboard Petroleum, Midland, Texas. Mr. Bliss has served as a Director of SPR since 1991, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Mary Lee Coleman, 65
President of Coleman Enterprises, a developer of shopping centers and industrial parks. She is also a director of First Dental Health. Ms. Coleman has served as a Director of NPC since 1980, and was elected a Director of SPR and SPPC in July 1999.
Theodore J. Day, 53
Senior Partner of Hale, Day, Gallagher Company, a real estate brokerage and investment firm. Mr. Day has served as a Director of SPPC since 1986, of SPR since 1987, and was elected a Director of NPC in July 1999. He is also a Director of the W.M. Keck Foundation.
Jerry E. Herbst, 64
Chief Executive Officer of Terrible Herbst, Inc., a gas station, car wash, convenience store chain and Herbst Supply Co., Inc., a wholesale fuel distributor, both family-owned businesses for which he has worked since 1959. He is also a partner of the Coast Resorts (hotel and casino industry). Mr. Herbst has served as a Director of NPC since 1990, and was elected a Director of SPR and SPPC in July 1999.
DIRECTORS WHOSE TERM EXPIRES IN 2004:
James R. Donnelley, 67
Partner, Stet and Query, Ltd., since June 2000. He is retired from R.R. Donnelley & Sons Company since June 2000, where he served as Vice Chairman of the Board from July 1990 to June 2000 and as a Director of since 1976. Mr. Donnelley was R.R. Donnelley and Sons' Group President, Corporate Development, from June 1987 to July 1990, and Group President, Financial Printing Services Group, from January 1985 to January 1988. He is also a Director of Pacific Magazines & Printing Limited, and Chairman of National Merit Scholarship Corporation. Mr. Donnelley has served as a Director of SPR since 1987, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Walter M. Higgins, 58
Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC and SPPC since August 2000. Mr. Higgins served as Chairman, President and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 2000. He was Chairman, President and Chief Executive Officer of SPR from January 1994 to January 1998. He also served as President and Chief Operating Officer of Louisville Gas and Electric Company from 1991 to November 1993. He is also a director of AEGIS Insurance Services, Inc., NEETF and American Gas Association.
John F. O'Reilly, 57
Chairman and Chief Executive Officer of the law firm of O'Reilly and Ferrario. He is also Chairman and Chief Executive Officer of Business Resource Group, the O'Reilly Gaming Group and related family owned business entities. Mr. O'Reilly is a member of the Community Board of Directors of Wells Fargo Bank Nevada, N.A., a member of the Advisory Council of the UNLV International Gaming Institute, and a member of the UNLV Foundation Board. Mr. O'Reilly is also a member of the Las Vegas Chamber of Commerce Government Affairs Committee, a Board member and Secretary of United Way of Southern Nevada, a Board member of the Nevada Development Authority, Chairman and Chief Executive Officer of Vision 2020. . . TODAY!, Inc., and is a member of the Board of Trustees of Loyola Marymount University in Los Angeles, California. Mr. O'Reilly has served as a Director of NPC since 1995, and was elected a Director of SPR and SPPC in July 1999.
DIRECTORS WHOSE TERM EXPIRES IN 2006:
Krestine M. Corbin, 65
President and Chief Executive Officer of Sierra Machinery, Incorporated, since 1984 and a director of that company since 1980. Ms. Corbin has served as a Director of SPR since 1989, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Clyde T. Turner, 65
Chairman and CEO of Turner Investments, Ltd., a general-purpose investment company, and several special-purpose real estate development companies known as Spectrum Companies in Las Vegas, Nevada. He is also a director of St. Rose Dominican Hospital and CapCure, and a member of the Environmental Advisory Committee to the Board of County Commissions, Clark County, Nevada. Mr. Turner is the retired Chairman and Chief Executive officer of Mandalay Bay. He was elected a Director of SPR, SPPC, and NPC in November 2001.
Dennis E. Wheeler, 60
Chairman, President and Chief Executive Officer of Coeur d'Alene Mines Corporation since 1986. Mr. Wheeler has served as a Director of SPR since 1990, of SPPC since 1992, and was elected a Director of NPC in July 1999.
Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a Director of Lands of Sierra, Inc., Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B. All of the above-listed companies are subsidiaries of Sierra Pacific Resources, with the exception of Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B, which are subsidiaries of Sierra Pacific Power Company.
(b) EXECUTIVE OFFICERS
The following are current executive officers of the companies indicated and their ages as of December 31, 2002. There are no family relationships among them. Officers serve a term which extends to and expires at the annual meeting of the Board of Directors or until a successor has been elected and qualified:
Walter M. Higgins, 58, Chairman, President and Chief Executive Officer, Sierra Pacific Resources
See above description under Item 10(a), "Directors."
Michael W. Yackira, 51, Executive Vice President, Strategy and Policy, Sierra Pacific Resources
Mr. Yackira was elected to his position in January 2003. Previously he was the Vice President and CFO of Mars, Inc. from 2001 to 2002. Prior to that, he was with Florida-based FPL Group, Inc. from 1989 to 2000. His positions during that span included President of FPL Energy, Vice President-Finance and CFO of FPL Group, Senior Vice President-Finance and CFO of Florida Power & Light Co., and Senior Vice President of Corporate Planning and Development. Positions in other industries include GTE Corporation and St. Joe Petroleum, Inc. Mr. Yackira is a certified public accountant.
Donald L. "Pat" Shalmy, 61, President, Nevada Power Company
Mr. Shalmy was elected to his present position in July 2002. He was previously Senior Vice President, NPC since May 2002. Formerly he held the position of Director, Government and Community Relations at Kummer, Kaempfer, Bonner & Renshaw Ltd. He was formerly President of the Las Vegas Chamber of Commerce from 1997 to 2001. From 1979 to 1997 he held various positions with Clark County, Nevada, including Director of Comprehensive Planning and County Manager.
Jeffrey L. Ceccarelli, 47, President, Sierra Pacific Power Company
Mr. Ceccarelli was elected to his present position in June 2000. He previously held the position of Vice President, Distribution Services, New Business, in July 1999 for SPPC and NPC. He was elected Vice President, Distribution Services for SPPC in February 1998. Prior to this, he served as Executive Director, Distribution Services. From January 1996 through January 1998, Mr. Ceccarelli was Director, Customer Operations. A civil engineer, Mr. Ceccarelli has been with SPPC since 1972.
C. Stanley Hunterton, 54, Senior Vice President, General Counsel and Corporate Secretary, Sierra Pacific Resources
Mr. Hunterton was elected to his present position in September 2002, and holds the same positions with SPPC and NPC. He continues to serve as a partner at the law firm of Hunterton & Associates in Las Vegas, Nevada, formed in 1986, handling complex civil litigation. Formerly he held the position of Special Attorney, US Department of Justice, Organized Crime and Racketeering Section, Detroit Strike Force and Las Vegas Strike Force.
John F. Young, 46, Senior Vice President, Energy Supply, Sierra Pacific Power Company and Nevada Power Company
Mr. Young resigned effective February 28, 2003. Mr. Young was elected to the Senior Vice President, Energy Supply position in July 2002. Previously he was President and Chief Executive Officer of Avalon Consulting, a firm specializing in the energy industry. Prior to that, he spent 17 years at Southern Company and its various utility affiliates in Georgia, Florida, Mississippi and Alabama, most recently as Executive Vice
President, Southern Generation. He held various other positions with Southern Company, including Vice President, Business Development, General Manager of Fuel Planning and Procurement, and Vice President, Investor Relations.
Victor H. Pena, 54, Senior Vice President and Chief Administrative Officer, Sierra Pacific Resources
Mr. Pena was elected to his current position in May 2001 and holds the same position at SPPC and NPC. From 1998 to his appointment at SPR, he held various executive positions at AGL Resources, Inc., in Atlanta, Georgia, including Vice President, Business Development, and Vice President, Financial Systems and Controller.
Richard K. Atkinson, 50, Vice President and Chief Financial Officer, Sierra Pacific Resources
Mr. Atkinson was elected to his present position in December 2002 and holds the same position with SPPC and NPC. He was previously Vice President, Treasurer, and Investor Relations Officer since May 2001. He was formerly Treasurer of SPR, SPPC and NPC since December 2000. Previously he held the positions of Assistant Treasurer, Executive Director, Finance, and other positions in the Finance Department. Mr. Atkinson has been with SPPC since 1980.
John E. Brown, 52, Vice President and Controller, Sierra Pacific Resources
Mr. Brown was elected to his current position in July 2002, and holds the same position at SPPC and NPC. He was formerly Controller since May 2001. Previously he held the position of Director, Corporate and Tax Accounting. Mr. Brown has held a variety of positions in SPR, including Compliance Officer, Director, Shareholder Relations, and Director, Internal Audit. Mr. Brown has been with SPR 21 years.
Richard J. Coyle, 35, Vice President and Chief Risk Officer, Sierra Pacific Resources
Mr. Coyle was elected to his present position in July 2002, and holds the same position for SPPC and NPC. He was previously President and Managing Director of Sierra Energy Company and Sierra Pacific Communications since June 2001. Formerly he held the position of Executive Director, Marketing and Operations for Sierra Pacific Energy Company since June 1999. Mr. Coyle has been with NPC since 1994.
Matt H. Davis, 46, Vice President, Distribution, Nevada Power Company
Mr. Davis was elected to his present position in 2002. He previously held the position of Vice President, Distribution Services, at both NPC and SPPC since July 1999. Previously he was Director, System Planning, and Division Director, System Planning and Operations for NPC. Mr. Davis has been with NPC since 1978.
Mary O. Simmons, 47, Vice President, Rates and Regulatory Affairs, Sierra Pacific Power Company and Nevada Power Company
Ms. Simmons was elected to her current position in May 2001. Previously she held the position of Controller for SPR since 1999, and held the same position with SPPC and NPC. Her previous positions include: Director, Water Policy and Planning; Director, Budgets and Financial Services; and Assistant Treasurer, Shareholder Relations for SPR. Ms. Simmons is a certified public accountant and has been with SPR since 1985.
Michael R. Smart, 46, Vice President, Distribution Services, Sierra Pacific Power Company
Mr. Smart was elected to his present position in July 2002. He was previously Vice President, Resource Management since May 2001, for both SPPC and NPC. He was formerly Acting Vice President, Resource Management, since October 2000. Previously he was Executive Director, Resource Management, for SPPC and NPC effective August 1999. Prior to this, from February 1998, he served as Director, Electric Operations, for SPPC. A registered electrical engineer in Nevada and California, Mr. Smart has been with SPPC since 1979 and has held numerous management positions in operations, engineering, and planning.
Jane Crane, 52, Vice President, Human Resources, Sierra Pacific Power Company and Nevada Power Company
Ms. Crane was elected to her present position in July 2002, acting as an outside consultant since April 2002, and joining the Company as Acting Vice President, Human Resources, in May 2002. Formerly she was a consultant in human resources management from April 2000 to April 2002. She previously held the position of Vice President, Human Resources, at ARCO Alaska, Inc. from March 1995 to March 2000. She held various other management positions at ARCO from 1980 to March 1995.
Carol Marin, 51, Vice President, Customer Service, Sierra Pacific Power Company and Nevada Power Company
Ms. Marin was elected to her present position in May 2001. Previously she held the position of Director, Customer Information Systems Project, for both Utilities from August 1999 through May 2001. From 1977 until 1999, Ms. Marin served in a variety of management positions for SPPC in customer service, major accounts, and operations analysis. Ms. Marin has been with SPPC for 25 years.
Julian C. "Jack" Leone, 65, Vice President, Marketing and Communications, Sierra Pacific Power Company and Nevada Power Company
Mr. Leone was elected to his present position in June 2002. He previously held the position of Vice President of Marketing at Caesars Palace since March 2001. Previous to that, he spent two years as a member of Sitrick and Company, a public relations firm based in Los Angeles. From 1984 to 1999, he held a series of senior public relations and marketing positions in the gaming industry, including Caesars World, Inc., MGM Grand Hotel Casino, and Mandalay Bay Resort and Casino.
Susan Brennan, 43, Vice President, Information Services, Sierra Pacific Power Company and Nevada Power Company
Ms. Brennan was elected to her present position in May 2001. Previously she held the position of Executive Director, Customer Service, from August 1999 to May 2001, for NPC. From 1992 to 1999, Ms. Brennan served in various financial and industry restructuring positions. Ms. Brennan has been with NPC for 10 years.
Bob Werner, 65, Vice President, Generation, Sierra Pacific Power Company and Nevada Power Company
Mr. Werner was elected to his present position in July 2002. He was a consultant to NPC from October 2001 until July 2002. From 1997 to 2001, he was previously self-employed as a Consulting Engineer working primarily in the areas of electric generation and coal technology. Prior to that, he held various technical and management positions at PacifiCorp.
Although all outstanding shares of SPPC's common stock are held by SPR and it is SPR's common stock which is traded on the New York Stock Exchange, SPPC has one series of non-voting preferred stock
outstanding and registered under the Securities Exchange Act of 1934 (the Act). As a technical matter, SPPC is thus deemed an "issuer" for purposes of the Act whose officers are required to make filings with respect to beneficial ownership, if any, of those non-voting preferred securities. SPPC's officers, all of whom are currently reporting pursuant to Section 16(a) of the Act with respect to SPR's common stock, have filed reports with respect to SPPC's preferred stock, which reports show no past or current beneficial ownership of such preferred stock.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of the Chief Executive Officer that served in that position during 2002, and each of the four most highly compensated officers for services in all capacities to SPR and its subsidiaries. Also included are two individuals who, although not officers at the end of 2002, warranted inclusion due to compensation levels.
(1) Mark A. Ruelle:
o Mr. Ruelle was President of Nevada Power Company until May 2002; Mr. Shalmy was appointed to that position in July 2002.
o Included in column (c) is a severance payment of $450,000, which represents 1.5 times his annual salary.
(2) Steven C. Oldham:
o Mr. Oldham was Senior Vice President of Energy Supply until his retirement in May 2002. Mr. Young was appointed to that position in July 2002.
o Included in column (c) is a severance payment of $245,000, which represents one year annual salary.
(3) The table below shows those executive perquisites that exceed 25% of the total perquisites listed in column (e) for each named executive.
(4) Restricted Stock Grants:
o As the result of a promotion in 2001, Mr. Ruelle was awarded a restricted grant of 4,000 shares with dividend equivalents. During 2002, after Mr. Ruelle's separation from SPR, this grant was forfeited, and has no value at December 31, 2002.
o Upon his hire in 2001, Mr. Pena was awarded a grant of 4,300 restricted shares with dividend equivalents. At December 31, 2002, the value of the grant was $20,963 at $6.50 per share. The grant will vest over a four year period at 25% per year. In 2002, 1,075 shares from this grant were issued to Mr. Pena, in accordance with the vesting schedule; the year-end value is calculated for the remaining 3,225 shares.
o In 2000, Mr. Higgins was awarded a restricted stock grant of 16,000 shares with dividend equivalents. At December 31, 2002, the value of the grant was $78,000 at $6.50 per share. The grant will vest over a four year period in the following manner:
September 2002 4,000 shares September 2003 4,000 shares September 2004 8,000 shares
In 2002, 4,000 shares from this grant were issued to Mr. Higgins, in accordance with the vesting schedule; the year-end value is calculated for the remaining 12,000 shares.
(5) The Long-term incentive payouts for the three-year periods ended December 31, 2001 and 2002, have not been approved for payment by the SPR Board of Directors.
(6) Amounts for All Other Compensation include the following for 2002:
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
The following table shows all grants of options to the named executive officers of SPR in 2002. Pursuant to Securities and Exchange Commission (SEC) rules, the table also shows the present value of the grant at the date of grant.
1. Under the SPR executive long-term incentive plan, the 2002 grants of nonqualifying stock options were made on January 1, 2002. One-third of these grants vest annually commencing one year after the date of the grant.
2. The total number of nonqualifying stock options granted to all employees in 2002 was 502,380.
3. The hypothetical grant-date present values are calculated under the Black-Scholes Model. The Black-Scholes Model is a mathematical formula used to value options traded on stock exchanges. The assumptions used in determining the option grant date present values listed above include the stock's expected volatility (37.78%), risk free rate of return (5.52%), projected dividend yield (0.00%), the stock option term (10 years), and an adjustment for risk of forfeiture during the vesting period (4 years at 3%). No adjustment was made for non-transferability.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES
The following table provides information as to the value of the options held by the named executive officers at year-end measured in terms of the closing price of Sierra Pacific Resources common stock on December 31, 2002:
(e) Pre-tax gain. Value of in-the-money options based on December 31, 2002, closing trading price of $6.50, less the option exercise price.
LONG-TERM INCENTIVE PLANS-AWARDS IN LAST FIVE YEARS
The executive long-term incentive plan (LTIP) provides for the granting of stock options (both nonqualified and qualified), stock appreciation rights (SARs), restricted stock performance units, performance shares and bonus stock to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR. Goals are established for total shareholder return (TSR) compared against the Dow Jones Utility Index and annual growth in earnings per share (EPS).
The following table provides information as to the performance shares granted to the named executive officers of Sierra Pacific Resources in 2002. Nonqualifying stock options granted to the named executives as part of the LTIP are shown in the table "Option/SAR Grants in Last Fiscal Year."
All levels of awards are made with reference to the number of shares at the time of the grant, the percentages shown below, and the price of each performance share at the time of the grant was $15.58.
1. The threshold represents the level of TSR and EPS achieved during the cycle, which represents minimum acceptable performance and which, if attained, results in payment of 50% of the target award. Performance below the minimum acceptable level results in no award earned.
2. The target represents the level of TSR and EPS achieved during the cycle, which indicates outstanding performance and which, if attained, results in payment of 100% of the target award.
3. The maximum represents the maximum payout possible under the plan and a level of TSR and EPS indicative of exceptional performance which, if attained, results in a payment of 175% of the target award.
PENSION PLANS
The following table shows annual benefits payable on retirement at normal retirement age 65 to elected officers under SPR's qualified and non-qualified defined benefit plans based on various levels of remuneration and years of service which may exist at the time of retirement. The amounts below are based upon a maximum benefit of 60% of final average earnings used under the Supplemental Executive Retirement Plan. This maximum is reduced to 50% for any Officer who became a participant after November 1, 1999.
SPR's noncontributory qualified retirement plan provides retirement benefits to eligible employees upon retirement at a specified age. Annual benefits payable are determined by a formula based on years of service and final average earnings consisting of base salary and incentive compensation. Remuneration for the named executives is the amount shown in columns (c) and (d) of the Summary Compensation Table. Pension costs of the retirement plan, to which SPR contributes 100% of the funding, are not and cannot be readily allocated to individual employees and are not subject to Social Security or other offsets.
The years of credited service under the qualified retirement plan for the named executives are as follows: Mr. Higgins 6.5, Mr. Ruelle 5.8, Mr. Oldham 25.6, Mr. Pena 5.8, Mr. Ceccarelli 28.3 (maximum vesting is 25 years), Mr. Davis 24.5, and Mr. Smart 23.8.
A supplemental executive retirement plan (SERP) and a restoration plan are also offered to the named executive officers. The SERP is intended to ensure the payment of a competitive level of retirement income to attract, retain and motivate selected executives. The Restoration Plan is intended to provide benefits to executive officers whose benefits cannot be paid under the qualified plan because of salary deferrals to the Non-Qualified Deferred Compensation Plan, IRS limitations on compensation that can be recognized by a qualified plan, and IRS limitations on benefits payable from a qualified plan.
The years of credited service under the non-qualified SERP are as follows: Mr. Higgins 9.1, Mr. Ruelle 5.8, Mr. Oldham 25.6, Mr. Pena 5.8, Mr. Ceccarelli 28.3 (maximum vesting is 25 years), Mr. Davis 24.5, and Mr. Smart 0.0.
SEVERANCE ARRANGEMENTS
Individual severance allowance plans exist for the named executive officers which provide for severance pay, payable in a lump sum or by purchase of an annuity, if within three years after a change in control of SPR,
there is a termination of employment by SPR related to such change in control, or a termination of employment by the employee for good reason, in each case as described in the plans. In these circumstances, officers are entitled to a severance allowance not to exceed an amount equal to 36 months of the officer's base salary and any bonus and the continuation for up to 36 months of participation in SPR's group medical and life insurance plans. Change in control is defined in the plans as, among other things, a dissolution or liquidation, a reorganization, merger or consolidation in which SPR is not the surviving corporation, the sale of all or substantially all the assets of SPR (not the sale of a work unit) or the acquisition by any person or entity of 30% or more of the voting power of SPR.
In addition, several merger-related and merger-conditioned severance arrangements have been entered into between SPR and several executives, which are described in Item 13, Certain Relationships and Related Transactions.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Voting Stock
The following table indicates the shares owned by Putnam Investments, the only investor known to Sierra Pacific Resources to be owners of more than 5 percent of any class of its voting stock as of March 11, 2003.
The table below sets forth the shares of Sierra Pacific Resources Common Stock beneficially owned by each director, nominee for director, the Chief Executive Officer, and the four other most highly compensated executive officers. No director, nominee for director or executive officer owns, nor do the directors and executive officers as a group own, in excess of one percent of the outstanding Common Stock of SPR. Unless otherwise indicated, all persons named in the table have sole voting and investment power with respect to the shares shown.
(1) Mr. Ruelle was President of Nevada Power until the appointment of Mr. Donald L. Shalmy to that position in May 2002.
(2) Mr. Oldham was Senior Vice President, Energy Supply of Sierra Pacific Resources until he left the Company in May 2002.
(a) Includes shares/units acquired through participation in the Employee Stock Purchase Plan and/or the 401(k) plan.
(b) The number of shares beneficially owned includes: shares the Executive Officers currently have the right to acquire pursuant to stock options granted under the Executive Long-Term Incentive Plan. Shares beneficially owned pursuant to stock options granted to Messrs. Higgins, Ruelle, Oldham, Pena, Ceccarelli, Davis, Smart and directors and executive officers as a group are 234,030, 0, 89,087, 25,880, 83,150, 40,750, 21,690 shares, and 677,865 respectively.
(c) Included in the shares beneficially owned by the Directors are 81,464 shares of "phantom stock" representing the actuarial value of the Director's vested benefits in the terminated Retirement Plan for Outside Directors. The "phantom stock" is held in an account to be paid at the time of the Director's departure from the Board.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TRANSACTIONS WITH MANAGEMENT
Mr. William E. Peterson became Senior Vice President and General Counsel for Sierra Pacific Resources in 1993 and retired from SPR in October 2002. Following his retirement, Mr. Peterson became associated with Woodburn and Wedge, a law firm in Reno, Nevada in which Mr. Peterson had been a partner until 1993 and at which he performed legal work for SPR and SPPC for 18 years prior to his employment by SPR. Woodburn and Wedge has performed legal services for SPPC since 1920, for NPC since 1999, and for SPR and all of its other subsidiaries from their inception, and continues to perform legal work for SPR. Mr. Peterson's wife, an equity partner in the firm since 1982, has performed work for SPR since 1976 and continues to do so from time to time. In order to facilitate Mr. Hunterton's transition to Mr. Peterson's position and to protect SPR's legal interests during the transition, Mr. Peterson agreed to perform legal work on an as-needed basis from the date of his retirement until the end of the year. Mr. Peterson also agreed to perform a minimum number of hours of legal services for SPR during each of the next three years at his customary hourly rates, subject to satisfactory and timely performance by him within accepted standards of professional practice.
In May 2002, SPR entered into severance and release agreement with four executive officers, including Steve C. Oldham, Senior Vice President, Energy Supply, Douglas R. Ponn, Vice President, Public Policy, Paul Heagen, Vice President, Marketing and Communications, for SPPC and NPC, and Mark A. Ruelle, President of NPC. Under the terms of these agreements, each executive officer received approximately 12 months pay, except in the case of Mr. Ruelle, who received 1.5 times his annual salary, all payable in installments over one year. In addition, each executive officer received continued medical and health coverage under SPR plans at SPR's expense until each became reemployed and obtained comparable coverage, and in the case of Mr. Oldham, an additional payment that was intended to bridge retirement pay until he attains his early retirement age (age 55). SPR also retained Mr. Ponn, formerly head of SPR's legislative effort, to assist SPR through the January to May 2003 legislative session.
CHANGE IN CONTROL AGREEMENTS
SPR has entered into change in control severance agreements with its executive staff, including Walter M. Higgins, Jeffrey L. Ceccarelli, Victor H. Pena, Mary O. Simmons, Susan Brennan, Carol Marin, Richard K. Atkinson, John Brown, Michael R. Smart, Matt H. Davis, Donald L. Shalmy, Julian C. Leone, Michael Yackira, Richard J. Coyle, Bob Werner, and Jane Crane. These agreements expire on December 31, 2004, and provide that, upon termination of the executive's employment during the term of the Agreement (subject to an extension in the event a Potential Change in Control, as defined in the agreement, occurs during the term) following a change in control of SPR (as defined in the agreement) either (a) by SPR for reasons other than cause (as defined in the agreements), (b) death or disability, or by the executive for good reason (as defined in the agreement), including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of SPR), the executive will
receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to two or, with respect to certain senior officers, three times the sum of the executive's base salary and target bonus, (ii) a lump sum payment equal to the present value of the benefits the executive would have received had he continued to participate in SPR's retirement plans for an additional two or three years (or, in the case of SPR's Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive's early retirement date, as defined in such plan), and (iii) continuation of life, disability, accident and health insurance benefits for a period of 24 or 36 months immediately following termination of employment, except with respect to Mr. Higgins, whose agreement is described in the Employment Agreements section below. The agreements also provide that if any compensation paid, or benefit provided, to the executive, whether or not pursuant to the change in control agreements, would be subject to the federal excise tax on "excess parachute payments," payments and benefits provided pursuant to the agreement will be cut back to the largest amount that would not be subject to such excise tax, if such cutback results in a higher after-tax payment to the executive. The Board of Directors entered into these agreements in order to attract and retain management and to encourage and reinforce continued attention to the executives' assigned duties without distraction under circumstances arising from the possibility of a change in control of SPR. In entering into these agreements, the Board was advised by Towers Perrin, the national compensation and benefits consulting firm described above, and Skadden, Arps, Slate, Meagher & Flom, an independent outside law firm, to insure that the agreements entered into were in line with existing industry standards, and provided benefits to management consistent with those standards.
EMPLOYMENT AGREEMENTS
WALTER M. HIGGINS
On August 4, 2000, SPR elected Walter M. Higgins as President, Chief Executive Officer and Chairman of the Board under terms and conditions of an employment offer. The terms and conditions of that agreement essentially replicated Mr. Higgins' compensation and benefits package provided by his previous employer, AGL Resources, and made him whole for benefits and compensation lost, forgone, or otherwise forfeited as a result of his accepting employment with SPR.
The Board of Directors engaged Towers Perrin to evaluate Mr. Higgins' offer prior to consummating it in order to assure that it was consistent with SPR policy to compensate its senior executives, including the Chief Executive Officer, at or near the midpoint of the competitive market for base salary and incentive compensation opportunities for executives of comparably sized companies in general industry.
The employment agreement with Mr. Higgins provides for an annual base salary of $590,000, participation in SPR's short-term incentive program at 65% of base pay, and participation in SPR's long-term incentive program approved by Stockholders at 140%. For the reasons expressed above in connection with the officer group as a whole, Mr. Higgins received no annual incentive or long-term payments for 2002. As part of his employment agreement, Mr. Higgins also received a one-time restricted stock grant of 16,000 shares with dividend equivalents, grossed-up for taxes, which will vest over a four-year period. Mr. Higgins is required to accumulate and maintain, over five years, five times annual compensation in SPR stock, and was also granted 400,000 non-qualified stock options at a strike price based on the closing stock price on the day he accepted employment with SPR, which will vest 25% per year or sooner if certain price threshold levels are met. Mr. Higgins is also eligible to participate in SPR's Supplemental Executive Retirement Plan and was provided credit for all previous years of service with SPR, plus all years served at AGL Resources. Mr. Higgins is also provided $2,000,000 of life insurance coverage at SPR expense and is otherwise eligible to participate in all employer-sponsored health, pension, benefit, and welfare plans. In the event Mr. Higgins is terminated by SPR for any reason other than cause (as defined in the agreement), he will receive one year's base salary and annual incentive payment, subject to execution of an appropriate release and non-compete covenants and full vesting in SPR's SERP calculated as though he were age 62 (retirement age). In the event of a termination resulting from
change in control, within 24 months following a change in control of SPR (as defined in the agreement either (a) by SPR for reasons other than cause (as defined in the agreement), (b) death or disability, or (c) by Mr. Higgins for good reason as defined in the agreement, including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of SPR and the acquirer)), he will receive certain payments and benefits. This severance payment and benefit includes (i) a lump sum payment equal to three times the sum of his base salary and target bonus, (ii) a lump sum payment equal to the present value of the benefits he would have received had he continued to participate in SPR's retirement plans for an additional three years (or, in the case of SPR's Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive's early retirement date, as defined in such plan) and (iii) continuation of life, disability, accident and health insurance benefits for a period of 36 months immediately following termination of employment.
Under the employment agreement, SPR will pay any additional amounts sufficient to hold Mr. Higgins harmless for any excise tax that might be imposed as a result of being subject to the federal excise tax on "excess parachute payments" or similar taxes imposed by state or local law in connection with receiving any compensation or benefits that are considered contingent on a change in control.
A change in control for purposes of the Employment Agreement occurs (i) if SPR merges or consolidates, or sells all or substantially all of its assets, and less than 65% of the voting power of the surviving corporation is owned by those Stockholders who were Stockholders of SPR immediately prior to such merger or sale; (ii) any person acquires 20% or more of SPR's voting stock; (iii) SPR enters into an agreement or SPR or any person announces an intent to take action, the consummation of which would otherwise result in a change in control, or the Board of Directors of SPR adopts a resolution to the effect that a change in control has occurred; (iv) with in a two-year period, a majority of the Directors of SPR at the beginning of such period cease to be directors; (v) the Stockholders of SPR approve a complete liquidation or dissolution of SPR; or (vi) there is consummated a sale of a majority of the stock, or sale of substantially all assets, or complete liquidation or dissolution of either SPPC or NPC.
In addition, in connection with SPR's family relocation policy, SPR made a cash equity advance of $800,000 to Mr. Higgins in 2002 to facilitate the permanent location of Mr. Higgins and relocation of his family in Las Vegas while his principal residence was being sold. Mr. Higgins repaid the equity advance in its entirety in 2002 when his prior residence was sold.
AFFILIATE TRANSACTIONS AND RELATIONSHIPS
Employees of SPR provide certain accounting, treasury, information technology and administrative services to NPC and SPPC. The costs of those services are allocated among the three Utilities according to each Utility's usage. Additionally, many of SPR's officers are also officers of NPC and SPPC. All three companies have the same members of their respective boards of directors.
SPR files a consolidated federal income tax return for itself and its subsidiaries. Current income taxes are allocated based on each entity's respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR does not believe that any significant additional tax liability would be incurred by any of its subsidiaries on behalf of any other subsidiary; however, SPR and its subsidiaries could potentially incur certain tax liabilities as a result of the joint tax filing in the event of a change in applicable law or as a result of an audit.
As part of their on-going cash management practices and operations, SPR may make intercompany loans to the Utilities and/or the Utilities may make intercompany loans to each other, subject to any applicable regulatory restrictions.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
SPR, NPC, and SPPC maintain disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the Exchange Act) designed to ensure that they are able to collect the information required to be disclosed in the reports they file with the Securities and Exchange Commission (SEC), and to process, summarize and disclose this information accurately and within the time periods specified in the rules of the SEC. The chief executive officer and chief financial officer of each of SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the disclosure controls and procedures of SPR, NPC, and SPPC are effective in bringing to their attention on a timely basis material information relating to SPR, NPC, and SPPC required to be included in periodic filings under the Exchange Act.
Since the Evaluation Date, there have not been any significant changes in the internal controls of SPR, NPC, and SPPC, or in other factors that could significantly affect these controls subsequent to the Evaluation Date.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND EXHIBITS
All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules have been omitted because the information is not applicable.
3. Exhibits: Exhibits are listed in the Exhibit Index on pages 227-244.
(b) Reports on Form 8-K:
Form 8-K dated October 4, 2002, filed by SPR and NPC - Item 5, Other Events
Disclosed that, in connection with a private placement of long-term debt, NPC had prepared an Offering Memorandum for distribution to the potential purchasers. Excerpts from the Offering Memorandum were included as an exhibit.
Form 8-K dated October 25, 2002, filed by SPR and NPC - Item 5, Other Events
Disclosed that, in connection with a private placement of long-term debt, NPC had prepared an Offering Memorandum for distribution to the potential purchasers. Excerpts from the Offering Memorandum were included as an exhibit.
Form 8-K dated October 30, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, NPC's press release dated October 30, 2002, announcing that it had paid in full those power suppliers who earlier had accepted extended payment terms for summer power supplies. Additionally, NPC disclosed that it had refinanced maturing bank debt and secured an accounts receivable purchase facility providing additional liquidity.
Also separately disclosed, and included as an exhibit, SPPC's press release dated October 31, 2002, announcing that it had refinanced maturing bank debt and secured an accounts receivable purchase facility providing additional liquidity.
Form 8-K dated November 14, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed that, on November 14, 2002, the federal bankruptcy court judge overseeing the bankruptcy case of Enron Power Marketing, Inc. (Enron) had rendered an oral decision relating to a motion filed by the Utilities in connection with the lawsuit filed by Enron in its bankruptcy case asserting claims for damages related to the termination of its power supply agreements with the Utilities.
Form 8-K dated December 19, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed that, on December 19, 2002, the FERC Administrative Law Judge (ALJ) issued an order dismissing complaints filed by the Utilities against nine of their major electric energy suppliers under section 206 of the Federal Power Act, and the Utilities' plan to file a brief with the full FERC taking exception to the ALJ's findings.
Also separately disclosed that, on December 19, 2002, the federal bankruptcy court judge overseeing the bankruptcy case of Enron had rendered a decision in the lawsuit filed by Enron in its bankruptcy case asserting claims for damages related to the termination of its power supply agreements with the Utilities.
Form 8-K dated December 30, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated December 30, 2002, announcing that Richard K. Atkinson had been named vice president and chief financial officer of the corporation succeeding Dennis D. Schiffel as chief financial officer.
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY
By /s/ Walter M. Higgins ---------------------------------------------- Walter M. Higgins Chairman, Chief Executive Officer and Director March 27, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company and in the capacities indicated on the 27th day of March, 2003.
/s/ Richard Atkinson /s/ John Brown - -------------------------------------- ------------------------------------ Richard K. Atkinson John E. Brown Vice President, Vice President, Chief Financial Officer Controller (Principal Financial Officer) (Principal Accounting Officer)
/s/ Edward P. Bliss /s/ Jerry E. Herbst - -------------------------------------- ------------------------------------ Edward P. Bliss Jerry E. Herbst Director Director
/s/ Mary Lee Coleman /s/ John F. O'Reilly - -------------------------------------- ------------------------------------ Mary Lee Coleman John F. O'Reilly Director Director
/s/ Krestine M. Corbin /s/ Clyde T. Turner - -------------------------------------- ------------------------------------ Krestine M. Corbin Clyde T. Turner Director Director
/s/ Theodore J. Day /s/ Dennis E. Wheeler - -------------------------------------- ------------------------------------ Theodore J. Day Dennis E. Wheeler Director Director
/s/ James R. Donnelley - -------------------------------------- James R. Donnelley Director
ANNUAL CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
I, Walter M. Higgins III, certify that:
1. I have reviewed the combined annual report on Form 10K of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company;
2. Based on my knowledge, the combined annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined annual report;
3. Based on my knowledge, the financial statements, and other financial information included in the combined annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined annual report;
4. The chief financial officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined annual report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined annual report (the "Evaluation Date"); and
c) presented in the combined annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The chief financial officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors:
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and
6. The chief financial officer and I have indicated in this combined annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 28, 2003
/s/ Walter M. Higgins, III -------------------------- Walter M. Higgins III Chief Executive Officer
ANNUAL CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002
I, Richard K. Atkinson, certify that:
1. I have reviewed the combined annual report on Form 10K of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company;
2. Based on my knowledge, the combined annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined annual report;
3. Based on my knowledge, the financial statements, and other financial information included in the combined annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined annual report;
4. The chief executive officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined annual report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined annual report (the "Evaluation Date"); and
c) presented in the combined annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The chief executive officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors:
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and
6. The chief executive officer and I have indicated in this combined annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 28, 2003
/s/ Richard K. Atkinson ----------------------- Richard K. Atkinson Chief Financial Officer
SIERRA PACIFIC RESOURCES SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
NEVADA POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
SIERRA PACIFIC POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
(1) Included in the provision charged to income in 2000 was $7.3 million and $0.3 million, respectively, for NPC and SPPC as reserves against receivables from California's Power Exchange and Independent System Operator.
(2) In 2001, the provision charge to income included $12.6 million and $1.2 million respectively, for NPC and SPPC as reserves against receivables from California's Power Exchange and Independent System Operator. The provision charge also included $.1 million and $.4 million respectively, for NPC and SPPC as reserves against receivables from Enron.
2002 FORM 10-K EXHIBIT INDEX
(a) Exhibits Index
Certain of the following exhibits with respect to SPR and its subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Lands of Sierra, Inc., Sierra Energy Company, Tuscarora Gas Pipeline Company and Sierra Water Development Company, are filed herewith. Certain other of such exhibits have heretofore been filed with the Commission and are incorporated herein by reference.
(* filed herewith)
(3) SIERRA PACIFIC RESOURCES
o Restated Articles of Incorporation of Sierra Pacific Resources dated July 28, 1999 (filed as Exhibit 3(A) to Form 10-K for year ended December 31, 1999).
o *(A) By-laws of Sierra Pacific Resources as amended through August 14, 2002.
NEVADA POWER COMPANY
o Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999).
o Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as Exhibit 3(C) to Form 10-K for year ended December 31, 1999).
SIERRA PACIFIC POWER COMPANY
o Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1993).
o Certificate of Amendments dated August 26, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company's preferred stock (filed as Exhibit 3.1 to Form 8-K dated August 26, 1992).
o Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company's Class A Series 1 Preferred Stock (filed as Exhibit 4.3 to Form 8-K dated August 26, 1992).
o By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).
o Articles of Incorporation of Pinon Pine Corp., dated December 11, 1995 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995).
o Articles of Incorporation of Pinon Pine Investment Co., dated December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995).
o Agreement of Limited Liability Company of Pinon Pine Company, L.L.C., dated December 15, 1995, between Pinon Pine Corp., Pinon Pine Investment Co. and GPSF-B INC 1995 (filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995).
o Amended and Restated Limited Liability Company Agreement of SPPC Funding LLC dated as of April 9, 1999, in connection with the issuance of California rate reduction bonds (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1999).
(4) SIERRA PACIFIC RESOURCES
o Amended and Restated Rights Agreement dated as of February 28, 2001 between Sierra Pacific Resources and Wells Fargo Bank Minnesota, N.A. as successor Rights Agent (filed as Exhibit 4.1 to Registration Statement on Form S-3 filed July 2, 2001, File No. 333-64438).
o Purchase Contract Agreement dated November 16, 2001, between Sierra Pacific Resources and The Bank of New York, relating to the Company's Premium Income Equity Securities (PIES) (filed as Exhibit 4.3 to Form 8-K dated November 16, 2001).
o Corporate PIES Certificate (filed as Exhibit 4.4 to Form 8-K dated November 16, 2001).
o Treasury PIES Certificate (filed as Exhibit 4.5 to Form 8-K dated November 16, 2001).
o Pledge Agreement dated November 16, 2001, among Sierra Pacific Resources, Wells Fargo Bank Minnesota, N.A. and The Bank of New York (filed as Exhibit 4.6 to Form 8-K dated November 16, 2001).
o Remarketing Agreement dated November 16, 2001, between Sierra Pacific Resources and Lehman Brothers, Inc. (filed as Exhibit 4.7 to Form 8-K dated November 16, 2001).
o Indenture between Sierra Pacific Resources and The Bank of New York, dated as of May 1, 2000 for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000).
o Global 8-3/4% Note due 2005 (filed as Exhibit 4.2 to Form 8-K dated May 22, 2000).
o Officers' Certificate establishing the terms of the 8-3/4% Notes due 2005 (filed as Exhibit 4.3 to Form 8-K dated May 22, 2000).
o 7.93% Senior Note due 2007 issued in connection with Sierra Pacific Resources PIES (filed as Exhibit 4.2 to Form 8-K dated November 16, 2001).
o Officers' Certificate establishing the terms of the 7.93% Senior Notes due 2007 (filed as Exhibit 4.3 to Form 8-K dated November 16, 2001).
o Fiscal and Paying Agency Agreement dated as of April 17, 2000 between Sierra Pacific Resources and Bankers Trust Company, relating to the Company's money market note program (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2000).
o Form of Global Floating Rate Note due April 20, 2003 in connection with the Company's money market note program (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 2000).
NEVADA POWER COMPANY
o General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for the quarter ended June 30, 2001).
o First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001).
o Officer's Certificate establishing the terms of Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(c) to Form 10-Q for the quarter ended June 30, 2001).
o Form of Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(d) to Form 10-Q for the quarter ended June 30, 2001).
o Second Supplemental Indenture, dated as of October 1, 2001, establishing Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003 (filed as Exhibit 4(A) to Form 10-K for the year ended December 30, 2001).
o Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003 (filed as Exhibit 4(B) to Form 10-K for the year ended December 30, 2001).
o Form of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003 (filed as Exhibit 4(C) to Form 10-K for the year ended December 30, 2001).
o Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Bonds, Series D, due April 15, 2004 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2002).
o Form of Nevada Power Company's General and Refunding Mortgage Bonds, Series D, due April 15, 2004 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended June 30, 2002).
o Officer's Certificate establishing the terms of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2002).
o Form of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2002).
o Fiscal and Paying Agency Agreement, dated as of September 19, 2001, between Nevada Power Company and Bankers Trust Company, relating to the issuance and sale of Nevada Power Company's 6% Notes due 2003 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2001).
o Form of Global Note due September 15, 2003, in connection with the issuance and sale of Nevada Power Company's 6% Notes due 2003 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2001).
o Junior Subordinated Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Debenture Trustee dated March 1, 1997 (filed as Exhibit 4.01 to Form S-3, File No. 333-21091).
o Trust Agreement of NVP Capital I dated March 1, 1997 (filed as Exhibit 4.03 to Form S-3, File No. 333-21091).
o Form of Amended and Restated Trust Agreement dated March 1, 1997 (filed as Exhibit 4.10 to Form S-3, File No. 333-21091).
o Form of Agreement as to Expenses and Liabilities between Nevada Power and NVP Capital I dated March 1, 1997 (filed as Exhibit 4.14 to Form S-3, File No. 333-21091).
o Form of Preferred Security Certificate for NVP Capital I and NVP Capital II dated March 1, 1997 (filed as Exhibit 4.11 to Form S-3, File No. 333-21091).
o Form of Guarantee Agreement dated March 1, 1997 (filed as Exhibit 4.12 to Form S-3, File No. 333-21091).
o Form of Supplemental Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Debenture Trustee dated March 1, 1997 (filed as Exhibit 4.13 to Form S-3, File No. 333-21091).
o Supplemental Indenture No. 2 and Assumption Agreement, dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Junior Subordinated Indenture dated as of March 1, 1997 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999).
o Form of Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Trustee dated October 1, 1998 (filed as Exhibit 4.1 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Certificate of Trust of NVP Capital III dated October 1, 1998 (filed as Exhibit 4.2 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Trust Agreement for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.3 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Form of Amended and Restated Declaration of Trust dated October 1, 1998 (filed as Exhibit 4.4 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Form of Preferred Security Certificate for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.5 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Form of Preferred Securities Guarantee Agreement dated October 1, 1998 (filed as Exhibit 4.7 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Form of Junior Subordinated Deferrable Interest Debenture dated October 1, 1998 (filed as Exhibit 4.9 to Form S-3, File Nos. 333-63613 and 333-63613-01).
o Supplemental Indenture No. 1 and Assumption Agreement, dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and
assuming the Indenture dated as of October 1, 1998 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999).
o Form of Senior Unsecured Note Indenture between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of March 1, 1999 (filed as Exhibit 4.1 to Form S-4, File No. 333-77325).
o Supplemental Indenture No. 1 between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of March 1, 1999 (including form of 6.20% Senior Unsecured Note, Series A due April 15, 2004) (filed as Exhibit 4.2 to Form S-4, File No. 333-77325).
o Supplemental Indenture No. 2 between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of April 1, 1999 (including form of 6.20% Senior Unsecured Note, Series B due April 15, 2004) (filed as Exhibit 4.3 to Form S-4, File No. 333-77325).
o Supplemental Indenture No. 3 and Assumption Agreement, dated as of July 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Senior Unsecured Note Indenture dated as of March 1, 1999 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(F) to Form 10-K for year ended December 31, 1999).
o Indenture of Mortgage and Deed of Trust providing for Nevada Power Company's First Mortgage Bonds, dated as of October 1, 1953 and Twenty-Eight Supplemental Indentures as follows:
o First Supplemental Indenture, dated as of August 1, 1954 (filed as Exhibit 4.2 to Form S-1, File No. 2-11440).
o Instrument of Further Assurance dated April 1, 1956 to Indenture of Mortgage and Deed of Trust dated October 1, 1953 (filed as Exhibit 4.8 to Form S-1, File No. 2-12666).
o Second Supplemental Indenture, dated as of September 1, 1956 (filed as Exhibit 4.9 to Form S-1, File No. 2-12566).
o Third Supplemental Indenture, dated as of May 1, 1959 (filed as Exhibit 4.13 to Form S-1, File No. 2-14949).
o Fourth Supplemental Indenture, dated as of October 1, 1960 (filed as Exhibit 4.5 to S-1, File No. 2-16968).
o Fifth Supplemental Indenture, dated as of December 1, 1961 (filed as Exhibit 4.6 to Form S-16, File No. 2-74929).
o Sixth Supplemental Indenture, dated as of October 1, 1963 (filed as Exhibit 4.6A to Form S-1, File No. 2-21689).
o Seventh Supplemental Indenture, dated as of August 1, 1964 (filed as Exhibit 4.6B to Form S-1, File No. 2-22560).
o Eighth Supplemental Indenture, dated as of April 1, 1968 (filed as Exhibit 4.6C to Form S-9, File No. 2-28348.
o Ninth Supplemental Indenture, dated as of October 1, 1969 (filed as Exhibit 4.6D to Form S-1, File No. 2-34588).
o Tenth Supplemental Indenture, dated as of October 1, 1970 (filed as Exhibit 4.6E to Form S-7, File No. 2-38314).
o Eleventh Supplemental Indenture, dated as of November 1, 1972 (filed as Exhibit 2.12 to Form S-7, File No. 2-45728).
o Twelfth Supplemental Indenture, dated as of December 1, 1974 (filed as Exhibit 2.13 to Form S-7, File No. 2-52350).
o Thirteenth Supplemental Indenture, dated as of October 1, 1976 (filed as Exhibit 4.14 to Form S-16, File No. 2-74929).
o Fourteenth Supplemental Indenture, dated as of May 1, 1977 (filed as Exhibit 4.15 to Form S-16, File No. 2-74929).
o Fifteenth Supplemental Indenture, dated as of September 1, 1978 (filed as Exhibit 4.16 to Form S-16, File No. 2-74929).
o Sixteenth Supplemental Indenture, dated as of December 1, 1981 (filed as Exhibit 4.17 to Form S-16, File No. 2-74929).
o Seventeenth Supplemental Indenture, dated as of August 1, 1982 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1982).
o Eighteenth Supplemental Indenture, dated as of November 1, 1986 (filed as Exhibit 4.6 to Form S-3, File No. 33-9537).
o Nineteenth Supplemental Indenture, dated as of October 1, 1989 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1989).
o Twentieth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit 4.21 to Form S-3, File No. 33-53034).
o Twenty-First Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.22 to Form S-3, File No. 33-53034).
o Twenty-Second Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034).
o Twenty-Third Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
o Twenty-Fourth Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
o Twenty-Fifth Supplemental Indenture, dated as of January 1, 1993 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).
o Twenty-Sixth Supplemental Indenture, dated as of May 1, 1995 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1995).
o Twenty-Seventh Supplemental Indenture dated as of as of July 1, 1999 (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 1999).
o Twenty-Eighth Supplemental Indenture dated as of July 1, 2001 (filed as Exhibit 4(D) to Form 10-K for the year ended December 30, 2001).
SIERRA PACIFIC POWER COMPANY
o General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001).
o First Supplemental Indenture, dated as of May 1, 2001, establishing Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(b) to Form 10-Q for the quarter ended June 30, 2001).
o Officer's Certificate establishing the terms of Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(c) to Form 10-Q for the quarter ended June 30, 2001).
o Form of Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(d) to Form 10-Q for the quarter ended June 30, 2001).
o Officer's Certificate establishing the terms of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 (filed as Exhibit 4.3 to Form 10-Q for the quarter ended September 30, 2002).
o Form of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended September 30, 2002).
o Indenture of Mortgage providing for Sierra Pacific Power Company's First Mortgage Bonds, dated as of December 1, 1940 (filed as Exhibit 7-A to Registration No. 2-7475).
o Ninth Supplemental Indenture, dated as of June 1, 1964 (filed as Exhibit 2-M to Registration No. 2-59509).
o Tenth Supplemental Indenture, dated as of March 31, 1965 (filed as Exhibit 4-K to Registration No. 2-23932).
o Eleventh Supplemental Indenture, dated as of October 1, 1965 (filed as Exhibit 4-L to Registration No. 2-26552).
o Twelfth Supplemental Indenture, dated as of July 1, 1967 (filed as Exhibit 4-L to Registration No. 2-36982).
o Sixteenth Supplemental Indenture, dated as of October 1, 1975 (filed as Exhibit 2-Y to Registration No. 2-53404).
o Nineteenth Supplemental Indenture, dated as of April 1, 1978 (filed as Exhibit (4)(A) to the 1991 Form 10-K).
o Twentieth Supplemental Indenture, dated as of October 1, 1978 (filed as Exhibit (4)(B) to the 1991 Form 10-K).
o Twenty-Seventh Supplemental Indenture, dated as of August 1, 1989 (filed as Exhibit (4)(A) to the 1989 Form 10-K).
o Twenty-Eighth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit (4)(A) to the 1992 Form 10-K).
o Twenty-Ninth Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit D to Form 8-K dated July 15, 1992).
o Thirtieth Supplemental Indenture, dated as of July 1, 1992 (filed as Exhibit (4)(B) to the 1992 Form 10-K).
o Thirty-First Supplemental Indenture, dated as of November 1, 1992 (filed as Exhibit (4)(C) to the 1992 Form 10-K).
o Thirty-Second Supplemental Indenture, dated as of June 1, 1993 (filed as Exhibit 4.6 to Registration No. 33-69550).
o Thirty-Third Supplemental Indenture, dated as of October 1, 1993 (filed as Exhibit C to Form 8-K dated October 20, 1993).
o Thirty-Fourth Supplemental Indenture, dated as of February 1, 1996 (filed as Exhibit C to Form 8-K dated March 11, 1996).
o Thirty-Fifth Supplemental Indenture, dated as of February 1, 1997 (filed as Exhibit C to Form 8-K dated March 10, 1997).
o Indenture dated as of April 9, 1999 between SPPC Funding LLC and Bankers Trust Company of California, N.A. in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 1999).
o First Series Supplement dated as of April 9, 1999 to Indenture between SPPC Funding LLC and Bankers Trust Company of California, N.A. in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999).
o Form of SPPC Funding LLC Notes, Series 1999-1, in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999).
o Collateral Trust Indenture dated June 1, 1992 between Sierra Pacific Power Company and Bankers Trust Company, as Trustee, relating to Sierra Pacific Power Company's medium-term note program (filed as Exhibit B to Form 8-K dated July 15, 1992).
o First Supplemental Indenture dated June 1, 1992 (filed as Exhibit C to Form 8-K dated July 15, 1992).
o Second Supplemental Indenture dated October 1, 1993 (filed as Exhibit B to Form 8-K dated October 20, 1993).
o Third Supplemental Indenture dated as of February 1, 1996 (filed as Exhibit B to Form 8-K dated March 11, 1996).
o Fourth Supplemental Indenture dated as of February 1, 1997 (filed as Exhibit B to Form 8-K dated March 10, 1997).
o Form of Medium-Term Global Fixed Rate Note, Series A in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit E to Form 8-K dated July 15, 1992 ).
o Form of Medium-Term Global Fixed Rate Note, Series B in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated October 25, 1993).
o Form of Medium-Term Global Fixed-Rate Note, Series C in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated March 11, 1996).
o Form of Medium-Term Global Fixed-Rate Note, Series D in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated March 10, 1997).
(10) SIERRA PACIFIC RESOURCES
o Change in Control Agreement dated May 21, 2001, by and between Sierra Pacific Resources and Walter M. Higgins (filed as Exhibit 10(B) to Form 10-K for the year ended December 30, 2001).
o Walter M. Higgins Employment Letter dated August 4, 2000 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2000).
o Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Richard K. Atkinson, Jeffrey L. Ceccarelli, Victor H. Pena, Donald L. Shalmy and Michael W. Yackira in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and Dennis D. Schiffel (filed as Exhibit 10(C) to Form 10-K for the year ended December 30, 2001).
o Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Susan Brennan, Richard J. Coyle, Jane Crane, Matt H. Davis, Carol Elmore, Julian C. Leone, Mary O. Simmons, Mike Smart and Bob Werner in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and John E. Brown (filed as Exhibit 10(D) to Form 10-K for the year ended December 30, 2001).
o Donald L. Shalmy Employment Letter dated May 21, 2002 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2002).
o *(A) Michael W. Yackira Employment Letter dated March 17, 2003.
o Severance and Release Agreement, dated May 24, 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and Mark A. Ruelle (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2002).
o Severance and Release Agreement, dated May 18, 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and Steven C. Oldham (filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2002).
o *(B) Severance and Release Agreement, dated September 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and William E. Peterson.
o Sierra Pacific Resources' Executive Long-Term Incentive Plan (filed as Exhibit 99.1 to Form S-8 dated December 13, 1999).
o Sierra Pacific Resources' Non-Employee Director Stock Plan (filed as Exhibit 99.2 to Form S-8 dated December 13, 1999).
o Sierra Pacific Resources' Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999).
NEVADA POWER COMPANY
o Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks named therein, and Societe Generale, Los Angeles Branch (relating to the Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B; Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds Series, 1995D; and Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds, Series 1995E) (filed as Exhibit 10.80 to Form 10-K, File No. 1-4698, Year 1995).
o Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks named therein, and Barclays Bank PLC, New York Branch (relating to Clark County, Nevada $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.81 to Form 10-K, File No. 1-4698, Year 1995).
o Letter of Credit and Reimbursement Agreement dated as of April 12, 1994 between Nevada Power Company and Societe Generale, Los Angeles Branch and Amendment No. 1 thereto dated as of May 3, 1994 (relating to $60,000,000 Clark County, Nevada Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1989A) (filed as Exhibit 10.72 to Form 10-K, File No. 1-4698, Year 1994).
o Reimbursement Agreement dated as of November 1, 1988 between the Fuji Bank, Limited and Nevada Power Company (relating to $25,000,000 Clark County, Nevada Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1998) (filed as Exhibit 10.43 to Form 10-K, File No. 1-4698, Year 1988).
o Reimbursement Agreement dated as of December 1, 1985 between The Fuji Bank, Limited and Nevada Power Company (relating to Clark County, Nevada $44,000,000 Floating Rate Weekly
Demand Industrial Development Revenue Bonds, Series 1985) (filed as Exhibit 10.38 to Form 10-K, File No. 1-4698, Year 1986).
o Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000).
o Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year ended December 31, 2000).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated November 1, 1997 (relating to Clark County, Nevada $52,285,000 Industrial Development Revenue Bonds, Series 1997A) (filed as Exhibit 10.83 to Form 10-K, File No. 1-4698, Year 1997).
o Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated November 1, 1997 (relating to Coconino County, Arizona $20,000,000 Pollution Control Corporation Pollution Control Revenue Bonds, Series 1997B) (filed as Exhibit 10.84 to Form 10-K, File No. 1-4698, Year 1997).
o Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1996 (relating to Coconino County, Arizona Pollution Control Corporation $20,000,000 Pollution Control Revenue Bonds, Series 1996) (filed as Exhibit 10.82 to Form 10-K, File 1-4698, Year 1996).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, Year 1995).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, Year 1995).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-4698, Year 1995).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds, Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No. 1-4698, Year 1995).
o Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1995 (relating to Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds, Series 1995E) (filed as Exhibit 10.79 to Form 10-K, File No. 1-4698, Year 1995).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1992 (Relating to Industrial Development Refunding Revenue Bonds, Series 1992C) (filed as Exhibit 10.67 to Form 10-K, File No. 1-4698, Year 1992).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Relating to Clark County, Nevada $105,000,000 Industrial Development Revenue Bonds, Series 1992A) (filed as Exhibit 10.65 to Form 10-K, File No. 1-4698, Year 1992).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Relating to Pollution Control Refunding Revenue Bonds, Series 1992B) (filed as Exhibit 10.66 to Form 10-K, File No. 1-4698, Year 1992).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated as of November 1, 1988 (relating to Clark County, Nevada $25,000,000 Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1988) (filed as Exhibit 10.42 to Form 10-K, File No. 1-4698, Year 1988).
o Financing Agreement between Clark County, Nevada and Nevada Power Company dated as of December 1, 1985 (relating to Clark County, Nevada $44,000,000 Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1985) (filed as Exhibit 10.37 to Form 10-K, File No. 1-4698, Year 1985).
o Financing Agreement dated as of February 1, 1983 between Clark County, Nevada and Nevada Power Company (relating to Clark County, Nevada $78,000,000 Industrial Development Revenue Bonds, Series 1983) (filed as Exhibit 10.36 to Form 10-K, File No. 1-4698, Year 1985).
o Collective Bargaining Agreement dated as of February 1, 2002, effective through February 1, 2005, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2002).
o *(C) Western Systems Power Pool ("WSPP") Agreement effective September 1, 2002 between Nevada Power Company as a member of WSPP and the other members of the WSPP.
o Agreement for Transmission Service dated March 29, 1989 between Overton Power District No. 5, Lincoln County Power District No. 1 and Nevada Power Company (filed as Exhibit 10.51 to Form 10-K, File No. 1-4698, Year 1989).
o Contract for Operation, Maintenance, Replacement, Ownership, and Interconnection of Facilities dated June 30, 1988 between United States Department of Energy Western Area Power Administration and Nevada Power Company (filed as Exhibit 10.52 to Form 10-K, File No. 1-4698, Year 1989).
o Transmission Facilities Agreement between Utah Power & Light Company and Nevada Power Company, dated August 17, 1987 (filed as Exhibit 10.41 to Form 10-K, File No. 1-4698, Year 1987).
o Contract for Sale of Electrical Energy between the State of Nevada and Nevada Power Company, dated July 8, 1987 (filed as Exhibit 10.39 to Form 10-K, File No. 1-4698, Year 1987).
o Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada Power Company and California Department of Water Resources (filed as Exhibit 5.34 to Form S-7, File No. 2-65097).
o Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed as Exhibit 5.36 to Form S-7, File No. 2-56356).
o Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power 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 (filed as Exhibit 5.35 to Form S-7, File No. 2-56356).
o Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power 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 (filed as Exhibit 5.31 to Form 8-K, File No. 1-4696, April 1974).
o Mohave Operating Agreement dated July 6, 1970 between Nevada Power 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 (filed as Exhibit 13.26F to Form S-1, File No. 2-38314).
o Navajo Project Coal Supply Agreement dated June 1, 1970 between Nevada Power 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 (filed as Exhibit 13.27B to Form S-1, File No. 2-38314).
o Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348).
o Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9, File No. 2-28348).
o Reliability Management System Agreement dated June 18, 1999 by and between Western Systems Coordinating Council and Nevada Power Company (filed as Exhibit 10(U) to Form 10-K for the year ended December 31, 2000).
o Service Agreement No. 90 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 20, 2001 between Nevada Power Company and Reliant Energy Services, Inc. (filed as Exhibit 10(G) to Form 10-K for the year ended December 30, 2001).
o Service Agreement Nos. 98 and 99 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power
Company and Mirant Americas Development, Inc. (filed as Exhibit 10(J) to Form 10-K for the year ended December 30, 2001).
o *(D) Settlement Agreement, dated April 16, 2002, by and between Nevada Power Company and each of Calpine Corporation, Duke Energy Trading and Marketing, L.L.C., Mirant Las Vegas, LLC, Pinnacle West Energy Corporation and Reliant Energy Services.
o *(E) Service Agreement No. 96 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 9, 2002 between Nevada Power Company and Calpine Corporation.
o *(F) Service Agreement No. 97 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 3, 2002 between Nevada Power Company and Duke Energy Trading and Marketing.
o *(G) Service Agreement No. 100 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Reliant Energy Services, Inc.
o *(H) Service Agreement No. 101.A for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Pinnacle West Energy Corporation.
o *(I) Service Agreement No. 101.B for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Southern Nevada Water Authority.
o Service Agreement No. 102 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 3, 2001 between Nevada Power Company and Las Vegas Cogeneration II, LLC (filed as Exhibit 10(M) to Form 10-K for the year ended December 30, 2001).
o Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as Lessee, dated January 1, 1984 for lease of administrative headquarters (the primary term of the sublease ends in 2014 and the lessee has the option to extend the term up to 25 additional years) (filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, Year 1983).
SIERRA PACIFIC POWER COMPANY
o Term Loan Agreement, dated as of October 30, 2002, by and among Sierra Pacific Power Company, the several banks and other financial institutions or entities from time to time parties to the Agreement, Lehman Brothers Inc., as advisor, sole lead arranger and sole bookrunner, Lehman Commercial Paper Inc., as syndication agent, and Lehman Commercial Paper Inc., as administrative agent (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2002).
o Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993A (filed as Exhibit (10) (I) to Form 10-K for the year ended December 31, 1993).
o Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993B (filed as Exhibit (10) (J) to Form 10-K for the year ended December 31, 1993).
o Financing Agreement dated as of March 1, 2001 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001 (filed as Exhibit 10(O) to Form 10-K for the year ended December 30, 2001).
o Financing Agreement dated September 1, 1990 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1990).
o Financing Agreement dated December 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 1993).
o Financing Agreement dated June 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(G) to Form 10-K for the year ended December 31, 1993).
o Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Humboldt County, Nevada relating to the Humboldt County, Nevada Variable Rate Demand Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 1993).
o Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(F) to Form 10-K for the year ended December 31, 1993).
o Transition Property Purchase and Sale Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1999).
o Transition Property Servicing Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 1999).
o Administrative Services Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 1999).
o Agreement dated January 1, 1998 (extended through December 31, 2002) between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local No. 1245. (Filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1997)
o Cooperative Agreement dated July 31, 1992 between Sierra Pacific Power Company and the United States Department of Energy in connection with the Pinon Pine Integrated Coal Gasification Combined Cycle Project (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 1992).
o Settlement Agreement and Mutual Release dated May 8, 1992 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the Securities and Exchange Commission).
o Western Systems Power Pool (WSPP) Agreement effective September 1, 2002 between Sierra Pacific Power Company as a member of WSPP and the other members of the WSPP (filed as Exhibit 10(c)).
o Coal Supply Agreement dated January 1, 2002 between Sierra Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006) (filed as Exhibit 10(R) to Form 10-K for the year ended December 30, 2001).
o Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1991).
o Amendatory Agreement dated February 14, 1992 to Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1991).
o Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (confidential portions omitted and filed separately with the Securities and Exchange Commission) (filed as Exhibit 5-GG to Registration No. 2-62476).
o Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(B) to Form 10-K for the year ended December 31, 1991).
o Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993).
o Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(B) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the Securities and Exchange Commission).
o Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 1992).
o Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (filed as Exhibit (10) (K) to Form 10-K for the year ended December 31, 1993).
SIERRA PACIFIC COMMUNICATIONS
o Unit Redemption, Release, and Sale Agreement entered into by and among Touch America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of September 9, 2002 (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2002).
o Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Qwest Communications Corporation (filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002).
(11) NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
o Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries and, in accordance with Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per share data have been omitted.
(12) SIERRA PACIFIC RESOURCES
o *(A) Statement regarding computation of Ratios of Earnings to Fixed Charges.
NEVADA POWER COMPANY
o *(B) Statement regarding computation of Ratios of Earnings to Fixed Charges.
SIERRA PACIFIC POWER COMPANY
o *(C) Statement regarding computation of Ratios of Earnings to Fixed Charges.
(21) SIERRA PACIFIC RESOURCES
o Nevada Power Company, a Nevada Corporation. Sierra Pacific Power Company, a Nevada Corporation. Great Basin Energy Company, a Nevada Corporation. Lands of Sierra, Inc., a Nevada Corporation. Sierra Energy Company dba e.three, a Nevada Corporation. Sierra Gas Holdings Company, a Nevada Corporation. Sierra Pacific Energy Company, a Nevada Corporation. Sierra Pacific Resources Capital Trust I, a Delaware Business Trust. Sierra Pacific Resources Capital Trust II, a Delaware Business Trust. Sierra Water Development Company, a Nevada Corporation. Tuscarora Gas Pipeline Company, a Nevada Corporation. Tuscarora Gas Operating Company, a Nevada Corporation. SRP Receivables Finance Corporation, a Delaware Corporation.
NEVADA POWER COMPANY
o Nevada Electric Investment Company, a Nevada Corporation Commonsite, Inc., a Nevada Corporation. NVP Capital I, a Delaware Business Trust. NVP Capital II, a Delaware Business Trust. Nevada Power Receivables Finance Corporation, a Delaware Corporation.
SIERRA PACIFIC POWER COMPANY
o Pinon Pine Company, a Nevada Corporation. Pinon Pine Investment Company, a Nevada Corporation. Pinon Pine Investment Co. LLC, a Nevada Limited Liability Company. GPSF-B, a Delaware Corporation. SPPC Funding LLC, a Delaware Limited Liability Company. Sierra Pacific Power Capital Trust I, a Delaware Business Trust. SPPC Receivables Finance Corporation, a Delaware Corporation.
(23) SIERRA PACIFIC RESOURCES
o *(A) Consent of Independent Accountants in connection with the Sierra Pacific Resources' Registration Statements No. 333-77523 (Common Stock Investment Plan) on Form S-3, No. 333-92651 (Employees' Stock Ownership Plan, Executive Long-Term Incentive Plan, and Non-Employee Director Stock Plan) on Forms S-8, and No. 333-72160 (Post-Effective Amendment to Registration) No. 333-80149 on Form S-3.
NEVADA POWER COMPANY
o *(B) Consent of Independent Accountants in connection with the Nevada Power Company's Registration Statement No. 333-102727 (Series E Mortgage Notes) on Form S-4.
(99) SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
o *(99.1) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
o *(99.2) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.