UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
| | | | | | | |
| Commission File | | Registrant, Address of Principal Executive Offices and Telephone | | I.R.S. Employer | | State of |
| Number | | Number | | Identification Number | | Incorporation |
1-08788 | | SIERRA PACIFIC RESOURCES | | 88-0198358 | | Nevada |
| | | P.O. Box 30150 (6100 Neil Road) | | | | |
| | | Reno, Nevada 89520-3150 (89511) | | | | |
| | | (775) 834-4011 | | | | |
| |
2-28348 | | NEVADA POWER COMPANY | | 88-0420104 | | Nevada |
| | | 6226 West Sahara Avenue | | | | |
| | | Las Vegas, Nevada 89146 | | | | |
| | | (702) 367-5000 | | | | |
| |
0-00508 | | SIERRA PACIFIC POWER COMPANY | | 88-0044418 | | Nevada |
| | | P.O. Box 10100 (6100 Neil Road) | | | | |
| | | Reno, Nevada 89520-0024 (89511) | | | | |
| | | (775) 834-4011 | | | | |
| | | |
| (Title of each class) | | (Name of exchange on which registered) |
| Securities registered pursuant to Section 12(b) of the Act: | | |
| Securities of Sierra Pacific Resources: | | |
| Common Stock, $1.00 par value | | New York Stock Exchange |
| 7.803% Senior Notes Due 2012 | | New York Stock Exchange |
| | | |
| Securities registered pursuant to Section 12(g) of the Act: | | |
| Securities of Nevada Power Company: | | |
| Common Stock, $1.00 stated value | | |
| Securities of Sierra Pacific Power Company: | | |
| Common Stock, $3.75 par value | | |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
Sierra Pacific Resources Yesþ Noo Nevada Power Company Yeso Noþ Sierra Pacific Power Company Yeso Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ
Indicate by check mark whether any registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).
Sierra Pacific Resources: Large accelerated filerþ Accelerated filero Non-accelerated filero
Nevada Power Company: Large accelerated filero Accelerated filero Non-accelerated filerþ
Sierra Pacific Power Company: Large accelerated filero Accelerated filero Non-accelerated filerþ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ (Response applicable to all registrants)
State the aggregate market value of Sierra Pacific Resources’ common stock held by non-affiliates. As of June 30, 2006: $ 2,811,596,466
Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date.
Common Stock, $1.00 par value, of Sierra Pacific Resources outstanding at February 27, 2007: 221,252,060 Shares
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 par value, of Sierra Pacific Power Company.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Sierra Pacific Resources’ definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 7, 2007, are incorporated by reference into Part III hereof.
This combined Annual Report on Form 10-K is separately filed by Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by Sierra Pacific Resources and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Nevada Power Company.
Information contained in this document relating to Sierra Pacific Power Company is filed by Sierra Pacific Resources and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
CONTENTS
2
FORWARD LOOKING STATEMENTS
The discussion of forward looking statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, is incorporated herein by reference.
PART I
ITEM 1. BUSINESS
SIERRA PACIFIC RESOURCES
Sierra Pacific Resources (SPR) is an investor-owned holding company that was incorporated under Nevada law on December 12, 1983. The company’s stock is traded on the New York Stock Exchange under the symbol “SRP”. SPR’s mailing address is P.O. Box 30150 (6100 Neil Road), Reno, Nevada 89520-3150 (89511).
SPR has six primary, wholly-owned subsidiaries: Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Sierra Pacific Energy Company (SPE), and Lands of Sierra (LOS). References to SPR refer to the consolidated entity, except where the context provides otherwise. NPC and SPPC are referred to collectively in this report as the “Utilities.”
The Utilities operate three business segments, as defined by FASB Statement No. 131,Disclosure about Segments of an Enterprise and Related Information: NPC electric; SPPC electric; and SPPC natural gas. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas service is provided in the Reno-Sparks area of Nevada. The Utilities are the major contributors to SPR’s financial position and results of operations. Other subsidiaries either do not meet or are below the quantitative threshold for separate segment disclosure and are combined under “all other” in the following pages. Parenthetical references are included after each major section title to identify the specific entity or entities addressed in the section. See Note 2, Segment Information of the Notes to Financial Statements, for further discussion.
NPC and SPPC service territories are as follows:
3
SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. The Utilities provide electric and natural gas services to a diverse mix of over one million residential, commercial, industrial and public sector customers. Major industries served include gaming/recreation, mining, warehousing/manufacturing, offices, health care, education, military bases and other governmental entities.
The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts that seasonal weather, rate changes and customer usage patterns have on demand for electric energy and services. NPC is a summer peaking utility, experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak also occurs in the summer, with a slightly lower peak demand in the winter.
The Utilities do not own generating facilities sufficient to meet the peak demands and reliability needs of Nevada’s growing population and, as a result, NPC is forecasting to purchase approximately 34% of its energy requirements from the wholesale market and SPPC is forecasting to purchase approximately 49% of its energy requirements from the wholesale market for year 2007. For the 2007 summer peak, NPC and SPPC have secured 100% of their forecast capacity needs.
The amount of power purchased by the Utilities varies from time to time depending on demand, the cost of purchased power compared with our cost of generation, and the availability of such power. In 2006, NPC and SPPC purchased approximately 45.7% and 56.9%, respectively, of total system energy needs. Some purchased power contracts are indexed to natural gas prices. Due to the relatively large seasonal gas and purchased power usage, the Utilities purchase power and hedge a portion of their total natural gas exposure as discussed further in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.
It is SPR’s strategy to grow the Utilities’ internal generating capacity in an effort to reduce reliance on purchased power. Consistent with this strategy, in 2006 NPC completed construction of the 1200 MW (unit ratings are nominal ratings) gas-fired Chuck Lenzie generating station (“Lenzie”) and acquired a 75% interest in the 560 MW, gas-fired Silverhawk generating station (“Silverhawk”). SPPC is constructing a new 514 MW facility at the Tracy Generating Station. (For further details, see the following Generation sections for NPC and SPPC).
Additionally, as part of the strategy to grow and invest in, and improve the performance of their regulated businesses, the Utilities announced their intention to develop a major energy project located near Ely, Nevada, which will consist of two 750-megawatt coal fired generation units and includes the construction of a 250-mile transmission line to interconnect the transmission systems of NPC and SPPC. The total project costs are estimated to be $3.8 billion. In November 2006, the Public Utilities Commission of Nevada (PUCN) approved NPC’s 2006 Integrated Resource Plan (IRP) and SPPC’s thirteenth amendment to its 2004 IRP. Included in the PUCN’s approval is Phase 1 of the construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities’ have obtained appropriate air permits. The PUCN approved the Utilities’ request to initially allocate Phase 1 costs between NPC and SPPC on an 80/20 split, respectively. The PUCN also required NPC and SPPC to file amendments to their IRPs in early 2008 once elements of the plan, including final costs, can be more accurately estimated. This project and details discussed above are collectively referred to in this report as the “Ely Energy Center”.
As a result of expanded service territory growth, both Utilities have added transmission infrastructure. Discussions of new transmission lines are in NPC’s and SPPC’s respective Transmission sections below.
Nevada state law allows, with PUCN approval, commercial customers with an average annual load of 1 MW or more, to choose alternate energy suppliers. In addition, some large customers may own and operate generation facilities to meet their own energy requirements. One large SPPC mining customer began operating a 118 MW generating facility in December of 2005 and another large SPPC mining customer has begun construction of a 203 MW facility. These matters are discussed further under Competition for NPC and SPPC below.
The Federal Energy Regulatory Commission (FERC), PUCN and, in the case of SPPC, the California Public Utilities Commission (CPUC) regulate portions of the Utilities’ accounting practices and electricity and natural gas rates. The FERC regulates the terms and prices of transmission services and sales of wholesale electricity. The PUCN and CPUC have authority over general and energy rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.
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 SPR’s, NPC’s and SPPC’s websites (www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com) 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. Available on the sierrapacificresources.com website is the code of ethics for the chief executive officer, chief financial officer and controller, charters for the Audit, Compensation and Nominating and Governance Committees of SPR’s Board of Directors and our corporate
4
governance and standards of conduct guidelines. Printed copies of these documents may be obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O. Box 30150, Reno, NV 89520-3150.
NEVADA POWER COMPANY
NPC is a Nevada corporation organized in 1921 and, by itself and through a predecessor corporation, has been providing electric services to southern Nevada since 1906. NPC became a subsidiary of SPR in July 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.
Nevada Electric Investment Company (NEICO) is a wholly-owned subsidiary of NPC. NEICO is a 25% member of Northwind Aladdin, LLC, which operates the central energy plant at the Aladdin Resort and Casino in Las Vegas. The other 75% is owned by Macquarie Infrastructure Company Trust.
Business and Competitive Environment
Overview
NPC is a public utility that generates, transmits and distributes electric energy in southern Nevada. At year-end 2006, NPC served approximately 807,000 customers in Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining areas, including Nellis Air Force Base and the Department of Energy’s Nevada Test Site in Nye County.
Electric Operations
NPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors in Southern Nevada. In addition to customer growth, demand and resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. NPC’s peak demand occurs in the summer. Therefore, NPC’s revenues and associated expenses are not incurred or generated evenly throughout the year.
To serve its growing customer base, NPC purchases power and generates electricity in accordance with an Energy Supply Plan, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. NPC’s strategy is to grow its internal generating capacity in an effort to reduce reliance on purchased power. Consistent with this strategy, in 2006, NPC completed construction of Lenzie and acquired Silverhawk, as discussed in further detail under the Generation section. Additionally, in November 2006, the PUCN approved NPC’s 2006 IRP. Included in the PUCN’s approval of NPC’s 2006 IRP, are the Ely Energy Center and the construction of 600 MW peaking units at Clark Station at an estimated cost of $395 million.
Nevada regulations require NPC to file general rate cases every two years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require NPC to make annual filings to reset Base Tariff Energy Rates (BTER) and either recover or credit balances that have been deferred representing fuel and purchased power costs incurred compared with amounts collected in current retail rates. If necessary, NPC can file more than once a year to seek a change in BTER to more closely match its actual costs. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3,Regulatory Actions, of the Notes to Financial Statements.
Under federal law, wholesale rates charged by NPC 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 NPC’s sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which NPC takes service.
Competition
State law 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. The law 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 NPC, the departure must not burden NPC 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 to NPC. Customers wishing to choose a new supplier must provide 180-day notice to NPC. NPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce NPC’s need to purchase power from potentially volatile wholesale energy markets.
Currently, there are no material applications pending with the PUCN to exit the system in NPC’s service territory.
5
Sales
NPC’s service territory continues to be among one of the fastest growing areas in the nation. In 2006, NPC set 44,103 meters and it is forecasted that NPC will set over 37,000 in 2007. In 2006, NPC’s operating revenues were approximately $2.1 billion.
Summer peak loads are driven by air conditioning demand. 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 peak load increased at an average annual growth rate of 4.7% over the past five years, reaching 5,623 MW in July 2006. NPC’s retail total electric megawatt-hour (MWh) sales have increased at an average annual growth rate of 4.3% over the past five years.
NPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh sales:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | MWH Sales (Billed and Unbilled) |
| | | 2006 | | 2005 | | 2004 |
| Residential | | | 9,033,142 | | | | 42.3 | % | | | 8,288,309 | | | | 41.3 | % | | | 7,981,116 | | | | 40.1 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Commercial & Industrial: | | | | | | | | | | | | | | | | | | | | | | | | |
| Gaming/Recreation/Restaurants | | | 3,736,608 | | | | 17.5 | % | | | 3,711,790 | | | | 18.5 | % | | | 3,587,428 | | | | 18.0 | % |
| All Other Retail | | | 8,049,753 | | | | 37.7 | % | | | 7,454,595 | | | | 37.1 | % | | | 7,038,692 | | | | 35.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Retail | | | 20,819,503 | | | | 97.5 | % | | | 19,454,694 | | | | 96.9 | % | | | 18,607,236 | | | | 93.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Wholesale | | | 244,128 | | | | 1.2 | % | | | 278,527 | | | | 1.4 | % | | | 870,398 | | | | 4.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Sales to Public Authorities | | | 281,369 | | | | 1.3 | % | | | 349,912 | | | | 1.7 | % | | | 408,927 | | | | 2.1 | % |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 21,345,000 | | | | 100 | % | | | 20,083,133 | | | | 100 | % | | | 19,886,561 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Growth in NPC’s residential class sales continues primarily as a result of new home construction in Las Vegas and the surrounding areas. New home sales in the Las Vegas area in 2006 totaled 36,051.
Tourism and gaming remain southern Nevada’s leading industries and together comprise one of NPC’s largest classes of customers (see Gaming/Recreation/Restaurants above). Currently, there are two major projects under construction in Las Vegas with over $11 billion estimated in construction costs.
The decrease in wholesale was due primarily to certain types of transactions that were reported in sales for 2004 and are now being netted in purchase power.
The decrease in sales to public authorities was due to Southern Nevada Water Authority (SNWA) moving to a distribution only service (DOS) tariff. The DOS tariff allows certain customers to obtain energy from other entities but still continue to have that energy delivered over our transmission and distribution lines.
Demand
Load and Resources Forecast
NPC’s integrated peak electric demand rose from 5,563 MW in 2005 to 5,623 MW in 2006. Variations in energy usage by NPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.
NPC plans to meet its customers’ needs through a combination of company-owned-generation and purchased power. NPC filed its 2006 Integrated Resource Plan (IRP) with the PUCN, pursuant to which the company received approval to commence construction of peaking units at Clark Station. The first 413 MW of the Clark peaking units have a scheduled in-service date of June 2008 and the remaining 206 MW has a scheduled in-service date of June 2009. These additional units will reduce NPC’s reliance on purchased power. Remaining needs will be met through power purchases through RFPs or short term purchases.
6
Below is a table summarizing the forecasted summer electric capacity requirement and resource needs of NPC (assuming no curtailment of supply or load, and normal weather conditions):
| | | | | | | | | | | | | | | | | | | | | |
| | | Forecasted Electric Capacity |
| | | Requirements and Resources (MW) |
| | | 2007 | | 2008 | | 2009 | | 2010 | | 2011(4) |
| Total Requirements (1) | | | 6,745 | | | | 7,026 | | | | 7,360 | | | | 7,668 | | | | 7,971 | |
| | | | | | | | | | | | | | | | | | | | | |
| Resources: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Company-owned existing generation | | | 2,854 | | | | 2,854 | | | | 2,854 | | | | 2,854 | | | | 2,854 | |
| Company-owned new generation (2) | | | | | | | 413 | | | | 619 | | | | 619 | | | | 619 | |
| Contracts for power purchases | | | 3,891 | | | | 1,346 | | | | 1,374 | | | | 1,381 | | | | 1,507 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Resources | | | 6,745 | | | | 4,613 | | | | 4,847 | | | | 4,854 | | | | 4,980 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Additional Required (3) | | | — | | | | 2,413 | | | | 2,513 | | | | 2,814 | | | | 2,991 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Includes system peak load plus planning reserves. |
| |
| (2) | | Clark Station peaking units operational in 2008 and 2009. |
| |
| (3) | | Additional Required is the difference between the total required and currently committed resources. Additional required represents the amount needed to achieve the forecasted system peak plus a planning reserve margin. |
| |
| (4) | | Does not include the Ely Energy Center, as the Ely Energy Center is not expected to be operational until December 2011. |
NPC includes in its long term plans planning reserves in excess of required operating reserves.
Energy Supply
The energy supply function at NPC encompasses the reliable and efficient operation of NPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization.
NPC faces energy supply challenges for its load control area. There is the potential for continued price volatility in NPC’s service territory, particularly during peak periods. A greater dependence on gas-fired generation in the region subjects power prices to gas price volatilities. NPC faces load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to NPC. Finally, NPC’s credit standing may affect the terms or ability to enter into certain transactions.
In response to these energy supply challenges, NPC has adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines that relate 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 a clear distinction between policy setting (or planning) and execution. Lastly, NPC will continue to pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans. Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.
7
Total System
NPC manages a portfolio of energy supply options. The availability of alternate resources allows NPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2006, NPC generated approximately 54.3% of its total electric energy requirements, purchasing the remaining 45.7% as shown below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | MWh | | % of Total | | MWh | | % of Total | | MWh | | % of Total |
| NPC Company Generation | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas/Oil | | | 8,093,020 | | | | 36.1 | % | | | 2,465,064 | | | | 11.7 | % | | | 2,557,166 | | | | 12.3 | % |
| Coal | | | 4,067,209 | | | | 18.2 | % | | | 5,629,139 | | | | 26.9 | % | | | 5,913,062 | | | | 28.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Generated | | | 12,160,229 | | | | 54.3 | % | | | 8,094,203 | | | | 38.6 | % | | | 8,470,228 | | | | 40.7 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased Power | | | | | | | | | | | | | | | | | | | | | | | | |
| Hydro | | | 465,983 | | | | 2.0 | % | | | 409,309 | | | | 2.0 | % | | | 450,086 | | | | 2.2 | % |
| Spot, Firm and Non-Firm | | | 7,453,758 | | | | 33.3 | % | | | 10,301,589 | | | | 49.0 | % | | | 9,458,794 | | | | 45.5 | % |
| Non-Utility Purchases | | | 2,328,653 | | | | 10.4 | % | | | 2,183,484 | | | | 10.4 | % | | | 2,410,381 | | | | 11.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Purchased | | | 10,248,394 | | | | 45.7 | % | | | 12,894,382 | | | | 61.4 | % | | | 12,319,261 | | | | 59.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total System | | | 22,408,623 | | | | 100.0 | % | | | 20,988,585 | | | | 100.0 | % | | | 20,789,489 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
As a supplement to its own generation, NPC purchases spot, short-term firm, intermediate-term firm, long-term 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. NPC’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 NPC’s own generation, again, subject to net system import limits. NPC’s 2006 company generated MWhs increased 50.2% from NPC’s 2005 company generated MWhs. The increase in NPC’s generation in 2006 is primarily due to the purchase of a 75% ownership in the SilverHawk generating station and the addition of the Lenzie generating station. NPC’s 2006 purchased power MWhs decreased 20.5% from NPC’s 2005 purchased power MWhs. See Energy Supply in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding NPC’s purchasing strategies.
Risk Management
See Item 7A, Quantitative and Qualitative Disclosures About Market Risk.
Generation
NPC’s generation capacity consists of a combination of 27 gas, oil and coal generating units with a combined capacity of 3,148 MWs as described in Item 2, Properties. In 2006, NPC generated approximately 54.3% of its total system requirements.
As described earlier, in an effort to reduce reliance on purchased power and diversify energy resources NPC acquired the Lenzie generating plant and a 75% ownership interest in the Silverhawk generating plant. The combination of the two plants added approximately 1,669 MWs of capacity in 2006. Additionally in 2006, NPC added a second 84 MW unit at the Harry Allen generating plant. The increase in capacity was partially offset by the loss of 403 MW of capacity due to the retirement of three steam units at the Clark Plant and the shut-down of the Mohave Plant on December 31, 2005, of which NPC is a 14% owner. See Note 13, Commitments and Contingencies, of the Notes to the Financial Statements, in Item 8 for further discussion of the Mohave shut-down.
In November, 2006, the PUCN approved Phase 1 of the construction of the Ely Energy Center. The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first unit is expected to become operational in late 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable.
Also approved by the PUCN was NPC’s request to construct natural gas-fired combustion turbine peaking units at Clark Station with approximately 413 MWs of peaking capacity to be installed prior to the summer of 2008 and approximately 206 MWs of additional peaking capacity to be installed prior to the summer of 2009.
8
Fuel Availability
NPC’s 2006 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, coal, and oil for energy generation per million British thermal units (MMBtu) for the years 2002-2006, along with the percentage contribution to NPC’s total fuel requirements were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Average Consumption Cost & Percentage Contribution to Total Fuel Requirement |
| | | Gas | | Coal | | Oil |
| | | $/MMBtu | | Percent | | $/MMBtu | | Percent | | $/MMBtu | | Percent |
| 2006 | | | 7.40 | | | | 58.8 | % | | | 1.63 | | | | 41.1 | % | | | 16.66 | | | | 0.1 | % |
| 2005 | | | 6.18 | | | | 32.7 | % | | | 1.59 | | | | 67.1 | % | | | 13.50 | | | | 0.1 | % |
| 2004 | | | 6.13 | | | | 27.3 | % | | | 1.33 | | | | 72.6 | % | | | 8.75 | | | | 0.1 | % |
| 2003 | | | 5.70 | | | | 40.9 | % | | | 1.41 | | | | 59.0 | % | | | 5.28 | | | | 0.1 | % |
| 2002 | | | 5.41 | | | | 38.9 | % | | | 1.37 | | | | 60.9 | % | | | 5.77 | | | | 0.2 | % |
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.
Natural gas supplies are procured one season ahead of use through a competitive bidding process. The gas prices are set at an appropriate industry index during the month of current delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the current energy marketplace. The addition of the Lenzie, Silverhawk and Harry Allen units during 2006 resulted in an increase of company generation. These generating units had the effect of reducing NPC’s exposure to fluctuations in the market price of gas because these units are more efficient than most generating facilities supplying energy to the market in which NPC purchases energy and, consequently, will require less fuel to produce the same amount of electric energy. This trend is expected to continue in 2007 since these generating units will be available for the entire year and NPC has made operating improvements at all sites.
Coal delivered to the Reid Gardner Station originates from various mines in the Utah and Colorado coal fields and is delivered to the station via the Union Pacific Railroad. NPC had five coal contracts which expired on December 31, 2006. These contracts were with Canyon Fuel Company, LLC, a subsidiary of Arch Coal Company, Arch Coal Sales Company, Oxbow Carbon & Minerals, LLC, Andalex Resources, Inc., and Valmy. They provided the full requirements of coal for 2006. During 2006 NPC executed replacement coal supply agreements effective January 2007. These contracts are with Arch Coal Sales Company and Andalex Resources, Inc. and will provide 100%, 75%, 45%, and 30% of Reid Gardner’s projected coal requirements for the years 2007, 2008, 2009, and 2010, respectively.
As of December 31, 2006, Reid Gardner Station’s coal inventory level was 397,033 tons, or approximately 66 days of consumption at 100% capacity.
A transportation services contract with Union Pacific Railroad provides for deliveries from the Provo, Utah interchange as well as various mines in Utah and Colorado, to the Reid Gardner Station in Moapa, Nevada. This contract expires on December 31, 2007.
The Utah Railway contract provides for delivery of all coal not loaded by the Union Pacific in Helper, Utah to interchange with Union Pacific at Provo, Utah. Both of NPC’s rail transportation contracts contain certain tonnage requirements and railroad service criteria.
Coal for the Navajo Station is obtained from surface mining operations conducted by Peabody Coal Company (Peabody) on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian tribes (the Tribes) reservations. The Navajo supply contract expires June 2011, with an option provided to NPC to extend for an additional 15 years.
Purchased Power
NPC, under the guidelines set forth in the NPC Energy Supply Plan, 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 2006, NPC purchased 45.7% of its total energy requirements.
NPC purchases both forward firm energy 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.
9
NPC has entered into long term purchase power contracts (3 or more years) with the following counterparties:
| | | | | | | | | |
| Company Name | | | | |
| (Counterparty) | | Quantity (MW) | | Contract Termination |
| State of Nevada, Colorado River Commission | | 200 MW | | | 2017 | |
| Nevada Sun Peak Limited Partnership | | 222 MW | | | 2016 | |
| Las Vegas Cogeneration II | | 224 MW | | | 2013 | |
| Southern Nevada Water Authority | | 125 MW | | | 2013 | |
| California Department of Water Resources | | 233 MW | | | 2013 | |
| Mirant | | 200 MW | | | 2008 | |
Mirant(1) | | 100 MW | | | 2007 | |
Mirant(1) | | 25 MW | | | 2007 | |
| | |
| (1) | | Effective from June 15th through September 15th each year. |
NPC’s credit standing affects the terms under which NPC is able to purchase fuel and electricity in the western energy markets. As a result of NPC’s improved credit quality, during 2006 NPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and electricity, reduce pre-payments for fuel to four counterparties, and reduce the number of counterparties requiring modified payment terms from the previous year. In early 2007, as further evidence of improving credit quality, NPC’s electric counterparties eliminated the requirement that NPC pre-pay electric purchases.
NPC is a member of the Western Systems Power Pool (WSPP) 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.
Qualifying Facilities
Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA), which were passed to promote renewable and alternative energy resources, and the Energy Policy Act of 2005, set out the requirements for utilities to purchase the output produced by Qualifying Facilities (QFs) at costs determined by the appropriate state’s public utility commission. QFs are small renewable energy power producers and co-generators. Certain QFs can qualify as renewable resources required by state law as discussed below; however, none of NPC’s current QFs qualify.
As of December 31, 2006, NPC had a total of 305 MW of contractual firm and non-firm capacity under contract with QFs. In 2006, energy purchased by NPC from the QFs constituted 22.7% of NPC’s net purchased power requirements for native load and 10.4% of NPC’s net system requirements (including generation).
Renewable Energy
Nevada law sets forth the renewable energy portfolio standard (“Portfolio Standard”) requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable energy resources (Renewables). Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. Pursuant to the Portfolio Standard, NPC was required to obtain six percent of its total energy from Renewables for year 2006. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20% in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources.
Nevada law also requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio Standard Annual Report for Compliance Year 2005, NPC reported that with PUCN approval of a sale and purchase of SPPC’s excess non-solar portfolio energy credits (“PCs”), NPC would meet the non-solar Portfolio Standard. However, NPC was non-compliant with the solar portion of the Portfolio Standard in 2005. Additionally, the report described NPC’s ongoing activities to reach full compliance with the Portfolio Standard in the near future. NPC will be required to meet nine percent (9%) of its total energy from Renewables for years 2007 and 2008.
NPC’s IRP approved by the PUCN in November, included NPC’s three-year Action Plan for acquiring Renewables and developing renewable energy facilities. In addition, in January 2007, the PUCN approved NPC’s Portfolio Standard Annual Report for Compliance Year 2005 and granted its request for the purchase of SPPC’s excess non-solar PCs and granted an exemption from the solar portion of the Portfolio Standard for compliance year 2005.
10
In April 2007, NPC will file with the PUCN its Portfolio Standard Annual Report for Compliance Year 2006. NPC expects it will meet the non-solar Portfolio Standard, but may not meet the solar requirement for 2006. If so, NPC will request an exemption from the PUCN for the solar portion of the Portfolio Standard for calendar year 2006.
Transmission
Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generators can be located anywhere from a few miles to hundreds of miles from customers.
NPC’s electric transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American Electric Reliability Council, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.
NPC’s transmission system links generating units within the NPC control area and generating systems, located external to the NPC control area, to the NPC distribution system. NPC’s transmission system is directly interconnected with the transmission systems of Western Area Power Administration, Los Angeles Department of Water and Power, Southern California Edison, and PacifiCorp. NPC currently is not directly interconnected with SPPC; however, the Ely Energy Center includes a 500 kV line that will interconnect the transmission systems of the two companies by 2011. The map below shows NPC’s transmission system:
As the control area operator, NPC is responsible for continuously balancing electric supply and demand by monitoring and controlling generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. NPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are matching loads with resources.
NPC plans, builds and operates a transmission system that delivered 22,408,623 MWh of electricity to customers on its transmission system in 2006. The NPC system handled a peak load of 5,623 MW in 2006 through 2,062 circuit miles of transmission
11
lines and other transmission facilities ranging from 60kV to 500kV. NPC processes generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this high growth system.
In the last 8 years, due primarily to high customer growth, NPC has constructed 4 major transmission projects totaling 210 miles of high voltage transmission. The projects completed include River Mountain (40 miles), Crystal (10 miles), Bighorn (60 miles), and Centennial (100 miles).
Transmission Regulatory Environment
NPC’s wholesale and retail access transmission services are regulated by the FERC under cost based regulation subject to the SPR Operating Companies Open Access Transmission Tariff (OATT). Transmission for NPC’s bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes. In accordance with the OATT, NPC offers several transmission services to wholesale customers:
| | • | | Long-term and short-term firm point-to-point transmission service (“guaranteed” service with fixed delivery and receipt points), |
| |
| | • | | Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and |
| |
| | • | | Network transmission service (equivalent to the service NPC provides for NPC’s bundled retail customers). |
These services are all offered on a nondiscriminatory basis in that all potential customers, including NPC, have an equal opportunity to access the transmission system. NPC’s transmission business is managed and operated independently from the generating and marketing business in accordance with FERC Standards of Conduct.
NPC is participating in the development of WestConnect. WestConnect is a group of southwest transmission-providing utilities that have agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market. In November 2005, NPC discontinued its relationship with Grid West and joined WestConnect as a member.
Construction Program
NPC’s construction program and estimated expenditures are subject to continuing review, and are revised to include the rate of load growth, 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. Capital construction expenditures and estimates are reflective of NPC’s obligation to serve its growing customer base.
Gross construction expenditures for 2006, including allowance for funds used during construction (AFUDC), net salvage, and contributions in aid of construction, were $670.4 million, and for the period 2002 through 2006, were $2.2 billion. Estimated construction expenditures for 2007 and the period from 2008 to 2011 are as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | | 2008-2011 | | | 5 - Year | |
| Electric Facilities | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Generation | | $ | 537,998 | | | $ | 3,082,351 | | | $ | 3,620,349 | |
| Distribution | | | 211,551 | | | | 888,550 | | | | 1,100,101 | |
| Transmission | | | 140,041 | | | | 1,103,075 | | | | 1,243,116 | |
| Other | | | 136,438 | | | | 403,882 | | | | 540,320 | |
| | | | | | | | | | |
| Total | | $ | 1,026,028 | | | $ | 5,477,858 | | | $ | 6,503,886 | |
| | | | | | | | | | |
12
Total estimated construction and plant cash requirements related to construction projects for 2007 and the 2008 to 2011 period consist of the following (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | | 2008-2011 | | | Total 5 - Year | |
| Construction Expenditures | | $ | 1,026,028 | | | $ | 5,477,858 | | | $ | 6,503,886 | |
| | | | | | | | | | | | | |
| AFUDC | | | (23,373 | ) | | | (487,761 | ) | | | (511,134 | ) |
| Net Salvage/ Cost of Removal | | | (1,800 | ) | | | (7,400 | ) | | | (9,200 | ) |
| Net Customer Advances and CIAC | | | (20,800 | ) | | | (85,305 | ) | | | (106,105 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
| Total Cash Requirements | | $ | 980,055 | | | $ | 4,897,392 | | | $ | 5,877,447 | |
| | | | | | | | | | |
In November, 2006 the PUCN approved NPC’s IRP, which among other items, includes the approval of Phase 1 construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities’ have obtained appropriate air permits. Current estimates to construct the Ely Energy Center, which includes a 500KV transmission line to connect NPC’s and SPPC’s transmission systems is approximately $3.8 billion. NPC’s estimated 80% allocation of the Ely Energy Center is included in construction expenditures above. The PUCN also required that NPC file an amendment to its 2006 IRP in early 2008 once elements of the plan, including final costs, can be more accurately estimated.
Also included in the approval of the IRP was NPC’s request to construct natural gas-fired combustion turbine peaking units at Clark Station at a cost of approximately $395 million with approximately 413 MWs of peaking capacity to be installed prior to the summer of 2008 and approximately 206 MWs of additional peaking capacity to be installed prior to the summer of 2009.
SIERRA PACIFIC POWER COMPANY
A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912. SPPC became a subsidiary of SPR in 1984. Its mailing address is P. O. Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024.
SPPC has two regulated business segments, SPPC electric and SPPC natural gas service, which are discussed separately in this section. SPPC has three primary, wholly owned subsidiaries: GPSF-B, Piñon Pine Corp. (PPC) and Piñon Pine Investment Co. (PPIC). GPSF-B, PPC and PPIC, collectively, own Piñon Pine Company, LLC, which was formed to utilize federal income tax credits available under Section 20 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Piñon Pine Facility.
SPPC Electric
Business and Competitive Environment
Overview
SPPC is a public utility that generates, transmits and distributes electric energy to approximately 361,000 customers. The service territory covers over 50,000 square miles of 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.
Electric Operations
SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth, demand and resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. SPPC’s peak demand occurs in the summer with a slightly lower peak demand in the winter.
To serve its growing customer base, SPPC purchases power and generates electricity in accordance with an Energy Supply Plan, approved by the PUCN, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. SPPC’s strategy is to grow its generating capacity in an effort to reduce reliance on purchased power. As part of this strategy, SPPC is constructing a 514 MW gas-fired combined-cycle plant at Tracy, east of Reno. The plant is scheduled to be completed by the summer of 2008. Additionally, in November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004 IRP. Included in the PUCN’s approval is the Ely Energy Center.
Electric loads and resulting revenues are affected by customer growth, weather, rate changes, and customer usage patterns. SPPC’s revenues and associated expenses are not incurred or generated evenly throughout the year.
13
Nevada regulations require SPPC to file general rate cases every two years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require SPPC to make annual filings to reset BTER and either recover or credit deferred energy balances that include fuel and purchased power costs above or below amounts collected in current retail rates. If necessary, SPPC can file more frequently than once a year to seek a change in BTER to more closely match actual prices. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.
Under federal law, wholesale rates charged by SPPC 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 SPPC’s sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which SPPC takes service.
Competition
Nevada state law 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. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet certain public interest standards. In particular, departing customers must secure new energy resources that are not under contract to SPPC, the departure must not burden SPPC 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 to SPPC. Customers wishing to choose a new supplier must provide 180-day notice to SPPC. SPPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce SPPC’s need to purchase power from potentially volatile wholesale energy markets.
In December 2005, Barrick Gold (Barrick), a large SPPC mining customer, concluded its construction of a 118 MW generating facility to meet the majority of its electric power needs. Barrick continues to purchase transmission and distribution services from SPPC and is selling approximately 8 MW of capacity from its new generating facility to SPPC. Barrick MWh retail sales for 2005 were approximately 10.1% of total system sales for SPPC.
Newmont Mining Corporation (Newmont) is constructing a new 203 MW generating plant in northeastern Nevada which is anticipated to be operational in 2008. In 2004, SPPC and Newmont entered into a nonbinding Term Sheet that provides for a wholesale power sale agreement and a new form of retail service. Under the term sheet, Newmont would sell the electrical output from its plant to SPPC for at least 15 years under a long-term wholesale, purchased power agreement, and remain a retail customer of SPPC during at least that period under the terms of a retail service agreement and pursuant to a new rate schedule. SPPC and Newmont submitted a number of related filings to the PUCN which were approved on February 23, 2005.
Currently, there are no other material applications pending with the PUCN to exit the system in SPPC’s service territory.
Sales
In 2006, SPPC set approximately 9,950 meters and forecasts that it will set over 9,000 meters in 2007. In 2006, SPPC’s electric operations contributed approximately $1.0 billion, or 83%, of SPPC’s total revenues.
Summer retail peak loads are primarily driven by air conditioning demand and irrigation pumping. Winter retail electric peak loads are primarily driven by increased demand for space heating, air movement (with forced air gas and oil furnaces), and ski resorts (hotels, lifts, etc.). SPPC’s peak load increased at an average annual growth rate of 2.2% over the past five years, reaching 1,701 MW in July 2006.
14
SPPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh sales:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | MWH Sales (Billed and Unbilled) |
| | | 2006 | | 2005 | | 2004 |
| Retail: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 2,480,681 | | | | 28.2 | % | | | 2,381,389 | | | | 25.5 | % | | | 2,295,944 | | | | 23.8 | % |
| Commercial and Industrial: | | | | | | | | | | | | | | | | | | | | | | | | |
| Mining | | | 1,873,177 | | | | 21.3 | % | | | 2,716,309 | | | | 29.1 | % | | | 2,686,716 | | | | 27.8 | % |
| All Other | | | 4,356,878 | | | | 49.5 | % | | | 4,136,208 | | | | 44.3 | % | | | 4,160,567 | | | | 43.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Retail | | | 8,710,736 | | | | 99.0 | % | | | 9,233,906 | | | | 98.9 | % | | | 9,143,227 | | | | 94.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Wholesale | | | 69,757 | | | | 0.8 | % | | | 81,856 | | | | 0.9 | % | | | 505,986 | | | | 5.2 | % |
| Streetlights | | | 15,502 | | | | 0.2 | % | | | 15,105 | | | | 0.2 | % | | | 14,932 | | | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| TOTAL | | | 8,795,995 | | | | 100 | % | | | 9,330,867 | | | | 100 | % | | | 9,664,145 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
In 2006, mining MWh sales decreased significantly due to the departure of Barrick which represented approximately 10.1% of total system sales in 2005. However, Nevada’s precious metals mining industry continued to see positive developments as the spot price of gold on world markets increased in 2006 by 19%, from $530 per ounce on January 3, 2006 to $632 per ounce on December 28, 2006, as reported by Kitco.com. . This increase in price, coupled with Nevada’s reasonable regulatory environment and favorable geology for gold deposits, offers positive opportunities for future mine development. Given the substantial amounts of both proven and probable gold reserves at existing mining operations and the industry’s strong presence in the state, the mining industry’s resulting high energy usage is expected to continue into the future, assuming that gold prices stay high.
SPPC has long-term electric service agreements with six of its major mining customers, with yearly revenues under these agreements totaling approximately $94.7 million. For 2006, this represented 9.3% of SPPC’s electric operating revenues of $1.0 billion. These agreements include requirements for customers to maintain minimum demand and load factor levels. In addition, they include provisions to recover all investments for customer-specific facilities that have been made by SPPC on their behalf.
In 2005, MWh sales in the wholesale segment decreased by 83.8% compared to sales in 2004. This decrease was a result of market conditions that resulted in fewer economic opportunities in layoffs/swap sales and purchases in 2005 compared to 2004. In addition, certain types of transactions that were reported in sales for 2004 are now being netted in purchased power.
Demand
Load and Resources Forecast
SPPC’s integrated peak electric demand dropped from 1,740 MW in 2005 to 1,701 MW in 2006 mainly due to the Barrick departure from SPPC’s system. Variations in energy usage by SPPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.
SPPC plans to meet its customers’ needs through a combination of company-owned generation and purchased power. As discussed in Energy Supply – Generation, SPPC is constructing a new 514 MW Combined Cycle facility at the existing Tracy Generating Station with a scheduled in-service date of June 2008. The addition of this facility is expected to significantly reduce SPPC’s reliance on purchased power compared to prior years. Remaining needs will be met through power purchased through RFPs or short term purchases.
15
Below is a table summarizing the forecasted summer electric capacity requirement and resource needs of SPPC (assuming no curtailment of supply or load, and normal weather conditions):
| | | | | | | | | | | | | | | | | | | | | |
| | | Forecasted Electric Capacity |
| | | Requirements and Resources (MW) |
| | | 2007 | | 2008 | | 2009 | | 2010 | | 2011(4) |
| Total Requirements (1) | | | 1,870 | | | | 2,051 | | | | 2,134 | | | | 2,177 | | | | 2,211 | |
| | | | | | | | | | | | | | | | | | | | | |
| Resources: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Company-owned existing generation | | | 1,023 | | | | 1,023 | | | | 1,035 | | | | 1,035 | | | | 1,035 | |
| Company-owned new generation (2) | | | | | | | 514 | | | | 514 | | | | 514 | | | | 514 | |
| Contracts for power purchases | | | 847 | | | | 257 | | | | 213 | | | | 261 | | | | 279 | |
| | | | | | | | | | | | | | | | | | | | | |
| Currently Committed Resources | | | 1,870 | | | | 1,794 | | | | 1,762 | | | | 1,810 | | | | 1,828 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Additional Required (3) | | | — | | | | 257 | | | | 372 | | | | 367 | | | | 383 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Includes system peak load plus planning reserves. |
| |
| (2) | | New generation in 2008 for Tracy combined cycle facility at 514 MW. |
| |
| (3) | | Additional Required represents the difference between the current committed resources and the total resources needed to achieve the forecasted system peak plus a planning reserve margin. |
| |
| (4) | | Does not include the Ely Energy Center, as the Ely Energy Center is not expected to be operational until December 2011. |
SPPC includes in its long term plans planning reserves in excess of required operating reserves.
Energy Supply
The energy supply function at SPPC encompasses the reliable and efficient operation of SPPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization.
SPPC faces energy supply challenges for its load control area. There is the potential for continued price volatility in SPPC’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. SPPC faces load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to SPPC. Finally, SPPC’s credit standing may affect the terms or ability to enter into certain transactions.
In response to these energy supply challenges, SPPC has 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 a clear distinction between policy setting (or planning) and execution. Lastly, SPPC will continue to pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans. Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.
16
Total System
SPPC manages a portfolio of energy supply options. 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. During 2006, SPPC generated 43.1% of its total electric energy requirements, purchasing the remaining 56.9% as shown below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | MWh | | % of Total | | MWh | | % of Total | | MWh | | % of Total |
| SPPC Company Generation | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas/Oil | | | 2,210,532 | | | | 23.4 | % | | | 2,345,196 | | | | 23.9 | % | | | 2,562,103 | | | | 24.8 | % |
| Coal | | | 1,848,591 | | | | 19.7 | % | | | 2,000,719 | | | | 20.4 | % | | | 2,018,715 | | | | 19.6 | % |
| Hydro | | | 0 | | | | N/A | | | | 33,355 | | | | 0.3 | % | | | 24,090 | | | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Generated | | | 4,059,123 | | | | 43.1 | % | | | 4,379,270 | | | | 44.6 | % | | | 4,604,908 | | | | 44.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased Power | | | | | | | | | | | | | | | | | | | | | | | | |
| Spot, Firm and Non-Firm | | | 4,392,896 | | | | 46.8 | % | | | 4,778,786 | | | | 48.7 | % | | | 4,845,650 | | | | 46.9 | % |
| Non-Utility Purchases | | | 941,445 | | | | 10.1 | % | | | 662,261 | | | | 6.7 | % | | | 873,868 | | | | 8.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Purchased | | | 5,334,341 | | | | 56.9 | % | | | 5,441,047 | | | | 55.4 | % | | | 5,719,518 | | | | 55.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total System | | | 9,393,464 | | | | 100.0 | % | | | 9,820,317 | | | | 100.0 | % | | | 10,324,426 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
As a supplement to its own generation, SPPC purchases spot, short-term firm, intermediate-term firm, long-term 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. The decrease in total system was primarily due to the transition of Barrick to a distribution only services customer in 2006. SPPC’s 2006 company generation decreased 7.3% compared to 2005. SPPC’s 2006 purchased power total MWhs decreased 2.0% from SPPC’s 2005 purchased power MWhs. 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.
Generation
SPPC’s generation capacity consists of a combination of 24 gas, oil and coal generating units with a combined capacity of 1,043 MWs as described in Item 2, Properties. In 2006, SPPC generated approximately 43.1% of its total system requirements.
In an effort to reduce reliance on purchased power and diversify energy resources, SPPC is constructing a 514 MW gas fired combined cycle generator at the Tracy station. The unit is expected to be operable by June 2008.
In November, 2006, the PUCN approved SPPC’s Phase 1 of the construction of the Ely Energy Center. The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first unit is expected to become operational in late 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable.
17
Fuel Availability
SPPC’s 2006 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, coal and oil for energy generation per MMBtu for the years 2002-2006, along with the percentage contribution to SPPC’s total fuel requirements, were as follows:
Average Consumption Cost & Percentage Contribution to Total Fuel
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gas | | Coal | | Oil |
| | | $/MMBtu | | Percent | | $/MMBtu | | Percent | | $/MMBtu | | Percent |
| 2006 | | | 8.92 | | | | 55.85 | % | | | 1.83 | | | | 43.88 | % | | | 10.15 | | | | .27 | % |
| 2005 | | | 7.87 | | | | 56.81 | % | | | 1.67 | | | | 43.08 | % | | | 7.37 | | | | .11 | % |
| 2004 | | | 7.32 | | | | 53.11 | % | | | 1.39 | | | | 44.93 | % | | | 6.14 | | | | 1.96 | % |
| 2003 | | | 6.68 | | | | 59.11 | % | | | 1.60 | | | | 40.79 | % | | | 6.92 | | | | .10 | % |
| 2002 | | | 4.42 | | | | 41.10 | % | | | 1.68 | | | | 58.70 | % | | | 5.69 | | | | .20 | % |
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.
Natural gas supplies are procured one season ahead of use through a competitive bidding process. The gas prices are set at an appropriate industry index during the month of current delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the current energy marketplace.
SPPC has long-term coal contracts with Arch Coal Sales Company and Black Butte Coal Company that provide for deliveries through December 31, 2009. These contracts represent 100% of Valmy’s projected coal requirements in 2007, and 75% of Valmy’s projected coal requirements for 2008 and 2009.
Union Pacific Railroad originates and delivers coal to the Valmy station. A transportation services contract is in place that expires December 31, 2007.
As of December 31, 2006, Valmy’s coal inventory level was 354,103 tons or approximately 62 days of consumption at 100% capacity.
SPPC meets its needs for residual oil and diesel for generation through purchases on the spot market. SPPC attempts to maintain an actual residual oil inventory target level of about 325,000 barrels, which is equal to a 14-day supply at full load operation.
Purchased Power
SPPC, under the guidelines set forth in the SPPC Energy Supply Plan, 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 2006, SPPC purchased 56.9% of its total energy requirement.
SPPC purchases hydroelectric and thermal generation spot market energy, by the hour and by monthly RFP’s, based upon economics and system import limits. Firm energy is also purchased during peak load periods 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.
SPPC has entered into long term purchase power contracts (3 or more years) with the following counterparties:
| | | | | |
| Energy Provider | | Capacity | | Expiration |
| Pacificorp | | 75 MW | | 2009 |
| Barrick | | 8 MW | | 2008 |
SPPC’s credit standing affects the terms under which SPPC is able to purchase fuel and electricity in the western energy markets. As a result of SPPC’s improved credit quality, during 2006 SPPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and electricity; reduce pre-payments for fuel to four counterparties; and reduce the number of counterparties requiring modified payment terms from the previous year. In early 2007 as further evidence of improving credit quality, SPPC’s electric counterparties eliminated the requirement that SPPC pre-pay electric purchases.
18
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.
Qualifying Facilities
Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA), which were passed to promote renewable and alternative energy resources, and the Energy Policy Act of 2005 set out the requirements for utilities to purchase the output produced by Qualifying Facilities (QFs) at costs determined by the appropriate state’s public utility commission. QFs are small renewable energy power producers and co-generators. Certain QFs can qualify as renewable resources required by state law as discussed below.
As of December 31, 2006, SPPC had a total of 151 MW of contractual firm and non-firm capacity under contract with QFs. In 2006, energy purchased by SPPC from the QFs constituted 17.4% of SPPC’s net purchased power requirements for native load and 9.9% of SPPC’s net system requirements (including generation).
Renewable Energy
Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from Renewables. Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. Pursuant to the Portfolio Standard, SPPC was required to obtain six percent of its total energy from Renewables for year 2006. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20 percent in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25 percent of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources.
Nevada law also requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio Standard Annual Report for Compliance Year 2005, SPPC reported compliance with the non-solar Portfolio Standard. However, SPPC was non-compliant with the solar portion of the Portfolio Standard in 2005. Additionally the report described SPPC’s ongoing activities to reach full compliance with the Portfolio Standard in the near future. SPPC will be required to meet nine percent (9%) of its total energy from Renewables for years 2007 and 2008.
In August 2006, the PUCN approved a long-term power purchase agreement for supply of renewable energy and portfolio energy credits (“PCs”) to SPPC from a project known as Galena 3 Geothermal Project being developed by Ormat Nevada, Inc.
In January 2007, the PUCN approved SPPC’s Portfolio Standard Annual Report for Compliance Year 2005 and granted its request for an exemption from the solar portion of the Portfolio Standard for compliance year 2005.
In April 2007, SPPC will file with the PUCN its Portfolio Standard Annual Report for Compliance Year 2006. SPPC expects it will meet the non-solar Portfolio Standard, but may not meet the solar requirement for 2006. If so, SPPC will request an exemption from the PUCN for the solar portion of the Portfolio Standard for calendar year 2006.
Transmission
Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because generators can be located anywhere from a few miles to hundreds of miles from customers.
SPPC’s electric transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American Electric Reliability Council, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.
SPPC’s transmission system links generating units within the SPPC control area to the SPPC distribution system. SPPC’s transmission system is directly interconnected with the transmission systems of Idaho Power, Los Angeles Department of Water and Power, Southern California Edison, PacifiCorp, Bonneville Power Administration, Pacific Gas & Electric and Plumas Sierra Rural Electric Cooperative. SPPC currently is not directly interconnected with NPC; however, the Ely Energy Center includes a 500 kV line that will interconnect the transmission systems of the two companies by 2011. The map below shows SPPC’s transmission system:
19
As the control area operator, SPPC is responsible for continuously balancing electric supply and demand by monitoring and controlling generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. SPPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are matching loads with resources.
SPPC plans, builds and operates a transmission system that delivered 9,393,464 MWh of electricity to customers in its control area in 2006. The SPPC system handled a peak load of 1,701 MW in 2006 through 2,446 circuit miles of transmission lines and other facilities ranging from 60kV to 345kV. SPPC processes generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this fast growing system.
In the last 8 years, due primarily to high customer growth, SPPC has constructed 2 major transmission projects totaling 347 miles of high voltage transmission. The projects completed include Alturas (167 miles), and Falcon – Gonder (180 miles).
Transmission Regulatory Environment
SPPC’s wholesale and retail access transmission services are regulated by the FERC under cost based regulation subject to the SPR Operating Companies Open Access Transmission Tariff (OATT). Transmission for SPPC’s bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes. In accordance with the OATT, SPPC offers several transmission services to wholesale customers:
| | • | | Long-term and short-term firm point-to-point transmission service (“guaranteed” service with fixed delivery and receipt points), |
| |
| | • | | Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and |
| |
| | • | | Network transmission service (equivalent to the service SPPC provides for SPPC’s bundled retail customers). |
These services are all offered on a nondiscriminatory basis in that all potential customers, including SPPC, have an equal opportunity to access the transmission system. SPPC’s transmission business is managed and operated independently from the generating and marketing business in accordance with FERC Standards of Conduct.
20
SPPC is participating in the development of WestConnect. WestConnect is a group of southwest transmission-providing utilities that have agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market. In early 2006, SPPC discontinued its relationship with Grid West and joined WestConnect as a member.
SPPC Gas
Business and Competitive Environment
Overview
SPPC provides natural gas service to approximately 146,000 customers in an area of about 600 square miles in Nevada’s Reno/Sparks area. SPPC also procures natural gas for electric power generation at the Tracy and Fort Churchill plants east of Reno.
Gas Operations
SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth and demand, resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. Gas demand and revenues are very seasonal for SPPC Gas. Average daily temperatures range from 71 to 34 degrees Fahrenheit and the average high temperature to low temperature range from 91 to 21 degrees Fahrenheit. This wide temperature swing causes gas send-out to vary substantially from a warm summer day to a cold winter day.
In recent years, natural gas prices have trended upward and fluctuated widely, depending on such factors as weather, supply, demand, and the cost of competing fuels. Natural gas supply and demand fundamentals indicate immediate continued volatility. Relatively low-priced sources of fuel have been somewhat depleted and new supply is expensive to bring on-line. Additionally, gas demand has steadily increased, particularly due to an increase in gas-fired electric generation on a national level. Much of SPPC’s electric generation resources use natural gas as their primary fuel source.
To serve its growing customer base, SPPC purchases all of its natural gas supply. SPPC is well connected with several major gas producing regions and the gas transport system into Northern Nevada is robust. SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines: Paiute Pipeline Company and Tuscarora Gas Transmission. In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.
Nevada state regulations require annual filings to reset base purchased gas rates and recover deferred balances that include purchased gas costs above or below amounts collected in current rates. The regulations also require a Gas Supply Plan to be filed annually. Natural gas commodity costs are passed directly through to customers on a dollar for dollar basis. SPPC does not profit from increased natural gas prices. SPPC may also file general rate cases to adjust gas division rates including cost of service and return on investment. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.
Competition
SPPC’s natural gas local distribution company (LDC) business is subject to competition from other suppliers and other forms of energy available to its customers. Large gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the Incentive Natural Gas Rate (INGR) tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose their source of fuel. Additionally, customers using greater than 1,000 therms per day have the ability to secure their own gas supplies. As of January 1, 2007, there were 15 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 4,940 Decatherms (Dth) per day. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own gas supply, which reduces SPPC’s purchases, but does not have an impact on net income.
Revenue
SPPC’s natural gas business accounted for $210 million in 2006 operating revenues or 17% of SPPC’s total revenues from continuing operations. SPPC expects to install approximately 5,000 meters in 2007.
Demand
Growth in all sectors is expected to continue as a result of new real estate developments under construction and planned for the near future in SPPC’s distribution service area. Projected peak demand, which will only occur when the temperature drops to 3 degrees Fahrenheit, is estimated to be 193,500 Dth for the winter of 2006/2007, up from 187,000 Dth for the previous winter.
21
To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with over two dozen Canadian and domestic suppliers. Seasonal and monthly gas supply contracts averaged approximately 116,000 Dth per day with the winter period contracts averaging approximately 134,000 Dth per day, and the summer period contracts averaging approximately 103,000 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. The Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies. SPPC also has storage on the Paiute Pipeline system. This liquefied gas storage project provides for an incremental supply of 23,000 Dth per day and is available at any time with two hours notice. Therefore, this storage project supports increases in short term gas supply needs due to unforeseen events such as extreme weather patterns and pipeline interruptions.
Following is a summary of SPPC’s transportation and storage portfolio as of December 31, 2006:
Firm Transportation Capacity
| | | | | | | | | |
| Northwest | | | 68,664 | | | decatherms per day firm | | (Annual) |
| Paiute | | | 68,696 | | | decatherms per day firm | | (November through March) |
| Paiute | | | 61,044 | | | decatherms per day firm | | (April through October) |
| Paiute | | | 23,000 | | | decatherms per day firm | | (LNG tank to Reno/Sparks) |
| Nova | | | 130,217 | | | decatherms per day firm | | (Annual) |
| ANG | | | 128,932 | | | decatherms per day firm | | (Annual) |
| GTN | | | 130,169 | | | decatherms per day firm | | (November through April) |
| GTN | | | 69,899 | | | decatherms per day firm | | (May through October) |
| Tuscarora | | | 132,823 | | | decatherms per day firm | | (Annual) |
Storage Capacity
| | | | | | | |
| Williams: | | | 281,242 | | | decatherms inventory capability at Jackson Prairie |
| | | | 12,687 | | | decatherms withdrawal capability per day from Jackson Prairie |
| Paiute | | | 303,604 | | | Decatherms inventory capability at Paiute LNG |
| | | | 23,000 | | | LNG Storage |
Total LDC Dth supply requirements in 2006 and 2005 were 15.5 million Dth and 17.1 million Dth, respectively. Electric generating fuel requirements for 2006 and 2005 were 23.5 million Dth and 24.3 million Dth, respectively.
Gas Distribution
As of December 31, 2006, SPPC owned and operated 1,988 miles of three-inch equivalent natural gas distribution piping. SPPC constructed approximately 2,600 feet of 12” steel gas main in the Stead area in 2006. SPPC also continued to increase its ongoing main and service replacement projects by replacing approximately 10,700 feet of various sized sections of main and approximately 124 services in 2006.
SPPC Electric and Gas
Construction Program
SPPC’s construction program and estimated expenditures are subject to continuing review and are revised to include 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, SPPC’s other cash needs 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. Capital construction expenditures and estimates are reflective of SPPC’s obligation to serve its growing customer base.
22
SPPC’s gross construction expenditures for 2006, including AFUDC and contributions in aid of construction, were $316 million, and for the period 2002 through 2006, were $844 million. Estimated construction expenditures for 2007 and the period 2008-2011 are as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | | 2008-2011 | | | 5 - Year | |
| Electric Facilities: | | | | | | | | | | | | |
| Generation | | $ | 309,256 | | | $ | 871,233 | | | $ | 1,180,489 | |
| Distribution | | | 61,596 | | | | 262,460 | | | | 324,056 | |
| Transmission | | | 54,301 | | | | 328,646 | | | | 382,947 | |
| Other | | | 29,258 | | | | 123,852 | | | | 153,110 | |
| | | | | | | | | | |
| Total | | | 454,411 | | | | 1,586,191 | | | | 2,040,602 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Gas Facilities: | | | | | | | | | | | | |
| Distribution | | | 16,652 | | | | 70,944 | | | | 87,596 | |
| Other | | | 80 | | | | 339 | | | | 419 | |
| | | | | | | | | | |
| Total | | | 16,732 | | | | 71,283 | | | | 88,015 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
| Common Facilities | | | 15,349 | | | | 64,965 | | | | 80,314 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
| TOTAL | | $ | 486,492 | | | $ | 1,722,439 | | | $ | 2,208,931 | |
| | | | | | | | | | |
Total estimated construction and plant cash requirements for 2007 and the 2008-2011 periods consist of the following (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | | 2008-2011 | | | Total 5 - Year | |
| Construction Expenditures | | $ | 486,492 | | | $ | 1,722,439 | | | $ | 2,208,931 | |
| | | | | | | | | | | | | |
| AFUDC | | | (28,926 | ) | | | (120,038 | ) | | | (148,964 | ) |
| Net Salvage/ Cost of Removal | | | (2,800 | ) | | | (11,465 | ) | | | (14,265 | ) |
| Net Customer Advances and CIAC | | | (22,000 | ) | | | (90,230 | ) | | | (112,230 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
| Total Cash Requirements | | $ | 432,766 | | | $ | 1,500,706 | | | $ | 1,933,472 | |
| | | | | | | | | | |
In December 2005, the PUCN approved the construction of a 514-megawatt, combined cycle natural gas power plant at Tracy Generating Station. Estimated construction costs are approximately $421 million with completion expected in 2008. Total project cost incurred was $168.9 million as of December 31, 2006.
In November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004 IRP, which among other items includes the approval of Phase 1 construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities have obtained appropriate air permits. Current estimates to construct the Ely Energy Center, which includes a 500KV transmission line to connect NPC and SPPC transmission systems is approximately $3.8 billion. SPPC’s estimated 20% allocation is included in construction expenditures above.
OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES
Tuscarora Gas Pipeline Company
Tuscarora Gas Pipeline Company (TGPC) was formed in 1993 as a wholly owned subsidiary of SPR 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 (TGTC) owned 50% by TGPC was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding natural gas market in northern Nevada and northeastern California. In November 2006, TGPC announced that it entered into an agreement to sell its interest in TGTC to TC PipeLines, LP for $100 million. In December 2006, TC PipeLines, LP assumed TGPC’s share in the pipeline company.
As an interstate natural gas pipeline, TGTC provides only transportation service to its customers. SPPC was the only customer at the start of commercial operations in 1995 and while TGTC serves many other customers today, SPPC continues to be TGTC’s largest customer contributing 71.2% of gross revenues in 2006.
23
Sierra Pacific Communications
Sierra Pacific Communications (SPC) was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC entered 2004 with two distinct business areas. The first involved a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the Long Haul System) and the second was the Metro Area Network (MAN) business in Las Vegas and Reno, Nevada.
In 2004, SPC disposed of their MAN assets and recognized a gain on sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets. SPC retained possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. In 2004, in accordance with Statement of Financial Accounting Standards 144 (SFAS 144),Accounting for the Disposition or Impairment of Long-Lived Assets, SPR reported the remaining Long Haul System as discontinued operations. However, due to certain legal issues, SPC was delayed in consummating the sale of the Long Haul System to Qwest. In January 2007, SPC agreed to dismiss pending arbitration against Qwest. As part of the Settlement Agreement, Qwest agreed to execute a quit claim deed disclaiming any further interest in the Long Haul system. In accordance with SFAS 144, if at any time the criteria for classifying assets as held for sale are no longer met, a long-lived asset classified as held for sale shall be reclassified as held and used. As of December 31, 2006, SPC assets associated with the Long-Haul were reclassified for all periods presented from assets held for sale in Discontinued Operations to assets held and used.
Lands of Sierra
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. In keeping with SPR’s strategy to focus on its core energy business, LOS continues to sell its remaining properties, which are located in Nevada and are of minimal book value. LOS does not materially contribute to the results of operations of SPR.
For a discussion of other subsidiaries’ results of operations, refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
ENVIRONMENTAL (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 Department of Air Quality and Environmental Management (DAQEM) administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. See Note 13, Commitments and Contingencies, Environmental of the Notes to Financial Statements, for further discussion.
Federal Legislative and Regulatory Initiatives
The topic of climate change continues to evolve, and response to this issue brings with it environmental, economic and social implications for SPR and other electric utilities. The United States currently has no policy or regulation to address greenhouse gas emissions; the main emphasis to date being reliance on voluntary measures. While several bills have been introduced in Congress that would address carbon dioxide emissions, none have been enacted to-date. Environmental advocacy groups and regulatory agencies in the United States are also focusing considerable attention on carbon dioxide emissions from power generating facilities and their potential role in climate change.
Every generation alternative – whether fossil fuels, nuclear, or renewable power options– has environmental and financial impacts. SPR recognizes these impacts and closely links its business objective of generating reliable, cost-effective energy with its environmental responsibilities. SPR has and will continue to identify projects that minimize or offset greenhouse gas emissions and believes precautionary actions to slow greenhouse gas emissions are appropriate. In 2006, SPR joined the California Climate Action Registry, in which SPR will voluntarily inventory, certify and publicly report on greenhouse gas emissions from NPC and SPPC by the end of 2007.
SPR’s environmental philosophy accentuates prudent use of natural resources and to that end, SPR supports multiple program areas aimed at achieving overall air emission reductions. Some examples are:
| | • | | Installation of commercially-proven pollution controls coupled with an emphasis on continued operational excellence to achieve further plant efficiency improvements. SPR’s new natural gas-fired generating plants require the combustion of far less fuel than older facilities to produce each kilowatt hour of electrical output. As new generation is added to the system, SPR is concurrently evaluating and eliminating older, less efficient units from its fleet. |
24
| | • | | Maintenance of robust demand-side management programs, including energy efficiency and conservation education and support. These programs increase the adoption of energy-efficient equipment by our customers, thereby creating savings on energy bills and potentially delaying the need for additional power plant, transmission, and distribution construction. |
| |
| | • | | Development of technology solutions through funding and participation in collaborative research programs for advanced coal technologies, as well as potential options for carbon sequestration. SPR is reserving space in its proposed Ely Energy Center design that will allow the retrofit of carbon capture technology once it becomes commercially viable. |
| |
| | • | | Expansion of company owned renewable energy sources and continued use of purchase power agreements and investments that focus on lower or non-emitting generation resources. The State of Nevada mandates that an increasing percentage of the energy SPR sells must come from renewable sources, reaching 20 percent by 2015. With two large-scale solar projects presently under construction in the State, by the end of 2007, Nevada will be number one in the nation for solar watts generated per person and the percentage of solar to total kilowatt hours sold. |
SPR and the Utilities may be affected by future federal or state legislation or regulations mandating a reduction in greenhouse gas emissions. Because of the high level of uncertainty regarding when any legislation or regulations will be adopted in this area or what form they will take, management is unable at this time to evaluate the potential economic impact of any such measures on SPR or the Utilities.
Congress has from time to time considered legislation that would amend the Clean Air Act to target specific emissions from electric utility generating plants. If enacted, this legislation would require reductions in emissions of nitrogen oxides, sulfur dioxide and mercury. There is significant uncertainty at this time as to whether such legislation will be passed by Congress and, if passed, the timing and extent of any required reductions.
Of particular importance to SPR, in 2005 the EPA issued its Clean Air Mercury Rule (CAMR) and Regional Haze Rule. SPR notes that both rules have been the subject of litigation by various parties.
CAMR— The EPA’s CAMR uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal and oil-fired generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. Under the Federal program, states will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. In late 2006, the State of Nevada proposed its own mercury emission reduction rule in keeping with EPA’s proposed model program. The State rule was submitted to EPA for approval in late 2006, and is currently pending approval.
Under the Nevada Clean Air Mercury Rule (NV CAMR), existing coal-fired facilities will be granted allowances for use during Phase I of the compliance period (2010 -2017). New SPR coal-fired units will be required to meet a specified emission limit and procure sufficient mercury emission allowances for compliance. SPR’s preliminary analysis of Phase I of the NV CAMR suggests that several of SPR’s existing units will be eligible to earn extra allowances, which may be applied to cover emissions from new sources as necessary.
Under Phase II of the compliance period (2018 and beyond), is it not certain whether or not SPR will be allotted the required allowances to cover its mercury emissions. The determining factor will be the amount of coal-fired generation added to Nevada in 2018 and beyond. SPR continues to evaluate future potential available allowances as well as evaluation of additional technology to meet the 2018 Phase II cap. New mercury reduction technology is still in its infancy and as such the form of technology or associated costs cannot be determined at this time.
Regional Haze Rules— In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. The EPA requires states to develop implementation plans to comply with regional haze rules by December 2007. States are required to identify the facilities that will have to reduce emissions through installation of emission controls, known as best available retrofit technology (BART), and then set emissions limits for those facilities. The State of Nevada has just begun its BART rule development as the first step toward the December 2007 deadline, and SPR is actively involved in the stakeholder process. At this time, it is not clear which, if any, SPR facilities will require the installation of BART technology or an approved BART alternative. Due to the uncertainties of technology requirements and timing, SPR is not able to estimate the cost impact to its facilities at this time.
25
GENERAL – EMPLOYEES (ALL)
SPR and its subsidiaries had 3,212 employees as of January 30, 2007, of which 1,828 were employed by NPC and 1,266 were employed by SPPC.
NPC’s current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 60% of NPC’s workforce, was renegotiated and ratified in April 2005. The new contract is in effect until February 2008. The three-year contract provided for a 4% general wage increase for bargaining unit employees effective February 2, 2005, with 3.75% increases in 2006 and 2007. In addition, the agreement includes modifications to holiday schedules, health care cost sharing, retirement benefits and other operational productivity improvements.
SPPC’s proposed amendment to its existing contract with the IBEW Local No. 1245, which represents approximately 65% of SPPC’s workforce, was ratified by the IBEW on February 28, 2007. The contract, which is expected to be executed in the near future, will be in effect through December 31, 2009. The three-year contract will provide for an 8% general wage increase for most bargaining unit employees effective March 5th, 2007, with 4% increases in 2008 and 2009. Due to protracted negotiations, bargaining unit employees did not receive a wage increase in 2006 and the negotiated 8% wage increase in 2007 reflects this. Some classifications will receive lump sum payments in lieu of a general wage increase and others will receive equity raises in addition to their general wage increase. Other significant negotiated items include modifications to holiday schedules, health care cost sharing, post retirement benefits, and other operational productivity improvements.
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. Public utilities are required by law to collect from their customers a universal energy charge (UEC) based on consumption. The UEC is designed to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2006, the Utilities collected $107.8 million in franchise or other fees based on gross revenues. They collected $9.8 million in UEC based on consumption. They also paid and recorded as expense $1.0 million of fees based on net profits.
The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates.
ITEM 1A RISK FACTORS
The Utilities plan to make significant capital expenditures to construct new transmission and generating facilities. If we are unable to finance such construction or limit the amount of capital expenditures associated therewith to forecasted levels, our financial condition and results of operation could be adversely affected.
Our long term business objectives include plans to construct new generating and transmission facilities. Such construction will require significant capital expenditures that the Utilities may finance through significant additional borrowings under the Utilities’ respective credit facilities, through additional debt financings in private or public offerings or through debt or equity financings by SPR. We cannot be sure that we will be able to obtain financing for such capital expenditures on favorable terms, or at all. Neither can we be sure that we will be successful in limiting capital expenditures to planned amounts, particularly in the event of escalating costs for materials, labor and environmental compliance. If we cannot obtain favorable financing arrangements for our planned capital expenditures, limit such capital expenditures to forecasted amounts and/or recover amounts spent on construction through future filings with PUCN, our financial condition and results of operation would be adversely affected.
The Utilities’ ability to access the capital markets is dependent on their ability to obtain regulatory approval to do so.
The Utilities will need to continue to support working capital and capital expenditures, and to refinance maturing debt, through external financing. The Utilities must obtain regulatory approval in Nevada in order to borrow money or to issue securities and will therefore be dependent on the PUCN to issue favorable orders in a timely manner to permit them to finance their operations, construction and acquisition costs and to purchase power and fuel necessary to serve their customers. We cannot assure you that the PUCN will issue such orders or that such orders will be issued on a timely basis.
If Federal and/or State requirements are imposed on NPC and SPPC mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions, such requirements could make some electric generating units uneconomical to construct, maintain or operate.
Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Environmental advocacy groups and regulatory agencies in the United States have also been focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature. Future changes in environmental regulations governing emissions reductions could make certain electric generating units uneconomical to construct, maintain or operate. In addition, any legal obligation that would require the Utilities to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.
26
The Utilities are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, or expose us to environmental liabilities.
The Utilities are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. These laws and regulations can result in increased capital, construction, operating, and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and may be enforced by both public officials and private individuals. We cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations.
In addition, either of the Utilities may be required to be a responsible party for environmental clean up at sites identified by environmental agencies or regulatory bodies. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.
Existing environmental regulations regarding air emissions (such as NOx, SO2, mercury emissions or greenhouse-gas emissions), water quality and other toxic pollutants may be revised or new climate change regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs, increased construction costs or additional operating restrictions, could have a material adverse effect on our financial condition and results of operations particularly if those costs are not fully recoverable from our customers and/or if such regulations make currently contemplated construction projects technologically obsolete or economically non-viable.
Furthermore, we may not be able to obtain or maintain all environmental regulatory approvals necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted or subjected to additional costs.
The Utilities may not be able to mitigate fuel and wholesale electricity pricing risks which could result in unanticipated liabilities and cash flow requirements or increased volatility in our earnings.
The Utilities’ business and operations are subject to changes in purchased power prices and fuel costs that may cause increases in the amounts they must pay for power supplies on the wholesale market and the cost of producing power in their generation plants. As evidenced by the western utility crisis that began in 2000, prices for electricity, fuel and natural gas may fluctuate substantially over relatively short periods of time and expose the Utilities to significant commodity price risks. Among the factors that could affect market prices for electricity and fuel are:
| | • | | prevailing market prices for coal, oil, natural gas and other fuels used in generation plants, including associated transportation costs, and supplies of such commodities; |
| |
| | • | | changes in the regulatory framework for the commodities markets that they rely on for purchased power and fuel; |
| |
| | • | | liquidity in the general wholesale electricity market; |
| |
| | • | | the actions of external parties, such as the FERC or independent system operators, that may impose price limitations and other mechanisms to address some of the volatility in the western energy markets; |
| |
| | • | | weather conditions impacting demand for electricity or availability of hydroelectric power or fuel supplies; |
| |
| | • | | union and labor relations; |
| |
| | • | | natural disasters, wars, acts of terrorism, embargoes and other catastrophic events; and |
| |
| | • | | changes in federal and state energy and environmental laws and regulations. |
As a part of the Utilities’ risk management strategy, they focus on executing contracts for power deliveries to the Utilities’ physical points of delivery to mitigate the commodity-related risks listed above. To the extent that open positions exist, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.
Increasing energy commodity prices, particularly with respect to natural gas, have a significant effect on our short-term liquidity. Although the Utilities are entitled to recover their prudently incurred power, natural gas and fuel costs through deferred energy rate case filings with the PUCN, if current commodity prices hold or increase, the Utilities’ deferred energy balances will increase, which will negatively affect our cash flow and liquidity until such costs are recovered from customers.
The Utilities are also subject to credit risk for losses that they incur as a result of non-performance by counterparties of their contractual obligations to deliver fuel, purchased power, natural gas (for resale) or settlement payments. The Utilities often extend credit to counterparties and customers and they are exposed to the risk that they may not be able to collect amounts owed to them. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, the Utilities may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.
27
The Utilities are also subject to liquidity risk resulting from the exposure that their counterparties perceive with respect to the possible non-performance by the Utilities of their physical and financial obligations under their energy, fuel and natural gas contracts. These counterparties may under certain circumstances, pursuant to the Utilities agreements with them, seek assurances of performance from the Utilities in the form of letters of credit, prepayment or cash deposits. In periods of price volatility, the Utilities’ exposure levels can change significantly, which could have a significant negative impact on our liquidity and earnings.
As of February 23, 2007, NPC had approximately $476.3 million available under its $600 million revolving credit facility and SPPC has approximately $331.1 million available under its $350 million revolving credit facility. The combined effects of higher natural gas prices, significant deferred energy balances and ongoing under-recovery of fuel, energy and natural gas costs may have a negative effect on our short-term liquidity.
If NPC and/or SPPC do not receive favorable rulings in the deferred energy applications that they file with the PUCN and they are unable to recover their deferred purchased power, natural gas and fuel costs, they will experience an adverse impact on cash flow and earnings. Any significant disallowance of deferred energy charges in the future could materially adversely affect their cash flow, financial condition and liquidity.
The rates that the Utilities charge their customers and certain aspects of their operations are subject to the regulation of the PUCN, which significantly influences the Utilities’ operating environment and affects their ability to recover costs from their customers. Under Nevada law, purchased power, natural gas and fuel costs in excess of those included in base rates are deferred as an asset on their balance sheets and are not shown as an expense until recovered from their retail customers. The Utilities are required to file deferred energy applications with the PUCN at least once every twelve months so that the PUCN may verify the prudence of the energy costs and allow them to clear their deferred energy accounts. Nevada law also requires the PUCN to act on these cases within a specified time period. Any of these costs determined by the PUCN to have been imprudently incurred cannot be recovered from the Utilities’ customers. Past disallowances in the Utilities’ deferred energy cases have been significant.
In January 2007, NPC filed its annual mandatory deferred energy rate case with the PUCN along with a request to recover costs associated with terminated power contracts. In its deferred filing, NPC seeks to reduce its base tariff energy rate due to expected lower fuel costs and asks for recovery of approximately $75 million in past fuel and purchased power costs, both rate changes to be effective June 1, 2007. The second filing requests recovery of costs associated with the settlement of claims for power contracts executed during the western energy crisis. NPC is seeking approximately $21 million per year for a period of four years, to recover costs relating to the settlement of these claims. While the PUCN has up to 210 days to decide a fuel and purchased power case, NPC has requested that the rates become effective June 1, 2007.
In December 2006, SPPC filed its annual mandatory deferred energy filing with the PUCN along with a request to recover costs associated with terminated power contracts. SPPC’s total deferred energy filing asks for recovery of approximately $18.7 million in past fuel and purchased power costs. In addition, the required deferred filing includes the setting of a new forward-looking rate to match the current estimate of costs of fuel and purchased power as well as the expiration of some rates previously approved by the PUCN. In its terminated power contract filing, SPPC is also seeking approximately $5 million per year for a period of four years, to recover costs relating to the settlement of the claims associated with the terminated power contracts.
As of December 31, 2006, NPC’s and SPPC’s unapproved deferred energy costs were $154.1 million and $28 million, respectively.
Material disallowances of deferred energy costs, gas costs or inadequate base tariff energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause downgrades of SPR’s and the Utilities’ securities by the rating agencies and could make it more difficult to finance operations and construction projects and buy fuel, natural gas and purchased power from third parties.
If NPC and/or SPPC do not receive favorable rulings in their future general rate cases, it will have a significant adverse effect on our financial condition, cash flows and future results of operations.
The Utilities’ revenues and earnings are subject to changes pursuant to regulatory proceedings known as general rate cases, which the Utilities file with the PUCN approximately every two years. In the Utilities’ general rate cases, the PUCN establishes, among other things, their recoverable rate base, their return on common equity, overall rate of return, depreciation rates and their cost of capital.
In November 2006, NPC filed its 2006 general rate case with the PUCN. The filing, if approved, would provide for a $156.4 million increase in its electric rates, for an overall increase of 7.4%. A decision on NPC’s general rate case is expected in the Spring of 2007.
We cannot predict what the PUCN will direct in their orders on the Utilities’ pending or future general rate cases. Inadequate base energy rates would have a significant adverse effect on 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 construction projects and to buy fuel, natural gas and purchased power from third parties.
28
Past regulatory decisions significantly adversely affected our liquidity. Adverse regulatory decisions could cause downgrades of our credit ratings which, in turn, could limit our access to the capital markets and make it difficult for the Utilities to obtain power necessary for their operations.
In March 2002, the PUCN issued a decision in NPC’s deferred energy rate case disallowing $434 million of its request to recover deferred purchased power and fuel costs through rate increases to its customers. Following this decision by the PUCN, both Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) lowered our unsecured debt ratings to below investment grade. As a result of these downgrades, our ability to access the capital markets to raise funds to service our debt obligations and refinance our maturing debt became limited. Since that time, SPR and the Utilities have completed a series of financings that have extended the debt maturities, reduced interest costs, improved their capital structure, increased liquidity and enhanced the credit of SPR and the Utilities. As a result, Moody’s improved the credit ratings of SPR and the Utilities, and S&P changed our credit outlook to “positive” from “negative.” Fitch Ratings Ltd. (“Fitch”) and Dominion Bond Rating Service (“DBRS”) commenced credit coverage, assigning ratings for the two Utilities’ senior secured debt at the minimum level for investment grade. Currently, Moody’s, S&P, and DBRS have our credit ratings on “stable” outlook and Fitch has our credit rating on “positive” outlook. SPR and the Utilities will continue to look for opportunities to improve their financial strength and improve their credit quality. However, any future downgrades would increase our cost of capital and limit our access to the capital markets.
Historically, the Utilities have purchased a significant portion of the power that they sell to their customers from power suppliers. If the Utilities’ and/or their power suppliers’ credit ratings are downgraded, the Utilities may experience difficulty entering into new power supply contracts, and to the extent that they must rely on the spot market, they may experience difficulty obtaining such power from suppliers in the spot market in light of their financial condition, or the financial condition of their power suppliers. In addition, if the Utilities experience unexpected failures or outages in their generation facilities, they may need to purchase a greater portion of the power they provide to their customers. If they do not have sufficient funds or access to liquidity to obtain their power requirements, particularly for NPC at the onset of the summer months, and are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.
If SPR is precluded from receiving dividends from the Utilities, its financial condition and ability to meet its debt service obligations will be materially adversely affected.
SPR is a holding company with no significant operations of its own. Its cash flows are substantially derived from dividends paid to it by the Utilities, which are typically utilized to service SPR’s debt, with the balance, if any, reinvested in SPR’s subsidiaries as contributions to capital. In the future, subject to various factors to be considered by SPR’s Board of Directors, a portion of SPR’s cash flow may be used to resume dividend payments on its common stock, in addition to paying debt service and making capital contributions to SPR’s subsidiaries.
The Utilities are subject to restrictions on their ability to pay dividends to SPR under the terms of certain of their respective financing agreements and a PUCN order. In addition, certain provisions of the Federal Power Act could, depending on the interpretation thereof, limit or prohibit the payment of dividends to SPR.
Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act and that any dividends paid to SPR are for SPR’s debt service obligations, under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is an amount less than 50% of such Utilities’ consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of debt securities to the end of the most recently ended fiscal quarter. If they do not meet these conditions, the Utilities can still pay SPR’s reasonable fees and expenses, provided that each such Utility has a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters. Due to the cumulative calculation of this restriction, NPC’s Series G Notes and SPPC’s Series H Notes are effectively the most restrictive dividend limitations. In addition, under the most restrictive of their dividend restrictions, each of the Utilities has a carve-out that permits them to pay up to $25 million to SPR from the date of issuance of the applicable debt securities, regardless of whether the other conditions to paying dividends have been met. Although each Utility currently meets the conditions described above, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. The dividend restriction in the PUCN order may be more restrictive than the Utilities’ individual dividend restrictions because the PUCN dividend restriction currently limits the amount of dividends paid to SPR collectively by the Utilities to SPR’s actual cash debt service payments, which amount may be less than the aggregate amount of the Utilities’ individual dividend restrictions. In 2006, SPR received approximately $53.7 million in dividends from the Utilities to meet its debt service obligations.
SPR’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC. SPR and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.
Because SPR is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing indebtedness and other future liabilities, including claims by the Utilities’ trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. SPR conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to meet its obligations under its indebtedness will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to SPR. As of January 31, 2007, the Utilities had approximately $3.5
29
billion of debt outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s December 31, 2006 financial statements, assuming an interest rate of 7%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $2.1 billion of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’s indebtedness. In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.
Whether SPR can procure sufficient renewable energy sources in each compliance year to comply with the Portfolio Standard for Renewable Energy.
Currently, the State of Nevada requires compliance with its Portfolio Standard for Renewable Energy, which mandates that a share of the energy delivered to Nevada retail customers come from renewable energy resources. This energy is to be provided via direct generation, saved from portfolio energy systems or realized from implementation of efficiency measures. The Utilities continue to take affirmative actions to fulfill the Portfolio Standard requirements on their system. However, the Utilities’ success in meeting the standard remains dependent on creation of new renewable energy projects, both owned or via output which is purchased from third parties, as well as maintenance of an ongoing positive climate for renewable energy development across Nevada.
Our operating results will likely fluctuate on a seasonal and quarterly basis.
Electric power generation is generally a seasonal business. In many parts of the country, including our service areas, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our operating results in the future will likely fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions in our service areas are milder. Unusually mild weather in the future could diminish our results of operations and harm our financial condition.
Changes in consumer preferences, war and the threat of terrorism or epidemics may harm our future growth and operating results.
The growth of our business depends in part on continued customer growth and tourism demand in the Las Vegas portion of our service area. Changes in consumer preferences or discretionary consumer spending in the Las Vegas portion of our service area could harm our business. We cannot predict the extent to which future terrorist and war activities, or epidemics, in the United States and elsewhere may affect us, directly or indirectly. An extended period of reduced discretionary spending and/or disruptions or declines in airline travel and business conventions could significantly harm the businesses in and the continued growth of the Las Vegas portion of our service area, which could harm our business and results of operations. In addition, instability in the financial markets as a result of war, terrorism or epidemics may affect our ability to raise capital.
A continued military presence in Iraq or any other military operations may affect our operations in unpredictable ways, such as increased security measures and disruptions of fuel supplies and markets, particularly oil. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our business in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that our infrastructure facilities (which includes our pipelines, production facilities, and transmission and distribution facilities) could be direct targets or indirect casualties of an act of terror. War and prolonged military operations may have an adverse effect on the economy in general, which could adversely affect our business, operations and financial condition.
ITEM 1B. UNRESOLVED STAFF COMMENTS
SPR, NPC and SPPC have received no written comments regarding their periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of their 2006 fiscal year and that remain unresolved.
ITEM 2. PROPERTIES
Substantially 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, as amended and supplemented.
Substantially all of SPPC’s property in California and 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, as amended and supplemented.
30
The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units were installed.
| | | | | | | | | | | | | | | | | | | |
| | | | | | | Number of | | Winter MW | | Summer MW | | Commercial Operation |
| Plant Name | | Type | | Fuel | | Units | | Capacity | | Capacity | | Year |
| Clark (1) | | Combined Cycle | | Gas/Oil | | | 6 | | | | 506 | | | | 430 | | | 1979, 1979, 1980, 1982, 1993, 1994 |
| | | Gas | | Gas/Oil | | | 1 | | | | 63 | | | | 54 | | | 1973 |
| | | | | | | | | | | | | | | | | | | |
| Sunrise | | Steam | | Gas | | | 1 | | | | 82 | | | | 80 | | | 1964 |
| | | Gas | | Gas/Oil | | | 1 | | | | 81 | | | | 70 | | | 1974 |
| | | | | | | | | | | | | | | | | | | |
| Harry Allen | | Gas | | Gas/Oil | | | 2 | | | | 168 | | | | 144 | | | 1995, 2006 |
| | | | | | | | | | | | | | | | | | | |
| Chuck Lenzie (2) | | Combined Cycle | | Gas | | | 6 | | | | 1,220 | | | | 1,102 | | | 2006 |
| | | | | | | | | | | | | | | | | | | |
| Silverhawk (3) | | Combined Cycle | | Gas | | | 3 | | | | 449 | | | | 395 | | | 2004 |
| | | | | | | | | | | | | | | | | | | |
| Mohave (4)(5) | | Steam | | Coal | | | 0 | | | | 0 | | | | 0 | | | 1971, 1971 |
| | | | | | | | | | | | | | | | | | | |
| Navajo (6) | | Steam | | Coal | | | 3 | | | | 255 | | | | 255 | | | 1974, 1975, 1976 |
| | | | | | | | | | | | | | | | | | | |
| Reid Gardner (7) | | Steam | | Coal | | | 4 | | | | 324 | | | | 324 | | | 1965, 1968, 1976, 1983 |
| | | | | | | | | | | | | | | | | | | |
| Total | | | | | | | 27 | | | | 3,148 | | | | 2,854 | | | |
| | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | The two combined cycles at Clark each consist of two gas turbines, two Heat Recovery Steam Generators (HRSG), and one steam turbine. In 1993 and 1994, the original four gas turbines (1979-1982) were combined with four new HRSGs and two new steam turbines to form the combined cycles. |
| |
| (2) | | The two combined cycles at Lenzie each consist of two gas turbines, two HRSGs and one steam turbine. |
| |
| (3) | | The acquisition of a 75% ownership interest in the 599 MW Silverhawk power station from Pinnacle West was consummated in 2006. Southern Nevada Water Authority continues to hold a 25% ownership interest in the plant. The combined cycle plant consists of two gas turbines, two HRSGs and one steam turbine. |
| |
| (4) | | Per a 1999 Consent Decree, Mohave ceased operation on December 31, 2005. The PUCN approved establishing regulatory accounts related to the shutdown. See Note 5, Jointly Owned Facilities and Note 13, Commitments and Contingencies, Regulatory Contingencies, of the Notes to Financial Statements for further discussion. |
| |
| (5) | | Prior to the shut down, the total summer net capacity of the Mohave Generating Station was 1,580 MW. Southern California Edison is the operating agent and NPC has a 14% interest in the Station. |
| |
| (6) | | NPC has an 11.3% interest in the Navajo Generating Station. The total capacity of the Station is 2,250 MW. Salt River Project is the operator (21.7% interest). There are four other partners: U.S. Bureau of Reclamation (24.3% interest), Los Angeles Dept. of Water & Power (21.2% interest), Arizona Public Service Co (14% interest), and Tucson Electric Power (7.5% interest). |
| |
| (7) | | Reid Gardner Unit No. 4 is co-owned by the California Department of Water Resources (CDWR) (67.8%) and NPC (32.2%); NPC is the operating agent. NPC is entitled to 25 MW of base load capacity and 235 MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300 hours/month, and 8 hours/day. There was a 15 MW upgrade to the Unit in 1990, which is now under CDWR’s control; the total summer net capacity of the Unit, subject to heat input limitation, is 257 MW. Reid Gardner Units 1, 2, and 3, subject to heat input limitations, are 100 MW each; the total net capacity of the Station is 557 MW. |
31
The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units became operational.
| | | | | | | | | | | | | | | | | | | |
| | | | | | | Number of | | Winter MW | | Summer MW | | Commercial Operation |
| Plant Name | | Type | | Fuel | | Units | | Capacity | | Capacity | | Year |
| Ft. Churchill | | Steam | | Gas/Oil | | | 2 | | | | 226 | | | | 226 | | | 1968, 1971 |
| | | | | | | | | | | | | | | | | | | |
| Tracy | | Steam | | Gas/Oil | | | 3 | | | | 244 | | | | 244 | | | 1963, 1965, 1974 |
| | | | | | | | | | | | | | | | | | | |
| Tracy 4&5 (1) | | Combined Cycle | | Gas | | | 2 | | | | 108 | | | | 104 | | | 1996, 1996 |
| | | | | | | | | | | | | | | | | | | |
| Clark Mtn. CT’s | | Gas | | Gas/Oil | | | 2 | | | | 144 | | | | 132 | | | 1994, 1994 |
| | | | | | | | | | | | | | | | | | | |
| Valmy (2) | | Steam | | Coal | | | 2 | | | | 261 | | | | 261 | | | 1981, 1985 |
| | | | | | | | | | | | | | | | | | | |
| Other (3) | | Gas, Diesels | | Propane, Oil | | | 13 | | | | 60 | | | | 56 | | | 1960-1970 |
| | | | | | | | | | | | | | | | | | | |
| Total | | | | | | | 24 | | | | 1,043 | | | | 1,023 | | | |
| | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Tracy 4&5 were part of the Pinõn Pine Integrated Coal Gasification Combined Cycle power plant located at Tracy Station. This project was part of the Department of Energy’s Clean Coal Demonstration Program. Although the coal gasification portion of the facility has never proven operational, the combined cycle unit has been operating on natural gas since 1996. The combined cycle consists of one combustion turbine, one HRSG, and one steam turbine. In 2003, SPPC installed duct burners, which added 15 MW of capacity. |
| |
| (2) | | Valmy is co-owned by Idaho Power Company (50%) and SPPC (50%); SPPC is the operator. The Plant has a total net capacity of 522 MW. |
| |
| (3) | | There are 3 combustion turbines and 10 diesel units included in the “Other” category. |
ITEM 3. LEGAL PROCEEDINGS
Sierra Pacific Resources and Nevada Power Company
Merrill Lynch/Allegheny Lawsuit
In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc. and Allegheny Energy Supply Co., LLC (collectively, Allegheny) in the United States District Court, District of Nevada, for compensatory and punitive damages of $850 million for causing the Public Utilities Commission of Nevada to disallow the approximate $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed in Note 13, Commitments and Contingencies of the Notes to Financial Statements). The PUCN held that NPC acted imprudently when it refused to enter into an electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and wrongful conduct caused the PUCN disallowance. Merrill Lynch filed motions to dismiss in May 2003 and June 2003. Thereafter, the case was stayed pending resolution of NPC’s appeal of the 2001 deferred energy case pending before the Nevada Supreme Court, which was decided in August 2006 and discussed further in Note 13, Commitments and Contingencies of the Notes to Financial Statements. The Nevada Supreme Court has since rendered its decision in the appeal.The Nevada District Court has yet to rule on the motions to dismiss. In October 2006, the District Court approved a stipulation continuing a stay of the proceeding pending final resolution of the PUCN remand proceedings in the 2001 deferred energy case.
Lawsuit Against Natural Gas Providers
In April 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. In July 2003, SPR and NPC filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. The defendants filed motions to dismiss, which were granted by the District Court. SPR and NPC appealed the decision to the Ninth Circuit Court of Appeals. Briefing has been completed. Oral argument was heard on February 13, 2007. Management cannot predict the timing or outcome of a decision on this matter.
32
Nevada Power Company and Sierra Pacific Power Company
Western United States Energy Crisis Proceedings before the FERC
FERC 206 complaints
In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.
On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. On July 28, 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June 26, 2003 decision. The Utilities appealed this decision to the Ninth Circuit. Oral argument was held on December 8, 2004. On December 19, 2006, a three judge panel of the Ninth Circuit overturned the FERC decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. The Company expects one or more of the losing parties to file a petition for certiorari seeking review by the U.S. Supreme Court. The parties must file such a petition within 90 days.
The Utilities have negotiated settlements with Duke Energy Trading and Marketing, Reliant Energy Services, Inc., Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as El Paso Marketing L.P.; and Enron, but have been unable to reach agreement in bilateral settlement discussions with other respondents. In accordance with the Enron Settlement Agreement, the Utilities withdrew from further participation in the FERC 206 Complaints (including any associated appeals) as against Enron.
Sierra Pacific Power Company
Piñon Pine
In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC’s participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable. In its order in May 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 General Rate Case and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). In March 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. In June 2006, the District Court granted PUCN’s motion to stay the Order. In July 2006, the Supreme Court issued an order questioning the finality of the District Court’s decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this matter. The BCP and PUCN responded in early August 2006. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and in January 2007, the matter was remitted back to the District Court, which, consistent with its January 2006 order, remanded the matter back to the PUCN for further review. A procedural schedule for this review has not yet been established.
Other Legal Matters
SPR and it 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.
Environmental Matters
Nevada Power Company
Reid Gardner Station
In August 1999, the Nevada Department of Environmental Protection (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 following 10 years.
33
This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Any future ponds will be double-lined with inter-liner leak detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005.
Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.
In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and in December 2004, issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. In July 2005, NDEP issued new NOAVs. In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. In July, 2005 NPC received a letter from the Environmental Protection Agency (EPA) requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request. In June, 2006, the EPA issued a Finding and Notice of Violation (NOV).
NPC has progressed to the final draft stage of dialogue and settlement discussions with NDEP, EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that may be required to achieve a settlement of the alleged violations. Management has booked an estimated minimum liability with respect to these matters. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen.
Clark Station
In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the DAQEM 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. In October 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act. NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations. Monetary penalties are not expected to be material and certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006 IRP filing.
NEICO
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 has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.
Sierra Pacific Power Company
PCB Treatment, Inc.
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
34
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 completed site investigations and along with the EPA determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The cleanup has now been completed on both buildings and is pending inspection and sign off by EPA. The cleanup for the two buildings came in under budget, as such, SPPC does not expect any further obligations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS
The following are current executive officers of SPR, NPC and SPPC indicated and their ages as of December 31, 2006. 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, 62, Chairman and Chief Executive Officer, SPR and Director and Chief Executive Officer of NPC and SPPC.
Mr. Higgins was elected to his current position on February 15, 2007. Previously, he was Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC and SPPC from August 2000 to February 15, 2007. Mr. Higgins served as Chairman, President and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 2000. He is also a director of AEGIS Insurance Services, the American Gas Association, Edison Electric Institute, and several not-for-profit organizations. He is a trustee of Sierra Nevada College.
Michael W. Yackira, 55, President and Chief Operating Officer, SPR
Mr. Yackira was elected to his current position on February 15, 2007. He was previously Corporate Executive Vice President and Chief Financial Officer from October 2004 to February 15, 2007. From December 2003 to October 2004 he held the position of Executive Vice President and CFO of SPR, as well as both NPC and SPPC. Mr. Yackira was previously Executive Vice President, Strategy and Policy, from January to December 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. Mr. Yackira is a certified public accountant.
Donald L. “Pat” Shalmy, 66, Corporate Senior Vice President, Policy & External Affairs, SPR; President, NPC
Mr. Shalmy was elected to his present position in November 2004. From July 2002 to October 2004 he held the position of President, NPC. 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. Prior to that, Mr. Shalmy was County Manager of Clark County for 121/2 years and President of the Las Vegas Chamber of Commerce for four years. He is also a director of the Las Vegas Monorail Company.
Jeffrey L. Ceccarelli, 52, Corporate Senior Vice President, Service Delivery & Operations; President, SPPC
Mr. Ceccarelli was elected to his present position in October 2004. From June 2000 to October 2004 he held the position of President, SPPC. He previously held the position of Vice President, Distribution Services, New Business, in July 1999 for SPPC and NPC. A civil engineer, Mr. Ceccarelli has been with SPPC since 1972.
Paul L. Kaleta, 51, Corporate Senior Vice President, General Counsel and Corporate Secretary, SPR
Mr. Kaleta was elected to his present position in February 2006, and holds the same position at NPC and SPPC. Previously he was General Counsel for Koch Industries, Inc. and various Koch subsidiaries from 1998 to 2005. Prior to that, he was Vice President and General Counsel of Niagara Mohawk Power Company for 8 years and, before that, in the private practice of law as an associate with Skadden, Arps, Slate, Meagher & Flom and as an associate and then equity member with Swidler Berlin, Chtd. (now Bingham McCutchen), both in Washington, D.C., for a total of 9 years.
Roberto R. Denis, 57, Corporate Senior Vice President, Energy Supply, SPR, NPC and SPPC
Mr. Denis was elected to his present position in October 2004. From August 2003 to October 2004 he held the position of Vice President, Energy Supply, for NPC and SPPC. From 2001 to 2003, he held the position of Vice President, Market & Regulatory Affairs, at FPL Energy, LLC. From 1999 to 2001, he held the position of Vice President of Market Services.
35
Stephen R. Wood, 63, Corporate Senior Vice President, Administration, SPR
Mr. Wood was elected to his present position in July 2004 and holds the same position at NPC and SPPC. He was previously President, Centaur Energy Development LLC, from 2000 to 2004. From 1997 to 2000 he served as President of Louisville Gas and Electric Company and President, Distribution Services, LG&E Energy Corp. concurrently. He was Executive Vice President and Chief Administrative Officer, LG&E Energy Corp. from 1994 to 1997. He is also a director of Martin Engineering, Inc.
William D. Rogers, 46, Corporate Senior Vice President, Chief Financial Officer and Treasurer, SPR
Mr. Rogers was elected to his current position on February 15, 2007. He was previously Vice President, Finance and Risk and Corporate Treasurer from November 14, 2006 to February 15, 2007. Prior to that, he was Corporate Treasurer from June 8, 2005 to November 14, 2006. Before joining SPR, he served as managing director of debt capital markets for Merrill Lynch & Co. in New York from 2000 to 2005. Prior to that, he served as managing director of debt capital markets with JP Morgan Chase in New York from 1992 until 2000.
John E. Brown, 56, Controller, SPR
Mr. Brown was elected to his current position in May 2001, and holds the same position at SPPC and NPC. Previously, he held the position of Director, Corporate and Tax Accounting, and Director, Internal Audit. Mr. Brown has been with SPR since 1981.
Mary O. Simmons, 51, Vice President, External Affairs, SPPC
Ms. Simmons was elected to her current position in November 2004. From May 2001 to October 2004, she held the position of Vice President, Rates and Regulatory Affairs, for NPC and SPPC. Previously she held the position of Controller for SPR and SPPC since 1997 and held the same position with NPC beginning in 1999. Ms. Simmons is a certified public accountant and has been with SPR since 1985.
36
PART II
| | |
| ITEM 5. | | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (SPR) |
SPR’s Common Stock is traded on the New York Stock Exchange (symbol SRP). The high and low sale prices of the Common Stock as reported by NYSE net composite price history for 2006 and 2005 are as follows:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 |
| | | High | | Low | | High | | Low |
| First Quarter | | $ | 14.60 | | | $ | 12.68 | | | $ | 11.30 | | | $ | 9.00 | |
| | | | | | | | | | | | | | | | | |
| Second Quarter | | | 14.35 | | | | 12.68 | | | | 13.05 | | | | 10.11 | |
| | | | | | | | | | | | | | | | | |
| Third Quarter | | | 14.91 | | | | 13.30 | | | | 15.36 | | | | 12.05 | |
| | | | | | | | | | | | | | | | | |
| Fourth Quarter | | | 17.50 | | | | 14.29 | | | | 15.20 | | | | 12.34 | |
Number of Security Holders:
| | | | | |
| Title of Class | | | | Number of Record Holders |
| Common Stock: | | $1.00 Par Value | | As of February 23, 2007:17,515 |
The Board last declared a 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. 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, as well as dividend restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014, 7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017. 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 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 Note 8, Debt Covenant and Other Restrictions of the Notes to Financial Statements, for a description of the restrictions on NPC’s and SPPC’s ability to pay dividends to SPR and on SPR’s ability to pay dividends on its common stock.
For information on the equity compensation plans, see Item 12.
37
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
| | | | | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | (dollars in thousands; except per share amounts) | |
| | | 2006(1) | | | 2005(2) | | | 2004(3) | | | 2003(4) | | | 2002(5) | |
| Operating Revenues | | $ | 3,355,950 | | | $ | 3,030,242 | | | $ | 2,824,796 | | | $ | 2,787,543 | | | $ | 2,984,604 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income (Loss) | | $ | 488,797 | | | $ | 358,678 | | | $ | 333,858 | | | $ | 260,314 | | | $ | (28,939 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations | | $ | 279,792 | | | $ | 86,137 | | | $ | 30,842 | | | $ | (117,286 | ) | | $ | (297,733 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) from Continuing Operations Per Average Common Share — Basic and Diluted | | $ | 1.34 | | | $ | 0.46 | | | $ | 0.17 | | | $ | (1.01 | ) | | $ | (2.92 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 8,832,076 | | | $ | 7,870,546 | | | $ | 7,528,467 | | | $ | 7,063,758 | | | $ | 7,110,639 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-Term Debt | | $ | 4,001,542 | | | $ | 3,817,122 | | | $ | 4,081,281 | | | $ | 3,579,674 | | | $ | 3,194,966 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Dividends Declared Per Common Share | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.20 | |
| | | | | | | | | | | | | | | | |
| | |
| (1) | | Income from continuing operations, for the year ended December 31, 2006, includes reinstatement of deferred energy of approximately $180 million and a $62.9 million gain on the sale of Tuscarora Gas Pipeline Company’s partnership interest in Tuscarora Gas Transmission Company. |
| |
| (2) | | Income from continuing operations, for the year ended December 31, 2005, includes a charge of $54 million for the inducement of debt conversion and the reversal of $20.9 million in interest charges as a result of settlements with terminated suppliers. |
| |
| (3) | | Income from continuing operations, for the year ended December 31, 2004, includes the reversal of $39.8 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment and the write-off of $47.1 million in disallowed plant costs at SPPC. |
| |
| (4) | | Loss from continuing operations, for the year ended December 31, 2003, was negatively affected by an unrealized net loss of $46.1 million on the derivative instrument associated with the issuance of SPR’s $300 million Convertible Notes, $91 million write-off of deferred energy costs by NPC and SPPC and approximately $52 million of interest charges related to the Enron litigation. |
| |
| (5) | | Loss from continuing operations and total assets, for the year ended December 31, 2002, was severely affected by the write-off of deferred energy costs and related carrying charges of $523 million as a result of the PUCN decision in NPC’s and SPPC’s deferred energy cases disallowing $434 million and $53 million, respectively, of deferred purchased fuel and power costs. |
NEVADA POWER
| | | | | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | (dollars in thousands) | |
| | | 2006(1) | | | 2005(2) | | | 2004(3) | | | 2003(4) | | | 2002(5) | |
| Operating Revenues | | $ | 2,124,081 | | | $ | 1,883,267 | | | $ | 1,784,092 | | | $ | 1,756,146 | | | $ | 1,901,034 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income (Loss) | | $ | 351,272 | | | $ | 228,827 | | | $ | 216,490 | | | $ | 183,733 | | | $ | (104,003 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 224,540 | | | $ | 132,734 | | | $ | 104,312 | | | $ | 19,277 | | | $ | (235,070 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 5,987,515 | | | $ | 5,173,921 | | | $ | 4,883,540 | | | $ | 4,210,759 | | | $ | 4,166,988 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-Term Debt | | $ | 2,380,139 | | | $ | 2,214,063 | | | $ | 2,275,690 | | | $ | 1,899,709 | | | $ | 1,683,310 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Dividends Declared — Common Stock | | $ | 48,917 | | | $ | 35,258 | | | $ | 45,373 | | | $ | — | | | $ | 10,000 | |
| | | | | | | | | | | | | | | | |
| | |
| (1) | | Income from continuing operations, for the year ended December 31, 2006, includes reinstatement of deferred energy of approximately $180 million. |
38
| | |
| (2) | | For the year ended 2005, Income from Continuing Operations included the reversal of $17.7 million in interest charges as a result of settlements with terminated suppliers. |
| |
| (3) | | Net Income for the year ended December 31, 2004 included the reversal of $27.5 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment. |
| |
| (4) | | Net Income for the year ended December 31, 2003 included a $46 million write-off of deferred energy costs and $36 million of interest charges related to the Enron litigation. |
| |
| (5) | | Net Loss and Total Assets for the year ended December 31, 2002 was severely affected by the write-off of $465 million of deferred purchased fuel and power costs and related carrying charges. |
SIERRA PACIFIC POWER
| | | | | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | (dollars in thousands) | |
| | | 2006 | | | 2005(1) | | | 2004(2) | | | 2003(3) | | | 2002(4) | |
| Operating Revenues | | $ | 1,230,230 | | | $ | 1,145,697 | | | $ | 1,035,660 | | | $ | 1,029,866 | | | $ | 1,081,034 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 120,017 | | | $ | 116,304 | | | $ | 111,245 | | | $ | 68,566 | | | $ | 55,292 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 57,709 | | | $ | 52,074 | | | $ | 18,577 | | | $ | (23,275 | ) | | $ | (13,968 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 2,807,837 | | | $ | 2,546,301 | | | $ | 2,524,320 | | | $ | 2,362,469 | | | $ | 2,457,516 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Preferred Stock | | $ | — | | | $ | 50,000 | | | $ | 50,000 | | | $ | 50,000 | | | $ | 50,000 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Long-Term Debt | | $ | 1,070,858 | | | $ | 941,804 | | | $ | 994,309 | | | $ | 912,800 | | | $ | 914,788 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Dividends Declared — Common Stock | | $ | 24,619 | | | $ | 23,933 | | | $ | — | | | $ | 18,530 | | | $ | 44,900 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Dividends Declared — Preferred Stock | | $ | 975 | | | $ | 3,900 | | | $ | 3,900 | | | $ | 3,900 | | | $ | 3,900 | |
| | | | | | | | | | | | | | | | |
| | |
| (1) | | Income from Continuing Operations, for the year ended December 31, 2005, includes the reversal in the fourth quarter of $3.2 million in interest expense related to settlement with terminated suppliers. |
| |
| (2) | | Net Income from Continuing Operations, for the year ended December 31, 2004, was affected by the write-off of $47.1 million in disallowed plant costs and the reversal of interest expense of $12.3 million due to the decision on the appeal of the Enron Bankruptcy judgment and a reduction to income tax expense of $3.3 million as a result of a flow-through adjustment for pension funding. |
| |
| (3) | | Loss from Continuing Operations, for the year ended December 31, 2003, was affected by the write off of $45 million in June 2003 of disallowed deferred energy costs and interest charges of $16 million related to the Enron litigation. |
| |
| (4) | | Loss from Continuing Operations, for the year ended December 31, 2002, was severely affected by the write-off of $58 million of deferred purchased fuel and power costs and related carrying charges. |
39
| | |
| ITEM 7. | | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Forward-Looking Statements
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 or untimely rulings in rate cases filed or to be filed by NPC and SPPC (collectively referred to as the Utilities) with the Public Utility 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 costs recorded by SPPC for its gas distribution business; |
| |
| | (2) | | the ability and terms upon which SPR, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of unfavorable rulings by the PUCN, untimely regulatory approval for such financings, and/or a downgrade of the current debt ratings of SPR, NPC, or SPPC; |
| |
| | (3) | | whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), sharp increases in the prices for fuel and/or power or a ratings downgrade; |
| |
| | (4) | | changes in environmental laws or regulations, including the imposition of significant new limits on emissions from electric generating facilities, such as requirements to reduce carbon dioxide (CO2) emissions, other greenhouse gases and/or other pollutants in response to climate change legislation; |
| |
| | (5) | | 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; |
| |
| | (6) | | changes in the rate of industrial, commercial, and residential growth in the service territories of the Utilities; |
| |
| | (7) | | the effect that any construction risks may have on our business, such as the risk of delays in permitting, changes in environmental laws, securing adequate skilled labor, cost and availability of materials and equipment, equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage; |
| |
| | (8) | | whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard; |
| |
| | (9) | | whether NPC will be successful in obtaining PUCN approval to recover the outstanding balance of its other regulatory assets and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case; |
| |
| | (10) | | whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements, their regulatory order from the PUCN, and limitations imposed by the Federal Power Act; |
| |
| | (11) | | unseasonable weather and other natural phenomena, which, in addition to affecting the Utilities’ customers’ demand for power, can have a potentially serious impact 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; |
| |
| | (12) | | the effect that any future terrorist attacks, wars, threats of war, or epidemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the economy in general; |
| |
| | (13) | | the final outcome of the proceedings to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate Case, which disallowed the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project; |
40
| | (14) | | the timing of the PUCN’s decision regarding the time period NPC is to recover the approximate $180 million of deferred energy that were disallowed in 2002 and were reinstated by the Nevada Supreme Court in July 2006; |
| |
| | (15) | | the timing and final outcome of the PUCN’s decision regarding the Utilities’ recovery of deferred energy costs associated with claims for terminated supplier contracts; |
| |
| | (16) | | employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages; |
| |
| | (17) | | changes in tax or accounting matters or other laws and regulations to which SPR or the Utilities are subject; |
| |
| | (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 or power demands of the Utilities’ 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) | | unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs; |
| |
| | (21) | | future economic conditions, including inflation rates and monetary policy; and |
| |
| | (22) | | financial market conditions, including changes in availability of capital or interest rate fluctuations. |
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.
41
EXECUTIVE OVERVIEW
Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of Sierra Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR and the Utilities collectively), and includes the following:
| | • | | Critical Accounting Policies and Estimates |
| | • | | For each of SPR, NPC and SPPC: |
| | • | | Results of Operations |
| |
| | • | | Analysis of Cash Flows |
| |
| | • | | Liquidity and Capital Resources |
| |
| | • | | Energy Supply (Utilities) |
| |
| | • | | Regulatory Proceedings (Utilities) |
SPR’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the distribution, transmission, generation and sale of electricity and, in the case of SPPC, sale of natural gas. Other segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of SPR and account for substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (SPR, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.
The Utilities are regulated by the PUCN and, for the California service territory of SPPC, the California Public Utilities Commission (CPUC), with respect to rates, standards of service, setting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. Under federal law, wholesale rates charged by the Utilities 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.
The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts of seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and services. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, with a slightly higher peak demand in the winter.
Overview of Major Factors Affecting Results of Operations
During 2006, SPR’s net income applicable to common stock was $277.5 million compared to $82.2 million in 2005. The change in earnings was primarily due to the following items (after income taxes):
| | • | | the July 2006, Nevada Supreme Court ruling which allows NPC to recover approximately $180 million ($117 million, after tax) of the previously disallowed deferred energy costs, for further discussion of the legal proceeding, see Note 13, Commitments and Contingencies of the Notes to Financial Statements; |
| |
| | • | | the $40.9 million gain on sale of the partnership interest in Tuscarora Gas Transmission Company (TGTC) held by Tuscarora Gas Pipeline Company’s (TGPC), a wholly owned subsidiary of SPR; |
| |
| | • | | improved operating income (excluding the approximate $180 million reinstatement); |
| |
| | • | | other income of $21.7 million for the carrying charge on Lenzie; |
| |
| | • | | early tender fees of $6.9 million for the extinguishment of $85 million of SPR’s 8.625% Senior Notes and $25 million of SPR’s 7.803% Senior Notes; and |
| |
| | • | | a charge recorded in 2005 for $35.1 million in early debt conversion fees associated with SPR’s convertible notes. |
42
During 2005, SPR’s net income applicable to common stock was $82.2 million compared to $28.6 million in 2004. The change in earnings was primarily due to the following items (after income taxes):
| | • | | increases in operating income primarily resulting from general rate cases decided in 2004 as well as continued customer growth; |
| |
| | • | | increases in Allowance for Other Funds used During Construction and Allowance for Borrowed Funds used During Construction, for a total of approximately $29.3 million, primarily due to the construction of the Chuck Lenzie Generating Station; |
| |
| | • | | lower interest expenses due to refinancing activities; |
| |
| | • | | reversal of interest for energy suppliers on settled disputes of approximately $13.6 million. |
Partially offsetting these increases in net income applicable to common stock were the following items (after income taxes):
| | • | | early conversion fees of the Convertible Notes of approximately $35.1 million after taxes and unamortized debt issuance costs and legal fees associated with the various financing transactions of approximately $6.3 million after taxes; |
| |
| | • | | legal fees of approximately $7.4 million. |
Overview of Key Business Issues
During 2006, SPR continued to focus on a “back to the basics” strategy that emphasized the Utilities’ core business. SPR’s and the Utilities’ strategies were aimed at owning more generating facilities, thereby reducing dependence on purchased power, while at the same time diversifying fuel mix for the Utilities’ growing service area. Looking ahead in 2007, SPR and the Utilities will continue to concentrate on the “back to the basics” strategy. The Utilities will continue to be subject to the purchased power and natural gas markets that have been volatile in recent years, in order to meet their obligations to serve their customers. Furthermore, with significant amounts of construction costs in the Utilities’ future, SPR and the Utilities will need to raise substantial amounts of capital to fund expenditures. As a result, reducing the cost of capital by attaining investment grade ratings for the Utilities’ secured debt has been and continues to be a significant business focus for 2007.
Summarized below are significant business issues in 2006 and the challenges ahead in 2007. It is not intended to be an exhaustive discussion, nor to suggest that other issues may not arise during 2007 or thereafter. Details relating to the discussion below can be found in the Notes to the Financial Statements and elsewhere within this Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Generation Strategy
In 2003, NPC and SPPC embarked on a strategy to build or acquire electric power plants in order to reduce their exposure to the energy markets, in an effort to reduce prices and volatility for its customers, and to provide an opportunity for increased earnings.
Accomplishments towards this goal in 2006 included:
| | • | | The completion of the Lenzie generating station, a nominally rated 1,200 MW natural gas-fired high efficiency combined cycle power plant acquired from Duke Energy (“Lenzie”). |
| |
| | • | | In January 2006, NPC completed the $208 million purchase of a 75 percent ownership interest in the Silverhawk Generating Facility (“Silverhawk”) from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation, a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC. Silverhawk is a 560-megawatt, natural gas-fueled high efficiency combined-cycle electric generating facility located 20 miles northeast of Las Vegas. |
| |
| | • | | The completion of an 80 MW combustion turbine at NPC’s Harry Allen site. |
With the completion of Lenzie, and the additional unit at NPC’s Harry Allen site, plus the acquisition of Silverhawk, NPC more than doubled its owned capacity since the end of 2005. As a result, NPC is less dependent upon the wholesale power markets for meeting the energy needs of its customers and produced approximately 54.3% of its energy needs in 2006 from owned generation, up from about 39% last year.
In addition, the PUCN granted NPC’s request that Lenzie be designated a critical facility and allowed a 2% enhancement above NPC’s authorized Return on Equity (ROE) to be applied to the rate base associated with the Lenzie construction costs expended after acquisition. The order allows for up to an additional 1%, or a total of 3% enhanced ROE, if the two Lenzie generator units were brought on line on or before dates specified in the order. In January 2006, NPC declared Block 1 of Lenzie commercially operable and in April 2006 declared Block 2 commercially operable, both ahead of the dates specified by the PUCN to qualify for the additional enhancement.
43
In 2006, SPPC began construction of a 514 MW gas fired high efficiency combined cycle generator at the Tracy Plant. SPPC anticipates an in-service date of June 2008. The PUCN also ordered that SPPC be allowed to include construction work in progress balances in the rate base of any interim general rate cases, prior to the in-service date, and granted a 1.5% enhanced ROE for the estimated $421 million investment. The unit will provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada.
Looking ahead
In November 2006, the PUCN approved NPC’s 2006 Integrated Resource Plan (“IRP”) and SPPC’s thirteenth amendment to its 2004 IRP. The Utilities’ IRPs focus on conventional generation, renewable energy, conservation, and transmission projects to meet Nevada’s growing electricity needs while diversifying the fuel mix of the Utilities’ generation portfolios. Included in the PUCN’s approval is Phase 1 of the construction of the Ely Energy Center, a major project to be located near Ely, Nevada consisting of two 750-megawatt coal-fired generation units. In addition, the PUCN approved the development and construction of a 250-mile 500kV transmission line that will deliver electricity from the Ely Energy Center as well as link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state. The PUCN approved spending up to $300 million for development activities associated with the Ely Energy Center; however, they placed a $155 million spending limit until the appropriate air permits are obtained. The PUCN established the project as a “critical facility,” thereby allowing it to qualify for incentives that will be determined in a later filing. Additionally, the PUCN required NPC and SPPC to file amendments to their IRPs in early 2008 once elements of the plan, including final costs, can be more accurately estimated. The current estimate for the Ely Energy Center and the 500kV transmission line is approximately $3.8 billion.
The PUCN also approved for NPC the construction of 600 megawatts of natural gas-fired combustion turbine peaking units at Clark Station to be installed in 2008 and 2009 at an approximate cost of $395 million. In the case of SPPC, the PUCN approved upgrades to the combustion systems to Valmy Units 1 and 2. For more details of NPC’s IRP and SPPC’s thirteenth amendment see Regulatory Proceedings later.
Nevada law sets forth the renewable energy portfolio standard (“Portfolio Standard”) requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable energy resources (Renewables). Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. In 2006, the Utilities were required to obtain six percent of their total energy from Renewables. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20% in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources. In 2007 and 2008 the Utilities will be required to obtain nine percent (9%) of their total energy from Renewables. The Utilities have embarked on a strategy to invest in renewable energy that, along with third party contracts, will provide the opportunity for the Utilities to meet the Portfolio Standard as set forth by Nevada law.
Management of Energy Risk
The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. While NPC has greatly reduced its dependence on wholesale power markets to meet its customers’ demand, both Utilities continue to have a significant need to tap energy markets due to the fact that the Utilities’ owned generation is insufficient to meet their customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies will not be sufficient to fulfill customer requirements.
The Utilities systematically manage and control each of the energy-related risks through three primary vehicles – organization and governance, energy risk management programs, and energy risk control practices.
The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.
The Utilities follow PUCN-approved energy supply plans that encompass the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for economic hedging in conjunction with energy purchases and sales are also used to mitigate these risks.
44
Liquidity and Access to Capital Markets
With volatile energy costs and substantial commitments to construction, SPR and the Utilities’ liquidity needs and access to capital markets was and continues to be a significant business issue. In 2006, management evaluated opportunities to refinance high yield debt at lower interest rates.
In 2006, SPR and the Utilities completed major financing transactions of approximately $1.6 billion that lowered our interest costs, improved liquidity and extended maturities which include:
| | • | | issuance of $325 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018 |
| |
| | • | | issuance of $370 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036 |
| |
| | • | | issuance of $210 million of NPC’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 |
| |
| | • | | issuance of $92.5 million of various NPC Pollution Control Refunding Revenue Bonds |
| |
| | • | | increases to NPC’s and SPPC’s Revolving Credit facilities to $600 million and $350 million, respectively |
| |
| | • | | issuance of $300 million of SPPC’s 6.0% General and Refunding Mortgage Notes, Series M, due 2016 |
| |
| | • | | issuance of $268 million of SPPC’s Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C |
| |
| | • | | SPR tendered for and extinguished approximately $85 million of SPR’s 8.625% Senior Notes and approximately $25 million of SPR’s 7.803% Senior Notes |
| |
| | • | | redemptions of various NPC debt of approximately $667.8 million |
| |
| | • | | redemption and payments of various SPPC debt of approximately $487 million |
| |
| | • | | redemption of $50 million of SPPC’s Series A Preferred Stock |
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds from the issuance were $280.6 million. In August 2006, SPR made a capital contribution to NPC for approximately $200 million. On December 27, 2006, SPR contributed capital to SPPC of approximately $75 million. SPR has invested the remaining proceeds in highly liquid short-term investments pending their use for general corporate purposes. As of December 31, 2006, SPR has 350 million shares of common stock authorized and approximately 221 million shares of common stock issued and outstanding.
Looking ahead
Management has been and continues to be focused on returning the Utilities’ senior secured debt to investment grade credit quality. Significant amounts of capital may be necessary to fund the construction costs of new power plants and, as a result, management may be required to meet such financial obligation with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and, if necessary, capital contributions from SPR. If energy costs rise at a rapid rate, and the Utilities do not recover, in a timely manner, the cost of fuel and purchased power, the Utilities may need to issue more debt to support their operating costs or may need to delay capital expenditures.
Regulatory
As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for annual rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every two years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. In addition, as necessary, the Utilities can file for a change to their Base Tariff Energy Rates (BTER) to more closely match actual prices. The Utilities remain committed to maintaining a positive relationship with their regulators. Details regarding recently approved and pending rate cases are discussed below inRegulatory Proceedingsdiscussed later.
45
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
SPR prepared its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In doing so, certain estimates were made that were critical in nature to the results of operations. The following discusses those significant estimates that may have a material impact on the financial results of SPR and the Utilities and are subject to the greatest amount of subjectivity. Senior management has discussed the development and selection of these critical accounting policies with the Audit Committee of SPR’s Board of Directors. The items discussed below represent critical accounting estimates that under different conditions or using different assumptions could have a material effect on the financial condition, results of operation, cash flows, liquidity and capital resources of SPR and the Utilities.
Regulatory Accounting
The Utilities’ retail rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the 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. Under federal law, wholesale rates charged by the Utilities 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.
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, Summary of Significant Accounting Policies of the Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery. Management’s judgment 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 and expensed in current period earnings.
Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Pensions, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below.
Deferred Energy Accounting
Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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 approval. Pursuant to AB 369, Nevada law 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, Nevada law specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. Both Utilities are entitled under statute to utilize deferred energy accounting for their electric operations and both Utilities accumulate amounts in their deferral of energy costs accounts. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances, recognized as interest income in the current period.
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 Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for a discussion of the Utilities’ purchased power procurement strategies, and commodity price risk and commodity risk management program. Currently, commodity price increases are recoverable through the deferred energy accounting mechanism, with no anticipated effect on earnings. 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.
See Note 3, Regulatory Actions of the Notes to Financial Statements, for additional discussion of the regulatory process to recover these deferred costs and description of the PUCN’s disallowance of significant amounts in NPC’s 2001 deferred energy cases.
46
Accounting for Derivatives and Hedging Activities
SPR, NPC, and SPPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.
Fuel and Purchased Power Contracts
In order to manage loads, resources, and energy price risk, the Utilities enter into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. In addition to forward fuel and power contracts, the Utilities also use over-the-counter options with financial institutions and other energy companies to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133 and are marked to market in the statement of financial position unless the contract qualifies for the normal purchases or sales exemption per the criteria in 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 options and these forward fuel and power contracts and other energy related derivative instruments.
In conjunction with the issuance of SFAS No. 133, the Public Utilities Commission of Nevada (PUCN) and in the case of SPPC, the California Public Utility Commission (CPUC) issued accounting orders authorizing the Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark to market gains and losses on energy commodity transactions until the period of settlement. The order provides for the Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the statement of operations and comprehensive income. Fuel and purchased power costs are subject to this accounting order and apply deferred energy accounting. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized in the period of settlement if currently recoverable or deferred if they are recoverable or payable through future rates.
The fair values of the forward contracts are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model that 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. The fair value of the Utilities derivative commodity instruments, which are recorded on the Consolidated Balance Sheet, are sensitive to market price fluctuations that can occur on a daily basis.
Accounting for Income Taxes
As of December 31, 2006, net operating losses (NOLs) were $227.1 million. The NOLs may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income.
The following table summarizes the NOL and tax credit carry-forwards and associated carry-forward periods, and a valuation allowance for amounts which SPR has determined that realization is uncertain (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Expiration |
| | | Deferred Tax Asset | | Valuation Allowance | | Net Deferred Tax Asset | | Period |
| | | |
| Federal NOL | | $ | 213,024 | | | $ | — | | | $ | 213,024 | | | | 2020-2023 | |
| State NOL | | | 1,058 | | | | — | | | | 1,058 | | | | 2008-2013 | |
| Research and development credit | | | 3,764 | | | | — | | | | 3,764 | | | | 2021-2025 | |
| Alternative minimum tax credit | | | 8,696 | | | | — | | | | 8,696 | | | indefinite |
| Arizona state coal credits | | | 1,292 | | | | 732 | | | | 560 | | | | 2007-2011 | |
| | | | | | | |
| Total | | $ | 227,834 | | | $ | 732 | | | $ | 227,102 | | | | | |
| | | | | | | |
At December 31, 2006, the Utilities had gross federal and state NOL carry-forwards of $608.6 million and $12.0 million, respectively.
Considering all positive and negative evidence regarding the utilization of the Utilities’ deferred tax assets, it has been determined that the Utilities are more likely than not to realize all recorded deferred tax assets, except for the Arizona coal tax credits. As such, these Arizona coal tax credits represent the only valuation allowance that has been recorded as of December 31, 2006.
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
47
(EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Department of Air Quality and Environmental Management (DAQEM) 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 any 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 13, Commitments and Contingencies of the Notes to Financial Statements, 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.
Defined Benefit Plans and Other Postretirement Plans
As further explained in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR maintains a qualified pension plan, a non-qualified supplemental executive retirement plan (SERP) and restoration plan, as well as an other postretirement benefit (OPEB) plan that provides health and life insurance for retired employees. All employees are eligible for these benefits if they terminate with certain age and service requirements from the qualified and restoration plans, or if they reach retirement age and meet certain service requirements under the SERP and OPEB plans 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 are ultimately collected in rates billed to customers. Amounts are funded to trusts maintained for the plans. The amounts funded are then used to meet benefit payments to plan participants. SPR contributed $17.3 million and $17 million to its pension plan, in 2006 and 2005, respectively, and $8.6 million and $14.9 million to the other postretirement benefits plan in 2006 and 2005, respectively. At the present time it is not expected that any additional funding for the pension plan will be required for plan years 2006 or 2007 to meet the minimum funding levels defined by ERISA. However, SPR and the Utilities currently expect to contribute in 2007 an amount similar to the 2006 funding. The amounts to contribute may change subject to market conditions. SPR uses a September 30 measurement date for its benefit plans.
Pension Plans
SPR’s reported costs of providing non-contributory defined pension benefits (described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) 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, the discount rates and demographic (mortality, retirement, termination) assumptions 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. SPR adopted SFAS 158 (Note 1 of Notes to the Financial Statements, Recent Pronouncements) in 2006. This pronouncement requires the immediate recognition of changes in benefit obligations due to differences between actuarial assumptions and actual experience in Accumulated Other Comprehensive Income, net of taxes. However, since SPR recovers SFAS 87 and SFAS 106 costs through rates, these amounts will be recorded as Other Regulatory Assets under the provisions of SFAS 71, and will be recognized as expense over a period of time. For the twelve months ended December 31, 2006, 2005, and 2004, SPR recorded pension expense for all pension plans of approximately $30.6 million, $23.5 million, and $28.3 million, respectively, in accordance with the provisions of SFAS No. 87. Actual payments of benefits made to retirees and terminated vested employees for the twelve months ended September 30, 2006, 2005 and 2004 were $21 million, $20.3 million and $17.5 million respectively.
48
SPR has not made changes to pension plan provisions in 2006, 2005, and 2004 that had significant impacts on recorded pension expense for these years. As further described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR increased the discount rate used in determining pension expense from 5.75% in 2006 to 6.00% for the calendar year 2007. For 2006, SPR moved to a more up-to-date mortality table. SPR also updated termination and retirement assumptions used to value benefit obligations as of December 31, 2006 as a result of an experience study.
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 such as current discount rates, mortality assumption and/or 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 for all pension plans. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that a decrease would impact the projected benefit obligation (PBO) and the reported annual pension cost (PC) 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.
| | | | | | | | | |
| | | Change in | | Impact on | | Impact on |
| Actuarial Assumption | | Assumption | | PBO | | PC |
| (dollars in millions) | | Incr/(Decr) | | Incr/(Decr) | | Incr/(Decr) |
| Discount Rate | | | 1 | % | | $(82.4) | | $(10.8) |
| Rate of Return on Plan Assets | | | 1 | % | | N/A | | $ (5.3) |
In selecting an assumed discount rate for fiscal years 2006 and 2005 disclosures, and for fiscal years 2006 and 2005 pension cost, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.
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. Investment returns on plan assets in the retirement plan gained approximately $34.4 million in 2006 and $55.7 million in 2005. These returns, in conjunction with SPR’s contributions, have improved the funded status compared to prior years.
Other Postretirement Benefits
SPR’s reported costs of providing other postretirement benefits (described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) 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, discount rates and demographic (mortality, retirement, termination) assumptions used in determining the postretirement benefit obligation and postretirement costs.
For the twelve months ended December 31, 2006, 2005 and 2004, SPR recorded other postretirement benefit expense of approximately $14.6 million, $14.1 million, and $13.4 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, 2006, 2005 and 2004 were $12.0 million, $8.1 million, and $8.0 million respectively.
SPR has not made changes to other postretirement benefit plan provisions in 2006, 2005, and 2004 that have had any significant impact on recorded benefit plan amounts. As further described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR has revised the discount rate for its 2006 disclosures to 6.00%, as compared to 2005 disclosures of 5.75%. For determining the expense to be recorded in 2007, SPR moved to a 6.00% discount rate from 5.75% in 2006. For 2006 expense, SPR also moved to a more up-to-date mortality table. SPR also updated termination and retirement assumptions used to value benefit obligations as of December 31, 2006 as a result of an experience study. The medical inflation trend assumption used to measure obligations was updated to reflect current expectations and recent experience by large employer health plans. 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 is proposing a change to the plan for SPPC’s bargaining unit 1245 employees, which was ratified on February 28, 2007, with final approval expected in March 2007. The proposed change would require a re-measurement of plan obligations.
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.
49
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 a decrease would impact the projected accumulated other postretirement benefit obligation (APBO) and the reported annual other postretirement benefit cost (PBC) on the income statement 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.
| | | | | | | |
| | | Change in | | Impact on | | Impact on |
| Actuarial Assumption | | Assumption | | APBO | | PBC |
| (dollars in millions) | | Incr/(Decr) | | Incr/(Decr) | | Incr/(Decr) |
| Discount Rate | | 1% | | $(21.4) | | $(1.9) |
| Health Care Cost Trend Rate | | 1% | | $19.6 | | $3.4 |
| Rate of Return on Plan Assets | | 1% | | N/A | | $(0.8) |
In selecting an assumed discount rate for fiscal year 2006 other postretirement benefits cost and disclosures, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.
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. Investment returns on plan assets gained $8 million in 2006 and $0.4 million in 2005.
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, 2006, include unbilled receivables of $92 million and $83 million for NPC and SPPC, respectively. Customer accounts receivable as of December 31, 2005 include unbilled receivables of $80 million and $77 million for NPC and SPPC, respectively.
RECENT PRONOUNCEMENTS
See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.
SIERRA PACIFIC RESOURCES
RESULTS OF OPERATIONS
Sierra Pacific Resources (Holding Company) and Other Subsidiaries
SPR (Holding Company)
The Holding Company’s (stand alone) operating results included approximately $51.4 million, $74.3 million, and $88.3 million of long-term debt interest costs for the years ended December 31, 2006, 2005 and 2004 respectively. The decrease in interest costs were primarily due to the conversion of SPR’s $300 million 7.25% Convertible Notes due 2010, the repurchase of the 7.93% Senior Notes associated with the PIES, and the reduced interest rate of 7.803% on the Senior Notes associated with the New PIES. See Note 14, Common Stock and Other Paid-in Capital of the Notes to Financial Statements, for further discussion on SPR debt. The Holding Company’s operating results for 2005 were negatively affected by early conversion fees of the Convertible Notes of approximately $35 million after taxes and unamortized debt issuance costs and legal fees associated with the Convertible Notes of approximately $4.7 million after taxes. See Note 6, Long-Term Debt of the Notes to Financial Statements, for further discussion of the conversion of the Convertible Notes. The Holding Company’s operating results for 2004 were negatively affected by an impairment of goodwill of approximately $11.7 million and higher interest costs. The Holding Company recognized charges of approximately $23.7 million during 2004 for tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8.75% Senior Unsecured Notes due 2005.
50
Tuscarora Gas Pipeline Company (TGPC)
TGPC, a wholly-owned subsidiary of SPR, sold its partnership interest in TGTC in December 2006. The gain from the sale of TGTC was approximately $40.9 million after taxes. TGPC contributed approximately $3.3 million after taxes in earnings for the year ended 2006 excluding the gain. TGPC contributed $5.1 million in net income applicable to common stock for the year ended December 31, 2005 and $5.2 million in net income applicable to common stock for the year ended December 31, 2004.
Sierra Pacific Communications
SPC, a wholly-owned subsidiary of SPR, incurred a net loss of $263.4 thousand for the year ended December 31, 2006, a net loss of $103 thousand for the year ended December 31, 2005, and a net loss of $3.2 million for the year ended December 31, 2004. SPC’s loss in 2004 was primarily due to the settlement with Sierra Touch America. See Note 17, Discontinued Operations and Disposal and Impairment of Long-Lived Assets of the Notes to Financial Statements for further discussion.
Other Subsidiaries
Other Subsidiaries of SPR did not contribute materially to the consolidated results of operations of SPR.
Sierra Pacific Resources (Consolidated)
See Executive Overview, Results of Operations for SPR Consolidated.
ANALYSIS OF CASH FLOWS
SPR’s consolidated net cash flows increased for the year ended December 31, 2006 compared to the same period in 2005, due to increases in cash from operating and financing activities, offset by cash used in investing activities. SPR received net proceeds of approximately $281 million from the issuance of 20 million shares of common stock in 2006. SPR also received approximately $100 million from the sale of TGTC. In December, SPR utilized a portion of the proceeds of common stock issuance and cash on hand for a tender offer that resulted in the extinguishment of approximately $85 million of SPR’s 8.625% Senior Notes and approximately $25 million of the 7.803% Senior Notes.
At various times during 2006, NPC borrowed a total of $710 million under its revolving credit facility and repaid a total of $860 million, including $150 million borrowed in 2005, using the net proceeds of issuance of $905 million of NPC’s General and Refunding Mortgage Notes, Series M, N and O and $200 million capital contribution from SPR. The remainder of the proceeds, together with the draw on the credit facility and cash from operations, was utilized to redeem approximately $563 million of outstanding debt and to pay associated costs and to finance net construction costs of $627 million. NPC also refinanced $92.5 million of tax exempt Revenue Bonds with newly issued auction rate Revenue Bonds during 2006.
At various times during 2006, SPPC borrowed approximately $248 million under its revolving credit facility, all of which was repaid during 2006. SPPC also issued $300 million in 6.0% General and Refunding Mortgage Notes, Series M, and $268 million in variable interest Pollution Control Revenue Bonds. A portion of the draw on the credit line was used to retire approximately $198 million of SPPC’s Medium Term Notes Series A, B and C. The net proceeds of the $300 million offering were used to pay off the amount borrowed under the revolving credit facility, redeem $20 million of Medium Term Notes, Series C, redeem $50 million of preferred stock and to pay associated costs, premiums and dividends. Proceeds from Pollution Control Revenue Bonds and cash from operations were used to retire $269 million of SPPC’s existing tax-exempt bonds.
Cash used for investing activities increased significantly when compared to 2005 primarily due to the acquisition of Silverhawk by NPC and the expansion of the Tracy Generating Station by SPPC. This increase was offset by the sale of the investment in Tuscarora for approximately $100 million and a reduction in construction at Lenzie that was placed in service in 2006.
Cash from operations increased during 2006 when compared to 2005 due to increases in deferred energy and general rates and a decrease in accounts receivable offset partially by the settlement with Enron. The increase was also offset by a reduction in accounts payable primarily associated with purchase power suppliers.
SPR’s consolidated net cash flows decreased for the year ended December 31, 2005 compared to the same period in 2004, as a result of decreases in cash from operating and financing activities and an increase in cash used by investing activities. Cash flows for operating activities are lower in 2005 due to energy costs being higher than amounts recovered in rates in 2005. Offsetting the decrease in cash from operating activities was the $60 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facilities and an increase in general rates in the second quarter of 2004. The increase in cash used by investing activities was mainly due to construction at NPC for the Chuck Lenzie project. The decrease in cash from financing activities in 2005, when compared to 2004, was primarily due to the reduction of debt issued in 2005.
51
LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)
Overall Liquidity
SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and interest.
| | | | | | | | | | | | | |
| Available Liquidity as of December 31, 2006 (in millions) |
| | | SPR | | NPC | | SPPC |
| | | |
| Cash and Cash Equivalents | | $ | 24.7 | | | $ | 36.6 | | | $ | 53.3 | |
| Balance available on Revolving Credit Facility | | | N/A | | | | 545.0 | | | | 340.6 | |
| | | | | | | | | | | | | |
| | | |
| Total Available Liquidity | | $ | 24.7 | | | $ | 581.6 | | | $ | 393.9 | |
| | | |
SPR has approximately $42.5 million payable of debt service obligations for 2007, which it intends to pay through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below)
SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, capital contributions from SPR.
On a consolidated basis, SPR’s overall liquidity continued to improve in 2006. The $200 million combined increase in the Utilities’ revolving credit facilities provides additional liquidity for increased commodity prices. SPR’s debt profile improved as a result of refinancing approximately $1.1 billion of long-term debt at the two Utilities. These refinancings are expected to reduce future interest expense.
SPR designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPR has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are SPR’s Capital Structure, Capital Requirements, recently completed stock and financing transactions and factors affecting our ability to obtain debt on favorable terms, including the effect of our holding company structure and limitation on dividends from the Utilities.
Capital Structure (SPR Consolidated)
SPR’s actual capital structure on a consolidated basis was as follows at December 31 (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 |
| Current Maturities of Long-Term Debt | | $ | 8,348 | | | | 0.1 | % | | $ | 58,909 | | | | 1.0 | % |
| Long-Term Debt | | | 4,001,542 | | | | 60.3 | % | | | 3,817,122 | | | | 63.8 | % |
| Preferred Stock | | | — | | | | — | % | | | 50,000 | | | | 0.8 | % |
| Common Equity | | | 2,622,297 | | | | 39.6 | % | | | 2,060,154 | | | | 34.4 | % |
| | | | | |
| Total | | $ | 6,632,187 | | | | 100 | % | | $ | 5,986,185 | | | | 100 | % |
| | | | | |
Capital Requirements
Construction Expenditures
SPR’s annual consolidated cash construction expenditures have increased since 2003 and are expected to continue to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2006, 2005 and 2004 were approximately $912 million, $590 million, and $557 million, respectively. SPR’s consolidated cash requirements for construction expenditures for 2007 are projected to be $1.4 billion. SPR’s consolidated cash requirements for cash construction expenditures for 2007-2011 are projected to be $7.8 billion. To fund these capital projects SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, capital contributions from SPR. Depending on the progress of the Ely Energy Center the timing and extent of the estimated capital expenditures necessary may change.
52
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, or Pension funding requirements as discussed in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, as of December 31, 2006, 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment Due by Period | | | | |
| | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | Thereafter | | | Total | |
| NPC/SPPC Long-Term Debt Maturities | | $ | 8,348 | | | $ | 329,468 | | | $ | 102,738 | | | $ | 7,843 | | | $ | 369,734 | | | $ | 2,654,363 | | | $ | 3,472,494 | |
| NPC/SPPC Long-Term Debt Interest Payments | | | 215,941 | | | | 203,602 | | | | 192,614 | | | | 192,188 | | | | 175,159 | | | | 1,663,305 | | | | 2,642,809 | |
| SPR Long-Term Debt Maturities | | | — | | | | — | | | | — | | | | — | | | | — | | | | 549,209 | | | | 549,209 | |
| SPR Long-Term Debt Interest Payments | | | 42,541 | | | | 42,541 | | | | 42,541 | | | | 42,541 | | | | 42,541 | | | | 135,707 | | | | 348,412 | |
| Purchased Power | | | 462,402 | | | | 368,810 | | | | 323,215 | | | | 323,882 | | | | 323,541 | | | | 3,925,708 | | | | 5,727,558 | |
| Coal and Natural Gas | | | 451,269 | | | | 147,851 | | | | 123,467 | | | | 95,525 | | | | 82,856 | | | | 544,908 | | | | 1,445,876 | |
| Long -Term Service Agreements(1) | | | 15,979 | | | | 13,867 | | | | 24,267 | | | | 22,037 | | | | 12,148 | | | | 123,783 | | | | 212,081 | |
| Capital Purchase Agreements | | | 13,121 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 13,121 | |
| Southern Operations Center Lease | | | 875 | | | | 3,000 | | | | 3,075 | | | | 3,180 | | | | 3,260 | | | | 65,320 | | | | 78,710 | |
| Operating Leases | | | 17,160 | | | | 17,443 | | | | 15,184 | | | | 12,748 | | | | 4,219 | | | | 101,046 | | | | 167,800 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Contractual Cash Obligations | | $ | 1,227,636 | | | $ | 1,126,582 | | | $ | 827,101 | | | $ | 699,944 | | | $ | 1,013,458 | | | $ | 9,763,349 | | | $ | 14,658,070 | |
| | | | | | | | | | | | | | | | | | | | | | |
(1) Does not include equipment and services contracts related to the new peaking units at Clark Generating Station, entered into in February 2007.
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 is expected to decrease in 2007 by approximately $1.3 million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date, the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006, SPR contributed a total of $16 million to meet their funding obligations under the plan. At the present time it is not expected that any additional funding will be required in 2007 to meet the minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA. However, SPR and the Utilities currently expect to contribute an amount similar to the 2006 funding. The amounts to be contributed may change subject to market conditions.
Capital Stock Transaction (SPR-Holding Company)
On May 1, 2006, SPR’s shareholders approved an amendment to SPR’s Restated Articles of Incorporation to increase the number of authorized shares of SPR common stock by 100 million shares, for a total amount of 350 million authorized shares.
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC for approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit facility. SPR invested the remaining proceeds in highly liquid short-term investments. In December 2006 these funds, along with net proceeds from the sale of TGTC, and available cash on hand, were used to fund the tender offer of a portion of SPR debt and to make a capital contribution to SPPC of approximately $75 million (see Overall Liquidity above). As of December 31, 2006, SPR had approximately 221 million shares of common stock issued and outstanding.
Financing Transactions (SPR-Holding Company)
Tender Offer
In November 2006, SPR commenced tender offers for up to $110 million aggregate principal amount of its 7.803% Senior Notes due 2012, its 8.625% Senior Notes due 2014, and its 6.75% Senior Notes due 2017. Each of the offers was conditioned on SPR purchasing no more than an aggregate principal amount of $110 million of all notes validly tendered. To meet this condition, SPR terminated the offer for the 6.75% Notes. In December 2006 approximately $25 million of the 7.803% Senior Notes outstanding, and approximately $85 million of the 8.625% Senior Notes outstanding were validly tendered and accepted by SPR. The total consideration paid was approximately $120.6 million (which included an early tender premium and accrued interest). As of December
53
31, 2006, the outstanding balances for the 7.803% Senior Notes and 8.625% Senior Notes were $74.2 million and $250.0 million, respectively.
Factors Affecting Liquidity
Effect of Holding Company Structure
As of December 31, 2006, SPR (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $74.2 million of its unsecured 7.803% Senior Notes due 2012; $225 million of its unsecured 6.75% Senior Notes due 2017; and $250 million of its unsecured 8.625% Senior Notes due 2014.
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 the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
As of December 31, 2006, SPR, NPC, SPPC and their subsidiaries had approximately $4.01 billion of debt and other obligations outstanding, consisting of approximately $2.39 billion of debt at NPC, approximately $1.07 billion of debt at SPPC and approximately $549 million of debt at the holding company and other subsidiaries. Although SPR and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, SPR and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.
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 impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In the PUCN order for Docket 05-10024 and 05-10025, issued in February 2006, a dividend restriction was instituted for both Utilities. Under this restriction, the combined amount that NPC and SPPC may pay to SPR each year is limited to the actual cash necessary to service SPR’s debt for the year. At the time of the order, SPR and the Utilities were only rated by Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. In February 2007, Dominion Bond Rating Service (“DBRS”), who had not previously issued ratings on the companies, assigned ratings for SPR, NPC and SPPC. DBRS and Fitch currently rate NPC and SPPC’s senior secured debt at the minimum level for investment grade. It is not clear what effect, if any, the DBRS rating will have on the PUCN dividend restriction. See “Credit Ratings” below for discussion of current ratings.
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 agreements entered into by the Utilities, restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are discussed in Note 8, Debt Covenant and Other Restrictions.
In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.
As of December 31, 2006, each Utility was able to pay dividends, subject to a cap, under the most restrictive test in its financing agreements; however, the total amount of dividends that the Utilities can pay to SPR under their financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under their financing agreements is greater than the amount that the Utilities can pay under the PUCN dividend restriction. In 2006, NPC paid $35.8 million and declared an additional $13.5 million in dividends to SPR and SPPC paid $17.9 million and declared an additional $6.7 million in dividends to SPR. In January 2007, SPPC paid $6.7 million in dividends to SPR and NPC paid $13.5 million in dividends to SPR.
54
Credit Ratings
SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations S&P, Moody’s, Fitch, and DBRS. As of February 23, 2007,the ratings are as follows:
| | | | | | | | | | | |
| | | | | Rating Agency |
| | | | | DBRS | | Fitch | | Moody’s | | S&P |
| SPR | | Sr. Unsecured Debt | | BB (low) | | BB- | | B1 | | B |
| NPC | | Sr.Secured Debt | | BBB (low)* | | BBB-* | | Bal | | BB+ |
| NPC | | Sr.Unsecured Debt | | Not rated | | BB | | Not rated | | B |
| SPPC | | Sr.Secured Debt | | BBB (low)* | | BBB-* | | Bal | | BB+ |
| | |
| * | | Ratings are investment grade |
In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB (low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.
In 2006, there were other changes to the ratings of the three companies. Fitch upgraded the ratings of SPR and the Utilities. The ratings for the senior secured debt of NPC and SPPC were increased to BBB-, the minimum level for investment grade. The senior unsecured debt for NPC was upgraded from BB- to BB, which is still non-investment grade. Fitch revised the rating outlook for SPR and the Utilities from Positive to Stable. S&P upgraded the ratings of NPC’s and SPPC’s senior secured debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its ratings for NPC’s and SPPC’s senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Energy 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 request adequate financial assurance, which, if not provided within three 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 three 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 December 31, 2006 for all suppliers continuing to provide power under a WSPP agreement would approximate a $55.8 million payment by NPC and an approximate $44.5 million payment by SPPC. These contracts qualify for the normal purchases scope exception of SFAS No. 133, and as such, are not required to be marked to market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. 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. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, four counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.
55
Financial Covenants
Nevada Power Company and Sierra Pacific Power Company
Each of NPC’s $600 million Second Amended and Restated Revolving Credit Agreement and SPPC’s $350 million Amended and Restated Revolving Credit Agreement, dated November 2005, and amended in April 2006, contains two financial maintenance covenants. The first requires that the Utility maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that the Utility maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2006, both Utilities were in compliance with these covenants.
Limitations on Indebtedness
Sierra Pacific Resources
The terms of SPR’s $250 million 8.625% Senior Unsecured Notes due March 2014, $74.2 million 7.803% Senior Unsecured Notes due 2012 and $225 million 6.75% Senior Unsecured Notes due 2017 restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional indebtedness unless:
1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or
2. the debt incurred is specifically permitted under the terms of the respective series of Senior Notes, which permits the incurrence of 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 supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers, or
3. the indebtedness is incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan and SPPC’s 2004 Integrated Resource Plan.
If the respective series of Senior Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the respective series of Senior Notes remain investment grade. As of December 31, 2006, SPR, NPC and SPPC would have been able to issue approximately$2.1 billion of additional indebtedness on a consolidated basis, assuming an interest rate of 7%, per the requirement stated in number 1 above.
Nevada Power Company
Certain factors impact NPC’s ability to issue debt:
| | 1. | | Financing Authority from the PUCN. In February 2006 NPC received PUCN authorization to enter into financings of $1.78 billion, which amount included $600 million for the revolving credit facility (described above). NPC has issued approximately $100 million of the new debt authorized under the PUCN Order. NPC’s only remaining authority under this PUCN Order allows NPC to refinance its existing debt and to use its $600 million revolving credit facility. |
| |
| | 2. | | Limits on Bondable Property. To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under its General and Refunding Mortgage Indenture. As of December 31, 2006, NPC had the capacity to issue $672 million of General and Refunding Mortgage Securities. |
| |
| | 3. | | Financial Covenants in its and SPR’s financing agreements. The terms of certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless certain conditions have been met. In addition to the SPR debt, the terms of certain NPC debt and the revolving credit facility restrict NPC from incurring any additional indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant and Other Restrictions of the Notes to Financial Statements in this report. |
As of December 31, 2006, the financial covenants under the revolving credit facility, which are more restrictive than the financial covenants found in other NPC debt, would allow NPC to issue up to $2.2 billion of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, of $2.1 billion as of December 31, 2006. However, since NPC currently has no PUCN authority to issue new debt, NPC is limited to borrowing under its credit facility. As of February 23, 2007, the balance available under the credit facility is$476.3 million.
56
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.1 billion, depending on the Utilities’ combined usage of their respective revolving credit facilities at the time of the covenant calculation.
Sierra Pacific Power Company
Certain factors impact SPPC’s ability to issue debt:
| | 1. | | Financing Authority from the PUCN. In February 2006, SPPC received PUCN authorization to enter into financings of $1.36 billion which amount includes $350 million for the revolving credit facility (described above). SPPC has issued $21 million of the new debt authorized in the PUCN Order. SPPC’s remaining authority under this PUCN Order allows SPPC to use its $350 million revolving credit facility, to issue $349 million in new debt, and to refinance existing debt as specified in the order. |
| |
| | 2. | | Limits on Bondable Property. To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of December 31, 2006, SPPC has the capacity to issue $381 million of General and Refunding Mortgage Securities. |
| |
| | 3. | | Financial Covenants in its and SPR’s financing agreements. The terms of certain SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless certain conditions have been met. In addition to the SPR debt, the terms of certain SPPC debt and the revolving credit facility restrict SPPC from incurring any additional indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant and Other Restrictions of the Notes to Financial Statements in this report. |
As of December 31, 2006, the financial covenants under the revolving credit facility, which are more restrictive than the financial covenants found in other SPPC debt, would allow SPPC to issue up to $797 million of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, at $2.1 billion as of December 31, 2006. As of February 23, 2007, the balance available under the credit facility is $331.1 million.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.1 billion, depending on the Utilities’ combined usage of their revolving credit facilities at the time of the covenant calculation.
Cross Default Provisions
None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by SPR or the other Utility under any of their respective financing agreements. Certain of SPR’s financing agreements, however, do contain cross-default provisions that would result in event of default by SPR upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of SPR and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity 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.
ENERGY SUPPLY (UTILITIES)
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 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. Some 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
57
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 IRP filed every three years, which has a twenty-year planning horizon; |
| |
| | (2) | | the Energy Supply Plan (“ESP”), which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio strategies 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 ESP operates in conjunction with the PUCN-approved twenty-year IRP. It serves as a guide for near-term execution and fulfillment of energy needs. When the ESP calls for executing contracts with a duration of more than three years, the IRP regulations require PUCN approval as part of the resource planning process.
In developing energy supply plans and executing such plans, management guidelines followed by the Utilities include:
| | • | | Maintaining an energy supply plan that balances the goals of minimizing costs, risks and price volatility (retail price stability), while maximizing reliability and predictability of supply. |
| |
| | • | | Investigating feasible commercial options to execute the ESP. |
| |
| | • | | Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction. |
| |
| | • | | Monitoring the portfolio against evolving market conditions and managing the resource optimization options. |
| |
| | • | | Ensuring 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 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 thresholds 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 IRPs 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. NPC’s IRP was filed in June 2006 and received approval in November 2006. SPPC’s IRP was filed in July 2004 and approved on November 2004. Between IRP filings, the Utilities are required to seek PUCN approval for modifications to their resource plans and for power purchases with terms of three years or greater by filing amendments to prior IRP filings.
The Utilities 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 recovery in rates.
58
Intermediate Term Energy Supply Plans
The Utilities update their intermediate term ESPs on an annual basis. In June 2006, NPC filed a new 20 year IRP, which included an ESP for years 2007-2009. In July 2006, SPPC filed the Thirteenth Amendment to its 2004 IRP which included, among other things, an ESP update for the remaining year of the planning cycle, 2007. Both plans were approved by the EROC and the CEO prior to submission to the PUCN. The Energy Supply Plans operate within the framework of the PUCN-approved twenty-year IRPs. They serve as a guide for near-term execution and fulfillment of energy needs. When the ESPs call for the execution of contracts of duration of more than three years, an amendment to the IRP is prepared and submitted for PUCN approval. The fuel, power procurement and risk management strategies contained in the ESPs filed in 2006 were found to be reasonable and prudent by the PUCN in November 2006.
In 2006, NPC added a significant amount of new, efficient, generating capacity to its system (Lenzie 1 and 2, Silverhawk and Harry Allen 4), essentially doubling the amount of Company-owned generating resources. For the remainder of their power needs, the PUCN approved ESPs provide for a competitive acquisition process to secure the required resources. Both Utilities have issued Requests For Proposals and executed forward contracts for their peak resource needs for the summer of 2007. The portfolio mix consists of owned generating resources, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to gas prices), to meet the following requirements:
| | • | | Optimize the tradeoff between overall fuel and purchase power cost and market price and supply risk. |
| |
| | • | | Pursue in-region capacity to enhance long-term regional reliability. |
| |
| | • | | Represent the set of transactions/products available in the market. |
| |
| | • | | Reduce credit risk—in a market with some counter-parties in weak financial conditions. |
| |
| | • | | Procure to match a difficult load profile, to the extent possible. |
| |
| | • | | Hedge the gas price risk exposure in the fuel portfolio through the purchase of a set of risk management options. |
| |
| | • | | Manage 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). |
Both of the ESPs reflect the Utilities’ strategies, embedded in their filed IRPs, to minimize supply and price risk through acquisition or construction of company owned generating resources in the intermediate term (e.g., peaking capacity at Clark Generating Station; Tracy combined cycle addition), forward contracts to meet capacity needs in the shorter term, and pursuit of fuel diversity options such as coal and renewables in the longer term.
Long Term Purchase Power Activities
The Utilities update their long-term energy supply plans on an annual basis in concert with the preparation of their respective ESPs, which are described in the preceding section. As noted above, the ESPs serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plans call for contracts of duration more than three years, requests for proposals are issued, bids are evaluated, and contracts are executed with the successful bidders. Those contracts are submitted to the PUCN for approval through an amended IRP.
As noted in the preceding section, the Utilities have reduced their longer-term needs for power from those in prior years. The Utilities have not entered into a long-term purchase agreement for conventional power since 2003. Currently, NPC has approximately 1,329 MW of long term contracts with various providers, terms and expiration dates, and 305 MWs of long term contracts with Qualifying Facilities. SPPC currently has 83 MWs of long term contracts which expire by 2009.
The Utilities also entered into long-term contracts with renewable energy providers.
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 and operating reserve requirement. The Utilities commit and dispatch generating units based on the comparative economics of generation versus spot-market purchase opportunities. Any amount of excess capacity or energy is sold on the wholesale market, while any deficient capacity or energy position is filled by either buying on the spot market or utilizing available generating capacity.
The day-ahead resource optimization begins with an analysis of projected hourly loads, existing resources, and operating reserve requirements. Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. The day-of resource optimization involves minimizing system production costs each hour by lowering or raising generating unit output or buying power and/or selling excess power in the wholesale market all in order to meet the system load
59
requirement and operating reserve requirement. 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 available excess energy when it exists.
Real-time resource optimization requires an hourly determination of whether to increase or decrease the loading of on-line generating units, commit previously off-line generating units, un-commit on-line generating units, sell excess power, or purchase power in the real-time market to meet the companies’ resource needs. In order to achieve the lowest production cost, the projected incremental or decremental cost of the next available generation resource options is compared to determine the lowest cost option.
Additional generating assets are expected to result in an uncommitted long peak position during the shoulders months. This will present resource procurement with the opportunity to implement a more active asset optimization strategy.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of $224.5 million in 2006 compared to net income of $132.7 million in 2005 and $104.3 million in 2004. NPC’s operating results for 2006 improved over 2005 primarily as a result of the July 2006, Nevada Supreme Court ruling which allows NPC to recover the approximate $180 million of the previously disallowed deferred energy costs and the carrying charge associated with the Lenzie generating station, partially offset by increased interest expense. NPC’s operating results for 2005 improved over 2004 primarily as a result of an increase in operating income, as discussed in detail below, an increase in Allowance for Other Funds Used During Construction and Allowance for Borrowed Funds During Construction and lower interest costs.
In 2006, NPC paid $35.8 million in dividends to SPR and declared an additional $13.5 million dividend. In 2005, NPC paid and declared common stock dividends of $35.3 million to SPR.
Gross margin is presented by NPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.
NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every two years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.
60
The components of gross margin for the years ended December 31 (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | 2006 | | | Prior Year % | | | 2005 | | | Prior Year % | | | 2004 | |
| Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 2,124,081 | | | | 12.8 | % | | $ | 1,883,267 | | | | 5.6 | % | | $ | 1,784,092 | |
| | | | | | | | | | | | | | | | | | | | | |
| Energy Costs: | | | | | | | | | | | | | | | | | | | | |
| Purchased power | | | 764,850 | | | | -20.6 | % | | | 963,888 | | | | 26.1 | % | | | 764,347 | |
| Fuel for power generation | | | 552,959 | | | | 99.6 | % | | | 277,083 | | | | 17.7 | % | | | 235,404 | |
| Deferral of energy costs disallowed | | | — | | | | | | | | — | | | | -100.0 | % | | | 1,586 | |
| Deferral of energy costs-net | | | 92,322 | | | | -302.2 | % | | | (45,668 | ) | | | -133.6 | % | | | 135,973 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 1,410,131 | | | | 18.0 | % | | $ | 1,195,303 | | | | 5.1 | % | | $ | 1,137,310 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Gross Margin before reinstatement of Deferred Energy | | $ | 713,950 | | | | 3.8 | % | | $ | 687,964 | | | | 6.4 | % | | $ | 646,782 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Reinstatement of Deferred Energy | | $ | 178,825 | | | | N/A | | | $ | — | | | | N/A | | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Gross Margin after reinstatement of Deferred Energy | | $ | 892,775 | | | | 29.8 | % | | $ | 687,964 | | | | 6.4 | % | | $ | 646,782 | |
| | | | | | | | | | | | | | | | | | |
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
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | | | | | | | | | Change | | | | |
| | | | | | | Change from | | | | | | | from Prior | | | | |
| | | Amount | | | Prior year | | | Amount | | | year | | | Amount | |
Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 975,568 | | | | 18.5 | % | | $ | 823,095 | | | | 7.9 | % | | $ | 762,907 | |
| Commercial | | | 442,477 | | | | 12.0 | % | | | 395,016 | | | | 6.1 | % | | | 372,271 | |
| Industrial | | | 631,762 | | | | 12.8 | % | | | 560,059 | | | | 5.7 | % | | | 529,916 | |
| | | | | | | | | | | | | | | | | | |
| Retail Revenues | | | 2,049,807 | | | | 15.3 | % | | | 1,778,170 | | | | 6.8 | % | | | 1,665,094 | |
Other1 | | | 74,274 | | | | -29.3 | % | | | 105,097 | | | | -11.7 | % | | | 118,998 | |
| | | | | | | | | | | | | | | | | | |
Total Revenues | | $ | 2,124,081 | | | | 12.8 | % | | $ | 1,883,267 | | | | 5.6 | % | | $ | 1,784,092 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of megawatt-hours (MWh) | | | 20,820 | | | | 7.0 | % | | | 19,455 | | | | 4.6 | % | | | 18,607 | |
| | | | | | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | | $ | 98.45 | | | | 7.7 | % | | $ | 91.40 | | | | 2.1 | % | | $ | 89.49 | |
| |
| 1 | Primarily wholesale, as discussed below |
NPC’s retail revenues increased in 2006 compared to 2005 due to increases in retail rates, customer growth and weather. Retail rates increased as a result of NPC’s various Base Tariff Energy Rate (BTER) and deferred energy cases (see “Regulatory Proceedings”). Residential, commercial and industrial customers increased by 4.9%, 5.1% and 4.3%, respectively. Customer usage increased due to colder winter weather and hotter spring weather. Based on NPC’s projected customer forecast, NPC expects retail electric customers in the Clark County area to continue to grow in 2007.
In November 2006, NPC filed its General Rate Case with the PUCN. The filing requests an overall rate increase, with rates to be effective June 1, 2007. In January 2007, NPC filed its annual deferred energy filing and an application to request recovery of deferred legal and settlement costs incurred for terminated power contracts executed during the Western Energy Crisis. If approved by the PUCN, the overall effect of both filings would be a slight decrease in rates. NPC requested that the rates become effective on June 1, 2007. A decision on these cases is expected in the Spring of 2007. For further discussion on the various cases see Regulatory Proceedings, later.
61
NPC’s retail revenues were higher in 2005 compared to 2004 primarily due to customer growth and higher rates. Increases in the number of residential, commercial and industrial customers were 5.5%, 5.7% and 3.8%, respectively. Higher rates became effective in April 2004, which were the result of NPC’s 2003 General and Deferred Rate Cases and October 2005, as a result of NPC’s 2005 BTER Update. These increases were slightly offset by a decrease resulting from NPC’s 2004 Deferred Energy Rate Case effective April 2005.
Electric Operating Revenues — Other decreased in 2006 compared to 2005, primarily due to revenues associated with Mohave which have been reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on Mohave refer to Note 13, Commitments and Contingencies in the Notes to Financial Statements. Also contributing to the decrease was a decrease in transmission revenues as a result of the purchase of Silverhawk. In 2005, the previous owner of Silverhawk used NPC’s transmission system to distribute electricity from the facility.
The decrease in Electric Operating Revenues — Other in 2005 compared to 2004 was primarily due to certain types of transactions that were reported in revenues for 2004, which are now netted in purchased power. The decrease also included decreased energy usage by Public Authority customers due to their transitioning to distribution only services by purchasing their energy from other sources, as allowed by Nevada law under certain circumstances. Partially offsetting this decrease was a refund in 2004 of $5.9 million owed to transmission customers as a result of FERC’s approval of a tariff agreement in July 2004. For further discussion on the Transmission case see Note 3, Regulatory Actions of the Notes to Financial Statements. The tariff agreement also lowered the transmission rates which contributed to the decrease in 2005 revenues.
Purchased Power
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior Year | | Amount | | Prior Year | | Amount |
Purchased Power | | $ | 764,850 | | | | -20.6 | % | | $ | 963,888 | | | | 26.1 | % | | $ | 764,347 | |
| | | | | | | | | | | | | | | | | | | | | |
| Purchased power in thousands of MWh | | | 10,248 | | | | -20.5 | % | | | 12,894 | | | | 4.7 | % | | | 12,319 | |
| Average cost per MWh of Purchased power | | $ | 74.63 | | | | -0.2 | % | | $ | 74.75 | | | | 20.5 | % | | $ | 62.05 | |
NPC’s purchased power costs decreased in 2006 compared to 2005, primarily due to an increase in internal generation with the addition of the Silverhawk and Lenzie plants. As a result, the volume of MWh purchased decreased compared to the prior year.
NPC’s purchased power costs increased in 2005 compared to 2004, due to higher prices and increased volume. NPC’s energy contracts calculate prices using gas indexes; therefore, higher natural gas prices in 2005 increased the price of purchased power. Furthermore, purchased power costs were higher due to gas tolling agreements entered into during the second quarter of 2004 and June 2005. These gas tolling agreements are purchased power agreements where NPC provides natural gas to the supplier who generates the energy for NPC. The gas tolling agreements are based on gas indexes; therefore, the increase in natural gas prices increased the cost of purchased power. Volume increased because NPC satisfied more of its native load requirements through purchased power rather than generation.
Fuel for Power Generation
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior year | | Amount | | Prior year | | Amount |
Fuel for Power Generation | | $ | 552,959 | | | | 99.6 | % | | $ | 277,083 | | | | 17.7 | % | | $ | 235,404 | |
| | | | | | | | | | | | | | | | | | | | | |
| Thousands of MWhs generated | | | 12,160 | | | | 50.2 | % | | | 8,094 | | | | -4.4 | % | | | 8,470 | |
| Average fuel cost per MWh of Generated Power | | $ | 45.47 | | | | 32.8 | % | | $ | 34.23 | | | | 23.2 | % | | $ | 27.79 | |
Fuel for power generation increased in 2006 as compared to 2005 due to several factors:
| | • | | With the addition of Silverhawk and Lenzie it was more economical for NPC to rely on its own generation rather than the purchase of power. As a result, the increase in volume of MWh’s generated increased significantly compared to the prior year. |
62
| | • | | The shutdown of Mohave as of the beginning of the year increased the cost per MWh of generated power. Although Silverhawk and Lenzie are highly efficient generation stations, the cost of coal is substantially lower than the cost of natural gas. Mohave generation during 2005 represented approximately 17% of total generation. |
| |
| | • | | Hedging instruments purchased when gas prices were escalating as a result of the 2005 hurricanes in the southern United States increased fuel for power generation costs. The settlement of these instruments during 2006 negatively impacted the average cost per MWh as natural gas prices were decreasing during this period. |
Fuel for power generation costs increased in 2005 as compared to 2004 due to the increased price of natural gas. The decrease in volume of generation was primarily due to NPC satisfying more of its native load requirements through purchased power rather than generation. The increase in average unit fuel cost per megawatt-hour was primarily due to higher gas costs in 2005 compared to 2004.
Deferral of Energy Costs — Net
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | Amount | | | Prior year | | | Amount | | | Prior year | | | Amount | |
| Reinstatement of deferred energy | | $ | (178,825 | ) | | | | | | $ | — | | | | | | | $ | — | |
| Deferred energy costs disallowed | | | — | | | | | | | | — | | | | | | | | 1,586 | |
| Deferral of energy costs-net | | | 92,322 | | | | N/A | | | | (45,668 | ) | | | N/A | | | | 135,973 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | (86,503 | ) | | | | | | $ | (45,668 | ) | | | | | | $ | 137,559 | |
| | | | | | | | | | | | | | | | | | |
Reinstatement of deferred energy represents the July 2006 decision by the Nevada Supreme Court which ruled that NPC is allowed to recover approximately $180 million of previously disallowed deferred energy and directed the District Court to remand the issue back to the PUCN to determine the rate schedule that will be used to recover this amount. In all other respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance. As a result of the Nevada Supreme Court decision, NPC recorded approximately $180 million before tax, of the previously disallowed deferred energy in its Consolidated Income Statement as “Reinstatement of Deferred Energy.” See Regulatory Proceedings, for further discussion of the $180 million of deferred energy.
Deferred energy costs disallowed for 2004 reflect the first quarter write-off of $1.6 million in electric deferred energy costs incurred during the twelve months ended September 30, 2003, that were disallowed by the PUCN in their March 2004 decision in NPC’s deferred energy rate case.
Deferred energy costs — net represent the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy costs - - net also include the current amortization of fuel and purchased power costs previously deferred. See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of Notes to Financial Statements for further detail of deferred energy balances.
Amounts for 2006, 2005 and 2004 include amortization of deferred energy costs of $120.5 million, $131.5 million and $228.8 million, respectively; and under-collections of amounts recoverable in rates of $28.2 million, $177.1 million and $92.7 million, respectively.
63
Allowance for Funds Used During Construction (AFUDC)
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | Amount | | | Prior year | | | Amount | | | Prior year | | | Amount | |
| Allowance for other funds used during construction | | $ | 11,755 | | | | -37.1 | % | | $ | 18,683 | | | | 341.7 | % | | $ | 4,230 | |
| | | | | | | | | | | | | | | | | | | | | |
| Allowance for borrowed funds used during construction | | | 11,614 | | | | -49.9 | % | | | 23,187 | | | | 304.1 | % | | | 5,738 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 23,369 | | | | -44.2 | % | | $ | 41,870 | | | | 320.0 | % | | $ | 9,968 | |
| | | | | | | | | | | | | | | | | | |
AFUDC for NPC was lower in 2006 compared to 2005 due to a decrease in Construction Work in Progress (CWIP) balance on which AFUDC is calculated. The decrease in the average CWIP balance was primarily due to the completion of Blocks 1 and 2 of the Chuck Lenzie Station and Harry Allen Unit 4 in early spring of 2006.
AFUDC was higher in 2005 compared to 2004 due to the construction of Blocks 1 and 2 of the Lenzie Generating Station.
Other (Income) and Expenses
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior year | | Amount | | Prior year | | Amount |
| Other operating expense | | $ | 218,120 | | | | 3.4 | % | | $ | 211,039 | | | | 14.9 | % | | $ | 183,736 | |
| Maintenance expense | | $ | 61,899 | | | | 18.9 | % | | $ | 52,040 | | | | -8.7 | % | | $ | 57,030 | |
| Depreciation and amortization | | $ | 141,585 | | | | 14.1 | % | | $ | 124,098 | | | | 4.4 | % | | $ | 118,841 | |
| Interest charges on long-term debt | | $ | 171,188 | | | | 7.6 | % | | $ | 159,106 | | | | 4.2 | % | | $ | 152,764 | |
| Interest for energy suppliers | | $ | — | | | | N/A | | | $ | (14,825 | ) | | | -38.7 | % | | $ | (24,171 | ) |
| Interest charges-other | | $ | 17,038 | | | | 25.6 | % | | $ | 13,563 | | | | -6.7 | % | | $ | 14,533 | |
| Carrying charge for Lenzie | | $ | (33,440 | ) | | | N/A | | | $ | — | | | | N/A | | | $ | — | |
| Interest accrued on deferred energy | | $ | (21,902 | ) | | | 7.6 | % | | $ | (20,350 | ) | | | 0.7 | % | | $ | (20,199 | ) |
| Other income | | $ | (16,992 | ) | | | -33.7 | % | | $ | (25,626 | ) | | | 12.2 | % | | $ | (22,844 | ) |
| Disallowed merger costs | | | | | | | N/A | | | $ | — | | | | N/A | | | $ | 3,961 | |
| Other expense | | $ | 8,480 | | | | -0.5 | % | | $ | 8,525 | | | | 27.9 | % | | $ | 6,665 | |
Other operating expense increased in 2006 compared to 2005 due to various costs all of which were not individually significant. These increases were partially offset by a decrease in legal fees and operating expense related to Mohave, Reid Gardner and Clark compared to 2005.
Other operating expense increased for 2005 compared to 2004 primarily due to increased advisory fees, amortization of regulatory assets and severance costs associated with the reorganization of SPPC, NPC and SPR.
The increase in Maintenance expense in 2006 compared to 2005 was primarily due to the addition of Lenzie and Silverhawk Generating Stations in 2006; partially offset by reduced maintenance expenses for Mohave and Navajo.
The decrease in Maintenance expense in 2005 compared to 2004 was due to the timing of scheduled and unscheduled plant maintenance at Clark Station, Reid Gardner and Navajo during 2004.
Depreciation and amortization increased in 2006 compared to 2005 primarily as a result of increases in plant-in-service. The increase is primarily due to the purchase of Silverhawk and completion of the Harry Allen Unit IV. The increase in depreciation and amortization expense between 2005 and 2004 was the result of routine increases to plant-in-service to serve regular system growth.
Interest charges on Long-Term Debt increased for the year ended December 31, 2006, compared to 2005 due primarily to the issuance in January 2006 of $210 million Series M, General and Refunding Mortgage Notes and the use of the Revolving Credit Facility, partially offset by various refinancings of debt at lower interest rates. The $210 million was issued to fund the acquisition of the Silverhawk Generating Facility. Interest charges related to this issuance was approximately $11.9 million. NPC’s use of the Revolving Credit Facility increased in 2006 primarily due to increased capital expenditures and fuel and purchase power expenses. Interest expense for the Revolving Credit Facility was approximately $12 million compared to $1.9 million in the prior year.
64
Interest charges on Long-Term Debt increased slightly for the year ended December 31, 2005, compared to 2004 due primarily to increases in long-term debt balances related to new debt issued in November 2004 of $250 million, interest associated with various draws from the Long-Term Credit Facility in 2005, and an increase in interest rates on NPC’s $115 million variable rate interest notes in 2005. This increase was partially offset by debt redemptions, in July 2005 of $87.5 million and $122.5 million. See Note 6, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt.
NPC’s interest charges for energy suppliers are comprised of interest accruals for terminated supplier balances that had been subject to litigation. The amount reported in 2005 includes reversals of accrued balances due to settlements reached with suppliers. The amount reported in 2004 includes the reversal of $28 million resulting from a ruling by the U.S. District Court that lowered the interest rate previously accrued. See Note 13, Commitments and Contingencies of the Notes to Financial Statements, for more information regarding the Enron litigation.
NPC’s interest charges-other increased for the year ended December 31, 2006 when compared to the same period in 2005, due to higher costs related to new debt issues and redemptions. Interest charges-other for the year ended December 31, 2005 decreased compared to the same period in 2004 following reduced charges related to NPC’s short-term credit facilities. These costs were offset with additional costs associated with the debt redemption of $210 million in July 2005. See Note 6, Long-Term Debt of the Notes to Financial Statements, for additional information regarding long-term debt.
NPC’s carrying charges on Lenzie for the year ended December 31, 2006 represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. See Note 1 of the Notes to Financial Statements for discussion of the accounting for the carrying charge for Lenzie.
NPC’s Interest accrued on deferred energy for the year ended December 31, 2006, were slightly higher than the same period in 2005 due to slightly higher average deferred energy balances during 2006, excluding deferred energy assets of $179 million associated with the Nevada Supreme Court decision reversing the deferred energy costs disallowance. NPC’s interest accrued on deferred energy costs was comparable for 2005 to 2004. See Note 3, Regulatory Actions of the Notes to Financial Statements for further discussion of deferred energy accounting issues and Note 13, Commitments and Contingencies of the Notes to Financial Statements for further discussion of the Nevada Supreme Court decision.
Disallowed merger costs for the year ended December 31, 2004 were a result of the PUCN decision in NPC’s 2003 General Rate Case. The PUCN decision permitted substantially all of the merger costs that NPC requested recovery of, except for a 20% reduction in merger costs that were to be amortized over the next two years. Also included in the write-off are merger costs allocable to non-Nevada jurisdictional sales that NPC had determined not to be recoverable in rates. See “Regulatory Proceedings” — and Note 3, Regulatory Actions of the Notes to Financial Statements, for additional information regarding NPC’s recovery of merger costs.
NPC’s Other income decreased for the year ended December 31, 2006 compared to the same period in 2005 due primarily to the lower amortization of gains associated with disposition of SO2 allowances and the expiration of the amortization associated with the disposition of property offset slightly by higher interest income. NPC’s Other income slightly increased for the year ended December 31, 2005 compared to the same period in 2004 due to higher interest income offset by lower amortization of gains associated with disposition of SO2 allowances.
NPC’s Other expense was comparable for 2006 to 2005. NPC’s Other expense increased for the year ended December 31, 2005 compared to the same period in 2004 due primarily to higher expenses associated with corporate advertising, lobbying activities, and various other charges, all of which were not individually significant.
ANALYSIS OF CASH FLOWS
NPC’s cash flows increased during the year ended December 31, 2006, compared to the same period in 2005, due to an increase in cash from financing activities, a slight increase in cash from operating activities offset partially by an increase in use of cash by investing activities.
At various times during 2006, NPC borrowed a total of $710 million under its revolving credit facility and repaid a total of $860 million, including $150 million borrowed in 2005, using the net proceeds of issuance of $905 million of NPC’s General and Refunding Mortgage Notes, Series M, N and O and a $200 million capital contribution from SPR. The remainder of the proceeds, together with the draw on the credit facility and cash from operations, was utilized to redeem approximately $563 million of outstanding debt and to pay associated costs and to finance net construction costs of $627 million. NPC also refinanced $92.5 million of Revenue Bonds with newly issued auction rate Revenue Bonds during 2006. In 2006, SPR contributed capital of $200 million to NPC and NPC paid dividends to SPR of approximately $35.8 million.
Cash used by investing activities increased in 2006 when compared to 2005 primarily due to the acquisition of Silverhawk and improvements at other generating stations, offset by a reduction in spending at the Lenzie plant that was placed in service in 2006.
65
Cash from operations increased during 2006 when compared to 2005 due to rate increases for deferred energy and a decrease in accounts receivable, offset by a decrease in collections for deferred energy balances due to the ending of collection periods and a reduction in accounts payable primarily associated with purchase power suppliers. The increase was also offset by the settlement with Enron.
NPC’s cash flows decreased during the year ended December 31, 2005, compared to the same period in 2004, as a result of an increase in cash used for investing activities and by decreases in cash flows from operating and financing activities. Cash used in investing activities increased mainly due to an increase in utility construction for the Chuck Lenzie project under construction in 2005. The decrease in cash from operating activities is primarily due to energy costs being higher than amounts recovered in rates in 2005 and changes in accounts receivable for tax sharing agreements. Also partially offsetting the decrease in cash from operating activities was the $49 million escrow payment for Enron in 2004, and a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility. Cash from financing activities decreased in 2005 due to a reduction in debt issued in 2005, offset by additional investments from the parent company and lower dividend payments. NPC was able to retire $210 million of high yield notes in the third quarter utilizing the majority of a $230 million equity contribution from SPR, per the equity claw-back provisions of the note.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on NPC’s outstanding indebtedness.
| | | | | |
| Available Liquidity as of December 31, 2006 (in millions) | |
| | | NPC | |
| Cash and Cash Equivalents | | $ | 36.6 | |
| Balance available on Revolving Credit Facility | | | 545.0 | |
| | | | | |
| | | | |
Total Available Liquidity1 | | $ | 581.6 | |
| | | | |
| |
| 1 | As of February 23, 2007, NPC had approximately $476.3 million available under its revolving credit facility. |
In August 2006, SPR contributed capital to NPC of approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit facility. There were no other capital contributions from SPR to NPC in 2006.
In 2006, NPC paid $35.8 million in dividends to SPR and declared an additional $13.5 million dividend. In January 2007, NPC paid the $13.5 million dividend to SPR.
NPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and external borrowings. However, to fund capital requirements, as discussed below, NPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the issuance of long-term debt. Additional liquidity beyond the amount indicated in the footnote above would come from a capital contribution from SPR, or through additional financing authority granted by an order of the PUCN, requested through the submittal of a financing application.
NPC’s overall liquidity continued to improve in 2006. NPC’s revolving credit facility was increased to $600 million in April, 2006, providing $100 million of additional liquidity for increased commodity prices. NPC’s debt profile improved as a result of refinancing more than $668 million of long-term debt. These refinancings are expected to reduce future interest expense.
NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are NPC’s Capital Structure, Capital Requirements, Contractual Obligations, recently completed Financing Transactions and Factors Affecting Liquidity including our ability to obtain debt on favorable terms and limitations on indebtedness.
66
Capital Structure
NPC’s actual consolidated capital structure was as follows at December 31 (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 |
| | | | | |
| Current Maturities of Long-Term Debt | | $ | 5,948 | | | | 0.1 | % | | $ | 6,509 | | | | 0.2 | % |
| Long-Term Debt | | | 2,380,139 | | | | 52.2 | % | | | 2,214,063 | | | | 55.6 | % |
| Common Equity | | | 2,172,198 | | | | 47.7 | % | | | 1,762,089 | | | | 44.2 | % |
| | | | | |
| Total | | $ | 4,558,285 | | | | 100 | % | | $ | 3,982,661 | | | | 100 | % |
| | | | | |
Capital Requirements
Construction Expenditures
NPC’s cash construction expenditures have increased since 2004 and are expected to continue to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2006, 2005 and 2004 were approximately $627.0 million, $478 million, and $454 million, respectively. NPC’s cash requirement for construction expenditures for 2007 are projected to be $980.1 million. NPC’s cash requirement for construction expenditures for 2007 through 2011 are projected to be $5.9 billion. To fund these capital projects NPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility, the issuance of long-term debt, and if necessary, capital contributions from SPR. Depending on the progress of the Ely Energy Center, the timing and extent of the estimated capital expenditures necessary may change.
Contractual Obligations
The table below provides NPC’s consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2006, 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment Due by Period | |
| | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | Thereafter | | | Total | |
| Long-Term Debt Maturities | | $ | 5,948 | | | $ | 7,068 | | | $ | 22,138 | | | $ | 7,843 | | | $ | 369,734 | | | $ | 1,986,113 | | | $ | 2,398,844 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-Term Debt Interest Payments | | | 153,962 | | | | 154,367 | | | | 154,228 | | | | 153,812 | | | | 136,782 | | | | 1,261,214 | | | | 2,014,365 | |
| Purchased Power | | | 310,988 | | | | 257,739 | | | | 239,361 | | | | 244,305 | | | | 242,671 | | | | 2,868,242 | | | | 4,163,306 | |
| Coal and Natural Gas | | | 250,201 | | | | 62,833 | | | | 50,075 | | | | 47,107 | | | | 34,438 | | | | 183,550 | | | | 628,204 | |
| Long -Term Service Agreements(1) | | | 15,979 | | | | 13,867 | | | | 24,267 | | | | 22,037 | | | | 12,148 | | | | 123,783 | | | | 212,081 | |
| Southern Operations Center Lease | | | 875 | | | | 3,000 | | | | 3,075 | | | | 3,180 | | | | 3,260 | | | | 65,320 | | | | 78,710 | |
| Operating Leases | | | 6,525 | | | | 7,146 | | | | 6,253 | | | | 5,161 | | | | 3,441 | | | | 64,459 | | | | 92,985 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Contractual Cash Obligations | | $ | 744,478 | | | $ | 506,020 | | | $ | 499,397 | | | $ | 483,445 | | | $ | 802,474 | | | $ | 6,552,681 | | | $ | 9,588,495 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Does not include equipment and services contracts related to the new peaking units at Clark Generating Station, entered into in February 2007. |
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 is expected to decrease in 2007 by approximately $1.3 million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date, the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006, SPR contributed a total of $16 million to meet its funding obligations under the plan. At the present time it is not expected that any additional funding will be required in 2007 to meet the minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA. However, SPR and the Utilities currently expect to contribute an amount similar to the 2006 funding. The amounts to be contributed may change subject to market conditions.
67
Financing Transactions
Pollution Control Refunding Revenue Bonds, Series 2006, 2006A and 2006B
In August 2006, on behalf of NPC, Clark County, Nevada (Clark County) issued $39.5 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due January 2036. On the same date, on behalf of NPC, Coconino County, Arizona Pollution Control Corporation (Coconino County) issued $40 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006A, due September 2032, and $13 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006B, due March 2039.
In connection with the issuance of these Bonds, NPC entered into financing agreements with Clark County and Coconino County, pursuant to which Clark County and Coconino County loaned the proceeds from the sales of the bonds to NPC. NPC’s payment obligations under the financing agreements are secured by NPC’s General and Refunding Mortgage Notes, Series P.
The interest rates of the Bonds were initially determined by an auction. The method of determining the interest rate on the Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following bonds, all of which were previously issued for the benefit of NPC:
| | • | | $39.5 million principal amount of 6.60% Clark County’s Pollution Control Refunding Revenue Bonds, Series 1992B, |
| |
| | • | | $20 million principal amount of 6.375% Coconino County’s Pollution Control Revenue Bonds, Series 1996, |
| |
| | • | | $20 million principal amount of 5.80% Coconino County’s Pollution Control Revenue Bonds, Series 1997B, and |
| |
| | • | | $13 million principal amount of 5.35% Coconino County’s Pollution Control Refunding Revenue Bonds, Series 1995E. |
General and Refunding Mortgage Notes, Series O
On May 12, 2006, NPC issued and sold $250 million in aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018. The Series O Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:
| | • | | fund the early redemption of $78 million aggregate principal amounts of NPC’s 7.2% Industrial Development Revenue Bonds, Series 1992 C, due 2022, |
| |
| | • | | fund the early redemption, in June 2006, of approximately $72.2 million aggregate principal amount of NPC’s 7.75% Junior Subordinated Debentures due 2038 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred Securities of NVP Capital III, a wholly-owned subsidiary of NPC), |
| |
| | • | | repay amounts outstanding under NPC’s revolving credit facility. |
In June 2006, NPC issued an additional $75 million in aggregate principal amount of its 6.5% General and Refunding Mortgage Notes, Series O, as part of the same series as the original Series O Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018, outstanding is $325 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $120 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036 (described below) were used to pay the total consideration for the tender offer for the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series N
In April 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage Notes, Series N, due April 2036. The Series N Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:
| | • | | fund the early redemption of $35 million aggregate principal amount of NPC’s 8.50% Series Z First Mortgage Bonds due 2023 plus approximately $1 million of associated redemption premiums, |
| |
| | • | | fund the early redemption of $105 million aggregate principal amount of 6.70% Industrial Development Revenue Bonds, due 2022, and |
| |
| | • | | fund the early redemption of approximately $122.5 million aggregate principal amount of NPC’s 8.20% Junior Subordinated Debentures due 2037 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I, a wholly-owned subsidiary of NPC). |
68
In June 2006, NPC issued an additional $120 million in aggregate principal amount of its 6.65% General and Refunding Mortgage Notes, Series N, as part of the same series as the original Series N Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due 2036, outstanding is $370 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $75 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018 (described above) were used to pay the total consideration for the tender offer on the 10.875% General and Refunding Mortgage Notes, Series E, described below.
Tender Offer for General and Refunding Mortgage Notes, Series E
In June 2006, NPC commenced a tender offer for all of its 10.875% General and Refunding Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of holders of a majority in aggregate principal amount of the Series E Notes to eliminate substantially all of the restrictive covenants contained in the officer’s certificate governing the Series E Notes. Approximately $150 million of $162.5 million Series E Notes outstanding were validly tendered and accepted by NPC. Those holders who tendered the Series E Notes and delivered their consents by June 2006 were entitled to receive a consent payment of $30 per $1,000 principal amount of Series E Notes, plus tender consideration for each $1,000 principal amount of Series E Notes validly tendered. Those holders who tendered the Series E Notes after June 14, 2006, but prior to June 28, 2006, were entitled to receive the tender consideration only. This tender consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 2006 settlement date per $1,000 principal amount of the Series E Notes tendered. Proceeds from the June 2006 issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer. The total consideration (including the consent payment and accrued interest) paid in June 2006 was approximately $163.6 million. In October 2006, NPC redeemed the remaining $12.6 million aggregate principal amount of the Series E Notes, plus accrued interest, using available cash on hand.
Revolving Credit Facility
In April 2006, NPC increased the size of its second amended and restated revolving credit facility expiring 2010 to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2006, NPC had $55 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of February 23, 2007, NPC had $48.7 million of letters of credit outstanding and $75 million borrowed under the revolving credit facility.
The NPC Credit Agreement contains two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2006, NPC was in compliance with these covenants.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.
General and Refunding Mortgage Notes, Series M
In January 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 2016. The Series M Notes were issued with registration rights. In February 2006 the net proceeds of the issuance plus available cash were used to repay $210 million of amounts outstanding under NPC’s revolving credit facility, which were borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Generating Facility.
Discharge of NPC’s First Mortgage Indenture
In August 2006, following the refunding of the $39.5 million aggregate principal amount of Pollution Control Refunding Revenue Bonds (PCRBs), Series 1992B, (see above) the first mortgage bonds which secured the PCRBs were retired.
In August 2006, NPC exchanged $115 million in aggregate principal amount of First Mortgage Bonds, Series BB and Series CC, for $115 million in aggregate principal amount of General and Refunding Mortgage Bonds, Series Q. The first mortgage bonds had been issued as security for the $100 million Clark County, Nevada Industrial Development Refunding Revenue Bonds, Series 2000A, and the $15 million Clark County, Nevada Pollution Control Refunding Revenue Bonds, Series 2000B.
With the conclusion of these two transactions, all of the bonds outstanding under the First Mortgage Indenture were retired as of August 2006. Upon the satisfaction and discharge of the First Mortgage Indenture in September 2006, NPC’s General and
69
Refunding Mortgage Indenture, dated as of May 1, 2001, with the Bank of New York as Trustee, became the first priority lien on substantially all of NPC’s utility property in Nevada.
Factors Affecting Liquidity
Limitations on Indebtedness
Certain factors impact NPC’s ability to issue debt:
| | 1. | | Financing Authority from the PUCN. In February 2006, NPC received PUCN authorization to enter into financings of $1.78 billion, which amount included $600 million for the revolving credit facility (described above). NPC has issued approximately $100 million of the new debt authorized under the PUCN Order. NPC’s only remaining authority under this PUCN Order allows NPC to refinance its existing debt and to use its $600 million revolving credit facility. |
| |
| | 2. | | Limits on Bondable Property. To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under its General and Refunding Mortgage Indenture. As of December 31, 2006, NPC had the capacity to issue $672 million of General and Refunding Mortgage Securities. |
| |
| | 3. | | Financial Covenants in its and SPR’s financing agreements. The terms of certain SPR debt further prohibit NPC and SPPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of NPC’s Series G Notes, which mature in 2013, NPC’s Series I Notes, which mature in 2012, NPC’s Series L Notes, which mature in 2015, and NPC’s Second Amended and Restated Revolving Credit Facility restrict NPC from incurring any additional indebtedness unless certain covenants are satisfied (See Note 8, Debt Covenant and Other Restrictions). If NPC’s Series G Notes, Series I Notes, or the Series L Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of securities remains investment grade. |
As of December 31, 2006, the financial covenants under the revolving credit facility, which are more restrictive than the Series G, I and L Notes restrictions, would allow NPC to issue up to $2.1 billion of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, of $2.1 billion as of December 31, 2006. However, since NPC currently has no PUCN authority to issue new debt, NPC is limited to borrowing under its credit facility. As of February 23, 2007, the balance available under the credit facility is $476.3 million.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.1 billion, depending on the Utilities’ combined usage of their respective revolving credit facilities at the time of the covenant calculation.
Limitations on Ability to Issue General and Refunding Mortgage Bonds
As of December 31, 2006, $2.7 billion of NPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (2) above under “Limitations on Indebtedness”, additional securities may be issued under the General and Refunding Mortgage Indenture as of December 31, 2006. That amount is determined on the basis of:
| | 1. | | 70% of net utility property additions |
| |
| | 2. | | the principal amount of retired General and Refunding Mortgage Securities, and/or |
| |
| | 3. | | the principal amount of first mortgage bonds retired after October 2001. |
NPC also has the ability to release property from the lien of the General and Refunding Mortgage Indenture 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 securities issuable under that indenture.
70
Credit Ratings
NPC is rated by four Nationally Recognized Statistical Rating Organizations, S&P, Moody’s, Fitch, and DBRS. As of February 23, 2007, the ratings are as follows:
| | | | | | | | | | | |
| | | | | Rating Agency |
| | | | | DBRS | | Fitch | | Moody’s | | S&P |
| NPC | | Sr.Secured Debt | | BBB (low)* | | BBB-* | | Bal | | BB+ |
| NPC | | Sr.Unsecured Debt | | Not rated | | BB | | Not rated | | B |
| | |
| * | | Ratings are investment grade |
In February 2007, DBRS, who had not previously issued ratings on the NPC, assigned new ratings to NPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for NPC is Stable.
In 2006, there were other changes to the ratings of NPC’s debt. Fitch upgraded the ratings for NPC’s senior secured debt to BBB-, the minimum level for investment grade. The senior unsecured debt for NPC was upgraded from BB- to BB, which is still non-investment grade. Fitch revised the rating outlook for NPC from Positive to Stable. S&P upgraded the ratings of NPC’s senior secured debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its ratings for NPC’s senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Energy Supplier Issues
With respect to NPC’s contracts for purchased power, NPC purchases and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that NPC is 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 request adequate financial assurance, which, if not provided within three 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 three 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 December 31, 2006 for all suppliers continuing to provide power under a WSPP agreement would approximate a $55.8 million payment by NPC. These contracts qualify for the normal purchases scope exception of SFAS No. 133, and as such, are not required to be marked to market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. 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. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, four counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utility to provide collateral to continue receiving service. To date, a letter of credit has been provided to one of NPC’s gas transporters.
Cross Default Provisions
None of the financing agreements of NPC contain a cross-default provision that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC 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 such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.
71
SIERRA PACIFIC POWER COMPANY
RESULTS OF OPERATIONS
SPPC recognized net income of $57.7 million for the year ended December 31, 2006 compared to net income of $52.1 million in 2005 and a net income of $18.6 million in 2004. SPPC’s operating results for 2005 improved over 2004 primarily by the absence of the $47 million charge associated with the Piñon Pine power plant project, consisting of an approximate $43 million disallowance and a $4 million impairment charge. In January 2006, the Second Judicial District Court of the State of Nevada vacated and remanded back to the PUCN for further review as to whether the costs associated with the Piñon Pine power plant project were justly and reasonably incurred. The case remains at the PUCN for review. See Note 13, Commitments and Contingencies for further discussion of the case.
In 2006, SPPC paid $17.9 million in dividends to SPR and declared an additional $6.7 million dividend. In January 2007, SPPC paid the $6.7 million dividend to SPR. In 2005, SPPC declared and paid $23.9 million in common dividends to its parent SPR and declared and paid $3.9 million in dividends to holders of its preferred stock.
Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.
SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every two years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.
72
The components of gross margin for the years ended December 31 (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | 2006 | | | Prior Year | | | 2005 | | | Prior Year | | | 2004 | |
| Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 1,020,162 | | | | 5.5 | % | | $ | 967,427 | | | | 9.7 | % | | $ | 881,908 | |
| Gas | | | 210,068 | | | | 17.8 | % | | | 178,270 | | | | 15.9 | % | | | 153,752 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 1,230,230 | | | | 7.4 | % | | $ | 1,145,697 | | | | 10.6 | % | | $ | 1,035,660 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Energy Costs: | | | | | | | | | | | | | | | | | | | | |
| Purchased power | | $ | 344,590 | | | | -2.1 | % | | $ | 352,098 | | | | 15.5 | % | | $ | 304,955 | |
| Fuel for power generation | | | 247,626 | | | | 6.0 | % | | | 233,653 | | | | 4.3 | % | | | 224,074 | |
| Gas purchased for resale | | | 160,739 | | | | 14.1 | % | | | 140,850 | | | | 15.9 | % | | | 121,526 | |
| Deferral of energy costs-electric-net | | | 47,043 | | | | 480.1 | % | | | 8,110 | | | | 14.9 | % | | | 7,060 | |
| Deferral of energy costs-gas-net | | | 6,947 | | | | -1027.5 | % | | | (749 | ) | | | -81.9 | % | | | (4,136 | ) |
| | | | | | | | | | | | | | | | | | |
| | | $ | 806,945 | | | | 9.9 | % | | $ | 733,962 | | | | 12.3 | % | | $ | 653,479 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Energy Costs by Segment: | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 639,259 | | | | 7.6 | % | | $ | 593,861 | | | | 10.8 | % | | $ | 536,089 | |
| Gas | | | 167,686 | | | | 19.7 | % | | | 140,101 | | | | 19.3 | % | | | 117,390 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 806,945 | | | | 9.9 | % | | $ | 733,962 | | | | 12.3 | % | | $ | 653,479 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Gross Margin by Segment: | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 380,903 | | | | 2.0 | % | | $ | 373,566 | | | | 8.0 | % | | $ | 345,819 | |
| Gas | | | 42,382 | | | | 11.0 | % | | | 38,169 | | | | 5.0 | % | | | 36,362 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 423,285 | | | | 2.8 | % | | $ | 411,735 | | | | 7.7 | % | | $ | 382,181 | |
| | | | | | | | | | | | | | | | | | |
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
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | Amount | | | Prior year | | | Amount | | | Prior year | | | Amount | |
Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 319,140 | | | | 12.9 | % | | $ | 282,655 | | | | 13.4 | % | | $ | 249,287 | |
| Commercial | | | 370,617 | | | | 13.9 | % | | | 325,456 | | | | 10.3 | % | | | 294,956 | |
| Industrial | | | 299,163 | | | | -10.3 | % | | | 333,621 | | | | 12.8 | % | | | 295,882 | |
| | | | | | | | | | | | | | | | | | |
| Retail revenues | | | 988,920 | | | | 5.0 | % | | | 941,732 | | | | 12.1 | % | | | 840,125 | |
| Other | | | 31,242 | | | | 21.6 | % | | | 25,695 | | | | -38.5 | % | | | 41,783 | |
| | | | | | | | | | | | | | | | | | |
Total Revenues | | $ | 1,020,162 | | | | 5.5 | % | | $ | 967,427 | | | | 9.7 | % | | $ | 881,908 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of megawatt-hours (MWh) | | | 8,711 | | | | -5.7 | % | | | 9,234 | | | | 1.0 | % | | | 9,143 | |
| | | | | | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | | $ | 113.53 | | | | 11.3 | % | | $ | 101.99 | | | | 11.0 | % | | $ | 91.89 | |
SPPC’s retail revenues increased in 2006 as compared to 2005 primarily due to increases in retail rates and to a lesser extent customer growth. Retail rates increased as a result of SPPC’s various BTER and deferred energy cases. (Refer to “Regulatory Proceedings”). The number of residential, commercial and industrial customers increased (2.8%, 3.0% and 2.1% respectively). These increases were offset by lower industrial energy revenues and MWh’s as a result of SPPC’s large industrial customer, Barrick Gold, moving to distribution-only services effective December 1, 2005.
On December 1, 2006, SPPC filed its annual deferred energy filing and an application to request recovery of deferred legal and settlement costs incurred for terminated power contracts executed during the Western Energy Crisis. If approved by the PUCN,
73
the overall effect of both filings would be a slight decrease in rates. SPPC requested that the rates become effective on July 1, 2007. For further discussion on the various cases see Regulatory Proceedings, later.
SPPC’s retail revenues increased in 2005 as compared to 2004 due to increased rates and customer growth. Customer rates for Nevada increased due to SPPC’s 2003 General Rate Case and various deferred energy and BTER energy cases and an increase in California customer rates effective December 1, 2004 and September 1, 2005. For further discussion of rate cases see Note 3, Regulatory Actions of Notes to Financial Statements. Growth in residential and commercial customers (3.1% and 3.5%, respectively) also contributed to the increase. Additionally, contributing to the increase was the recognition in December 2005 of $12 million in DEAA revenues as a result of Barrick’s transition to distribution only services effective December 1, 2005, offset by lower BTER revenues.
The increase in Electric Operating Revenues — Other in 2006 compared to 2005, was primarily due to the amortization of impact charges and increased wheeling revenues resulting from Barrick becoming a distribution-only services customer.
The decrease in Electric Operating Revenues — Other in 2005 compared to 2004, was primarily due to certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power.
Gas Operating Revenues
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change | | | | | | | Change | | | | |
| | | | | | | from Prior | | | | | | | from Prior | | | | |
| | | Amount | | | year | | | Amount | | | year | | | Amount | |
Gas Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 120,734 | | | | 25.4 | % | | $ | 96,292 | | | | 18.5 | % | | $ | 81,262 | |
| Commercial | | | 54,316 | | | | 22.6 | % | | | 44,286 | | | | 13.5 | % | | | 39,019 | |
| Industrial | | | 20,509 | | | | 21.0 | % | | | 16,953 | | | | 37.4 | % | | | 12,336 | |
| | | | | | | | | | | | | | | | | | |
| Retail revenues | | | 195,559 | | | | 24.1 | % | | | 157,531 | | | | 18.8 | % | | | 132,617 | |
| Wholesale | | | 11,650 | | | | -34.5 | % | | | 17,786 | | | | -1.9 | % | | | 18,122 | |
| Miscellaneous | | | 2,859 | | | | -3.2 | % | | | 2,953 | | | | -2.0 | % | | | 3,013 | |
| | | | | | | | | | | | | | | | | | |
Total Revenues | | $ | 210,068 | | | | 17.8 | % | | $ | 178,270 | | | | 15.9 | % | | $ | 153,752 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of decatherms | | | 15,058 | | | | 1.6 | % | | | 14,819 | | | | 6.6 | % | | | 13,896 | |
| | | | | | | | | | | | | | | | | | | | | |
| Average retail revenues per decatherm | | $ | 12.99 | | | | 22.2 | % | | $ | 10.63 | | | | 11.4 | % | | $ | 9.54 | |
SPPC’s retail gas revenues increased in 2006 compared to 2005 primarily due to increases in customer rates and customer growth. Retail rates increased as a result of SPPC’s various general, energy and deferred energy rate cases (refer to “Regulatory Proceedings”). The number of residential, commercial and industrial customers increased (4.3%, 3.7% and 16.7%, respectively).
SPPC’s retail gas revenues increased in 2005 compared to 2004 primarily due to increases in Nevada customer rates, customer growth and weather. Customer rates increased as a result of SPPC’s Purchased Gas Adjustment filings effective November 2004, and SPPC’s Gas Deferred Energy Rate case and BTER Update effective November 2005 (refer to Note 3, Regulatory Actions of Notes to Financial Statements). Customer growth increased as a result of an increase in the number of residential, commercial, and industrial customers (4.3%, 3.5% and 15.9%, respectively). Weather contributed to the increase in revenues with colder temperatures in the winter and spring, partially offset by warmer temperatures in the fall.
The wholesale revenues for 2006 decreased compared to prior year 2005 primarily due to decreased availability of gas for wholesale sales.
Wholesale and miscellaneous gas revenues for 2005 were consistent with the prior year.
74
Purchased Power
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior Year | | Amount | | Prior Year | | Amount |
Purchased Power | | $ | 344,590 | | | | -2.1 | % | | $ | 352,098 | | | | 15.5 | % | | $ | 304,955 | |
| | | | | | | | | | | | | | | | | | | | | |
| Purchased power in thousands of MWh | | | 5,334 | | | | -2.0 | % | | | 5,441 | | | | -4.9 | % | | | 5,719 | |
| | | | | | | | | | | | | | | | | | | | | |
| Average cost per MWh of Purchased power | | $ | 64.60 | | | | -0.2 | % | | $ | 64.71 | | | | 21.4 | % | | $ | 53.32 | |
SPPC’s purchased power costs decreased in 2006 compared to 2005 primarily due to a decrease in volume associated with the loss of Barrick, which transitioned to distribution only services.
Purchased power costs increased in 2005 compared to 2004, due to higher prices. SPPC’s energy contracts calculate prices using gas indexes; therefore, higher natural gas prices in 2005 increased the price of purchased power. Overall volumes for 2005 were lower than 2004 due to certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power and because purchases associated with risk management activities, which are included in purchased power, decreased in 2005.
Fuel for Power Generation
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior year | | Amount | | Prior year | | Amount |
Fuel for Power Generation | | $ | 247,626 | | | | 6.0 | % | | $ | 233,653 | | | | 4.3 | % | | $ | 224,074 | |
| | | | | | | | | | | | | | | | | | | | | |
| Thousands of MWh generated | | | 4,059 | | | | -7.3 | % | | | 4,379 | | | | -4.9 | % | | | 4,605 | |
| Average fuel cost per MWh of Generated Power | | $ | 61.01 | | | | 14.3 | % | | $ | 53.36 | | | | 9.7 | % | | $ | 48.66 | |
Fuel for power generation and the average fuel cost per MWh increased in 2006 compared to 2005. The increase is primarily due to hedging instruments which were purchased during the period when gas prices were escalating as a result of the 2005 hurricanes in the southern United States. The settlement of these instruments negatively impacted the average cost per MWH as natural gas prices were decreasing in 2006. The settlements of hedging instruments in the fourth quarter of 2005 partially offset the gas cost in 2005. MWh generated decreased as compared to 2005 primarily due to Barrick, which transitioned to distribution-only service in 2006.
Fuel for power generation costs increased in 2005 as compared to 2004 due to increases in natural gas and coal prices. However, the natural gas cost increases were partially offset by SPPC’s hedging strategies, as discussed in Energy Supply (Utilities). The decrease in the volume of generation was primarily due to SPPC relying more on purchased power to satisfy its native load requirements.
Gas Purchased for Resale
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior year | | Amount | | Prior year | | Amount |
| Gas Purchased for Resale | | $ | 160,739 | | | | 14.1 | % | | $ | 140,850 | | | | 15.9 | % | | $ | 121,526 | |
| | | | | | | | | | | | | | | | | | | | | |
| Gas Purchased for Resale (in thousands of decatherms) | | | 17,491 | | | | 5.4 | % | | | 16,592 | | | | -6.1 | % | | | 17,673 | |
| | | | | | | | | | | | | | | | | | | | | |
| Average Cost per decatherm | | $ | 9.19 | | | | 8.2 | % | | $ | 8.49 | | | | 23.4 | % | | $ | 6.88 | |
The cost of gas purchased for resale and average cost per decatherm increased in 2006 as compared to 2005. The increase is primarily due to hedging instruments which were purchased during the period when gas prices were escalating as a result of the 2005 hurricanes in the southern United States. The settlement of these instruments negatively impacted the average cost per decatherm as
75
natural gas prices were decreasing in 2006. The volume of gas purchased for resale increased primarily due to the colder winter weather during the fourth quarter of 2006.
The cost of gas purchased for resale increased in 2005 as compared to 2004 due to increases in natural gas prices. The volume of gas purchased for resale decreased during this period due to the fuel forecast more closely matching usage, leaving less fuel available for wholesale sales. This decrease in volume of gas was partially offset by the increase in demand for gas for resale during the first two quarters of 2005 due to colder winter weather.
Deferral of Energy Costs — Net
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | Amount | | | Prior year | | | Amount | | | Prior year | | | Amount | |
| Deferred energy costs — electric — net | | $ | 47,043 | | | | N/A | | | $ | 8,110 | | | | 14.9 | % | | $ | 7,060 | |
| Deferred energy costs — gas — net | | | 6,947 | | | | N/A | | | | (749 | ) | | | -81.9 | % | | | (4,136 | ) |
| | | | | | | | | | | | | | | | | | |
| Total | | $ | 53,990 | | | | | | | $ | 7,361 | | | | | | | $ | 2,924 | |
| | | | | | | | | | | | | | | | | | |
Deferred energy — costs — net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy costs - - net also includes the current amortization of fuel and purchased power costs previously deferred.
Deferred energy costs — electric — net for 2006, 2005 and 2004 reflect amortization of deferred energy costs of $46.3 million, $56.7 million and $37.0 million, respectively; and an over-collection of amounts recoverable in rates of $0.7 million in 2006 and an under-collection of $48.6 million and $29.9 million in 2005 and 2004, respectively. See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of Notes to Financial Statements for further detail of deferred energy balances.
Deferred energy costs — gas — net for 2006, 2005 and 2004 reflect amortization of deferred energy costs of $6.3 million, $1.5 million and $3.3 million, respectively; and an over-collection of amounts recoverable in rates of $0.6 million in 2006 and an under-collection in 2005 and 2004 of $2.3 million and $7.4 million, respectively.
Allowance for Funds Used During Construction (AFUDC)
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Change from | | | | | | | Change from | | | | |
| | | Amount | | | Prior year | | | Amount | | | Prior year | | | Amount | |
| Allowance for other funds used during construction | | $ | 6,471 | | | | 294.8 | % | | $ | 1,639 | | | | -4.6 | % | | $ | 1,718 | |
| | | | | | | | | | | | | | | | | | | | | |
| Allowance for borrowed funds used during construction | | | 5,505 | | | | 266.0 | % | | | 1,504 | | | | -47.2 | % | | | 2,849 | |
| | | | | | | | | | | | | | | | | | |
| | | $ | 11,976 | | | | 281.0 | % | | $ | 3,143 | | | | -31.2 | % | | $ | 4,567 | |
| | | | | | | | | | | | | | | | | | |
AFUDC for SPPC is higher in 2006 compared to 2005 due to an increase in the average Construction Work-In-Progress (CWIP) balance on which AFUDC is calculated due to the expansion of the Tracy Generating Station which started in late 2005.
AFUDC is lower in 2005 compared to 2004 due to a decrease in the average CWIP balance, primary as a result from the completion in May 2004 of the 3 year Falcon-Gonder 345KV Transmission Line project.
76
Other (Income) and Expenses
| | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 |
| | | | | | | Change from | | | | | | Change from | | |
| | | Amount | | Prior year | | Amount | | Prior year | | Amount |
| Other operating expense | | $ | 141,350 | | | | 7.2 | % | | $ | 131,901 | | | | 3.0 | % | | $ | 128,091 | |
| Maintenance expense | | $ | 31,273 | | | | 17.2 | % | | $ | 26,690 | | | | 22.0 | % | | $ | 21,877 | |
| Depreciation and amortization | | $ | 87,279 | | | | -3.6 | % | | $ | 90,569 | | | | 4.3 | % | | $ | 86,806 | |
| Interest charges on long-term debt | | $ | 71,869 | | | | 3.8 | % | | $ | 69,240 | | | | -2.9 | % | | $ | 71,312 | |
| Interest for energy suppliers | | $ | — | | | | N/A | | | $ | (2,396 | ) | | | -78.2 | % | | $ | (10,999 | ) |
| Interest charges-other | | $ | 5,142 | | | | 38.0 | % | | $ | 3,727 | | | | -30.6 | % | | $ | 5,367 | |
| Interest accrued on deferred energy | | $ | (5,996 | ) | | | -15.5 | % | | $ | (7,092 | ) | | | 38.2 | % | | $ | (5,133 | ) |
| Other income | | $ | (9,412 | ) | | | 58.5 | % | | $ | (5,940 | ) | | | 74.4 | % | | $ | (3,406 | ) |
| Disallowed merger costs | | $ | — | | | | N/A | | | $ | — | | | | N/A | | | $ | 1,929 | |
| Plant costs disallowed | | $ | — | | | | N/A | | | $ | — | | | | N/A | | | $ | 47,092 | |
| Other expense | | $ | 8,422 | | | | 12.4 | % | | $ | 7,493 | | | | 30.9 | % | | $ | 5,726 | |
Other operating expense increased for 2006 compared to 2005 due to increased amortization of regulatory assets resulting from SPPC’s GRC, as discussed in Regulatory Proceedings. Also contributing to the increase was the recovery in 2005 of a claim against Pacific Gas and Electric; partially offset by Enron legal fees incurred in 2005.
Other operating expense increased for 2005 compared to 2004 primarily due to severance costs associated with the reorganization of SPPC, NPC and SPR.
The increase in Maintenance expense for 2006 compared to 2005 is primarily due to higher costs for scheduled maintenance and forced outages in 2006 at Ft. Churchill and Valmy; partially offset by a 2006 planned major outage at Tracy that was rescheduled to 2007.
The increase in Maintenance expense for 2005 compared to 2004 is primarily due to the timing of scheduled and unscheduled plant maintenance at Valmy.
Depreciation and amortization were lower in 2006 than 2005 due to the change in depreciation rates as ordered by PUCN in SPPC’s General Electric and Gas Rate Case. For further information on SPPC’s General and Electric Rate Case see Regulatory Proceedings, later.
Depreciation and amortization were higher in 2005 than 2004 due to an increase in plant-in-service from regular system growth.
SPPC’s interest charges on Long-Term Debt for the year ended December 31, 2006 increased from 2005 due primarily to interest on the $300 million Series M Notes issued in March 2006, partially offset by debt redemptions in 2006 of $188 million, and the refinancing of $268 million of tax exempt debt from fixed rate to variable in November 2006. SPPC’s interest charges on Long-Term Debt for the year ended December 31, 2005 decreased from 2004 as a result of the reduction in interest rate during 2004 associated with the replacement of its 10.5% $100 million term loan facility with 6.25% $100 million Series H Notes, and a reduction in interest rate in April 2004, of SPPC’s $80 million Washoe Water Bonds from 7.5% to 5.0%. See Note 6, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt.
SPPC’s interest charges for energy suppliers for the year ended December 31, 2005 reflects the reversal of interest of $3.2 million resulting from the November 2005 settlement agreement between the Utilities and Enron. SPPC’s Interest charges for energy suppliers for the year ended December 31, 2004 reflects the reversal of interest of $12.3 million resulting from a December 2004 ruling by the U.S. District Court that lowered the interest rate previously accrued. See Note 13, Commitments and Contingencies, of the Notes to Financial Statements, for more information regarding the Enron litigation.
SPPC’s interest charges-other for the year ended December 31, 2006 increased compared to the same period in 2005 primarily due to higher amortization of debt issuance costs related to new debt issuances. See Financing Transactions. SPPC’s Interest charges-other for the year ended December 31, 2005 decreased compared to the same period in 2004 due primarily to the absence of charges related to the accounts receivable facility and short-term debt.
SPPC’s interest accrued on deferred energy costs for the year ended December 31, 2006, was lower than the same period in 2005 due primarily to lower deferred energy balances during 2006, when compared to the same period in 2005. Interest accrued on deferred energy costs for the year ended December 31, 2005, was higher than the same period in 2004 due to higher deferred fuel and
77
purchased power balances and carrying charge rates during 2005. See Note 3, Regulatory Actions of the Notes to Financial Statements for further discussion of deferred energy accounting issues.
SPPC’s other income increased for the year ended December 31, 2006, compared to the same period in 2005 primarily due to an increase in interest income associated with higher cash balances from the issuance of new debt in March 2006, as well as gains from the sale of property. SPPC’s other income increased for the year ended December 31, 2005, compared to the same period in 2004 due primarily to an increase in interest income.
Disallowed merger costs expense includes the 2004 write-off of costs that resulted from the July 1999 merger between SPR and NPC, allocable to non-Nevada jurisdictional electricity sales, which were determined not to be recoverable in future rates.
SPPC’s plant costs disallowed is the result of the decision by the PUCN to disallow recovery of a portion of the costs associated with the Piñon Pine power plant project. See Note 3, Regulatory Actions and Note 13, Commitments and Contingencies of the Notes to Financial Statements, for details.
SPPC’s other expense for the year ended December 31, 2006 increased from the same period in 2005, due primarily to a loss on the disposition of property, higher donations, assistance program expenses, and penalties. SPPC’s other expense for the year ended December 31, 2005 increased from the same period in 2004. Higher expense was recognized during 2005 related to SPPC’s California Restructure Implementation costs of approximately $1 million that were disallowed by the CPUC.
ANALYSIS OF CASH FLOWS
SPPC’s cash flows decreased slightly during the year ended December 31, 2006, when compared to the same period in 2005, as a result of an increase in cash used by investing activities offset by an increase in cash from operating and financing activities.
Cash used by investing activities increased primarily as a result of the expansion of the Tracy plant during the year ended December 31, 2006, compared to the same period in 2005.
At various times during the year ended December 31, 2006, SPPC borrowed approximately $248 million under its revolving credit facility, all of which was repaid during 2006. SPPC also issued $300 million in 6.0% General and Refunding Mortgage Notes, Series M and $268 million in variable interest Pollution Control Revenue Bonds. A portion of the draw on the credit line was used to retire approximately $198 million of SPPC’s Medium Term Notes Series A, B and C. The net proceeds of the $300 million offering were used to pay off amounts borrowed under the revolving credit facility, redeem $20 million of Medium Term Notes, Series C, redeem $50 million of preferred stock and pay associated costs, premiums and dividends. Proceeds from Pollution Control Bonds and cash from operations were used to retire $269 million of SPPC’s existing tax-exempt bonds. In 2006, SPPC paid dividends to SPR of approximately $17.9 million and received a capital contribution of $75 million from SPR.
Cash from operating activities were higher in 2006 mainly due to the settlement of balances outstanding for tax sharing agreements, a reduction in prepayments for energy and increases in general and energy rates, offset by the settlement with Enron during the first quarter.
SPPC’s cash flows increased during the year ended December 31, 2005, when compared to the same period in 2004, as a result of an increase in cash flows from operating activities partially offset by increases in cash used in investing and financing activities. Cash flows from operating activities were higher in 2005 due to rate increases that became effective in the second quarter of 2004, which was the result of SPPC’s General and Deferred Rate Cases (refer to “Regulatory Proceedings”). Also causing an increase in cash flow from operations was the $11 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility and changes in accounts receivables for tax sharing agreements, offset by energy costs being higher than amounts recovered in rates in 2005. Cash flows used in investing activities increased primarily as a result of construction activity related to growth. Cash used for financing activities increased due to payment of dividends to the parent in 2005, offset by the payoff of the short-term credit facility in 2004.
78
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows are electric and gas revenues, including the recovery of previously deferred energy and gas costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and the payment of interest on SPPC’s outstanding indebtedness.
| | | | | |
| Available Liquidity as of December 31, 2006 (in millions) | |
| | | SPPC | |
| Cash and Cash Equivalents | | $ | 53.3 | |
| Balance available on Revolving Credit Facility | | | 340.6 | |
| | | | | |
| | | | |
Total Available Liquidity1 | | $ | 393.9 | |
| | | | |
| |
| 1 | As of February 23, 2007, SPPC had approximately $331.1 million available under its revolving credit facility. Additionally, if necessary, SPPC has the ability to issue additional debt, as discussed under Limitations on Indebtedness. |
In December 2006, SPR contributed capital to SPPC of approximately $75 million. SPPC used the proceeds to repay indebtedness under its revolving credit facility, and for general corporate purposes. There were no other capital contributions from SPR to SPPC in 2006.
In 2006, SPPC had paid $17.9 million in dividends to SPR and declared an additional $6.7 million dividend. In January 2007, SPPC paid the $6.7 million dividend to SPR.
SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, SPPC may be required to meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility, and if necessary, the issuance of long-term debt and/or capital contribution from SPR.
SPPC’s overall liquidity continued to improve in 2006. The revolving credit facility was increased to $350 million in April, 2006, providing $100 million of additional liquidity for increased commodity prices. SPPC’s debt profile improved as a result of refinancing more than $536 million of long-term debt. These refinancings are expected to reduce future interest expense.
SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.
Detailed below are SPPC’s Capital Structure, Capital Requirements, Contractual Obligations, recently completed Financing Transactions and Factors Affecting Liquidity including SPPC’s ability to obtain debt on favorable terms and limitations on indebtedness.
Capital Structure
SPPC’s actual consolidated capital structure was as follows at December 31:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 |
| | | | | |
| Current Maturities of Long-Term Debt | | $ | 2,400 | | | | 0.1 | % | | $ | 52,400 | | | | 3.00 | % |
| Long-Term Debt | | | 1,070,858 | | | | 54.7 | % | | | 941,804 | | | | 53.1 | % |
| Preferred Stock | | | — | | | | | | | | 50,000 | | | | 2.8 | % |
| Common Equity | | | 884,737 | | | | 45.2 | % | | | 727,777 | | | | 41.1 | % |
| | | | | |
| Total | | $ | 1,957,995 | | | | 100.0 | % | | $ | 1,771,981 | | | | 100 | % |
| | | | | |
Capital Requirements
Construction Expenditures
SPPC’s cash construction expenditures are expected to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2006, 2005 and 2004 were approximately $285 million, $113 million and $104 million, respectively. SPPC’s cash construction expenditures for 2007 are projected to be $432.8 million. SPPC’s cash construction expenditures for 2007 through 2011 are projected to be $1.9 billion. To fund these capital projects SPPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the
79
issuance of long-term debt and/or capital contributions from SPR. Depending on the progress of the Ely Energy Center the timing and extent of the estimated capital expenditures necessary may change.
Contractual Obligations
The table below provides SPPC’s consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2006, 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payment Due by Period | |
| | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | Thereafter | | | Total | |
| Long-Term Debt Maturities | | $ | 2,400 | | | $ | 322,400 | | | $ | 80,600 | | | $ | — | | | $ | — | | | $ | 668,250 | | | $ | 1,073,650 | |
| Long-Term Debt Interest Payments | | | 61,979 | | | | 49,235 | | | | 38,386 | | | | 38,377 | | | | 38,377 | | | | 402,091 | | | | 628,445 | |
| Purchased Power | | | 163,165 | | | | 125,161 | | | | 98,028 | | | | 93,836 | | | | 95,231 | | | | 1,308,566 | | | | 1,883,987 | |
| Coal and Natural Gas | | | 201,068 | | | | 85,018 | | | | 73,392 | | | | 48,418 | | | | 48,418 | | | | 361,358 | | | | 817,672 | |
| Capital Purchase Agreements | | | 13,121 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 13,121 | |
| Operating Leases | | | 10,635 | | | | 10,297 | | | | 8,931 | | | | 7,587 | | | | 778 | | | | 36,587 | | | | 74,815 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Contractual Cash Obligations | | $ | 452,368 | | | $ | 592,111 | | | $ | 299,337 | | | $ | 188,218 | | | $ | 182,804 | | | $ | 2,776,852 | | | $ | 4,491,690 | |
| | | | | | | | | | | | | | | | | | | | | | |
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 is expected to decrease in 2007 by approximately $1.3 million compared to the 2006 cost of $30.6 million. As of September 30, 2006, the measurement date, the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2006, SPR contributed a total of $16 million to meet its funding obligations under the plan. At the present time it is not expected that any additional funding will be required in 2007 to meet the minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA. However, SPR and the Utilities currently expect to contribute an amount similar to the 2006 funding. The amounts to be contributed may change subject to market conditions.
Financing Transactions (SPPC)
Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C
In November 2006, on behalf of SPPC, Humboldt County, Nevada (Humboldt County) issued $49.75 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due October 2029. On the same date, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $58.7 million aggregate principal amount of it Gas Facilities Refunding Revenue Bonds, Series 2006A, due August 2031; $75 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2006B, due March 2036; and $84.8 million aggregate principal amount of its Gas and Water Facilities Refunding Revenue Bonds, Series 2006C, due March 2036.
In connection with the issuance of these Bonds, SPPC entered into financing agreements with Humboldt County and Washoe County, pursuant to which Humboldt County and Washoe County loaned the proceeds from the sales of the bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series N.
80
The interest rates of the Bonds were initially determined by an auction. The method of determining the interest rate on the Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following, all of which were previously issued for the benefit of SPPC:
| | • | | $17.5 million principal amount of 6.65% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $20 million principal amount of 6.55% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1990 |
| |
| | • | | $21.2 million principal amount of 6.70% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1992 |
| |
| | • | | $75 million principal amount of 6.65% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $45 million principal amount of 6.30% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $30 million principal amount of 5.90% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1993B |
| |
| | • | | $9.8 million principal amount of 5.90% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1993A |
| |
| | • | | $39.5 million principal amount of 6.55% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $10.25 million principal amount of 6.30% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1992A |
Humboldt County Pollution Control Refunding Revenue Bonds
In October 2006, the 6.35% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1992B, due August 2022, in the amount of $1 million were redeemed at 100% of the stated principal amount, plus accrued interest.
Revolving Credit Facility
In April 2006, SPPC increased the size of its amended and restated revolving credit facility expiring 2010 to $350 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2006, SPPC had $9.4 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of February 23, 2007, SPPC had $18.9 million of letters of credit and had no amounts borrowed under the revolving credit facility.
The SPPC Credit Agreement contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2006, SPPC was in compliance with these covenants.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.
General and Refunding Mortgage Notes, Series M
In March 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage Notes, Series M, due May 15, 2016. The Series M Notes were issued with registration rights. Proceeds of the offering were used to repay $173 million borrowed under the revolving credit facility which was utilized to:
| | • | | fund the early redemption of $110 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022; |
| |
| | • | | fund the early redemption of $58 million aggregate principal amount of SPPC’s Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023; |
| |
| | • | | pay for maturing debt of $30 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.81% to 6.83% Series C Notes due 2006; and |
| |
| | • | | pay for $51 million in connection with the redemption of $50 million of SPPC’s Series A Preferred Stock (two million shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends to the redemption date of $.4875 per share). |
| |
| | • | | pay for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.62% to 6.65% Series C Notes due 2006. |
81
Discharge of SPPC’s First Mortgage Indenture
In November 2006, following the refunding of the $268.25 million aggregate principal amount of Pollution Control and Gas & Water Refunding Revenue Bonds (see Financing Transactions above), the first mortgage bonds which secured these revenue bonds were retired.
In November 2006, the remaining $20 million aggregate principal amount of Series C Medium Terms Notes matured. On that date, the first mortgage bonds which secured the Medium Term Notes were retired.
With the conclusion of these two transactions, all of the bonds outstanding under the First Mortgage Indenture were retired as of November 2006, and all filings necessary to make effective the release of the lien of the First Mortgage Indenture were completed as of January 2007. Upon the satisfaction and discharge of the First Mortgage Indenture, SPPC’s General and Refunding Mortgage Indenture, dated as of May 2001, with the Bank of New York as Trustee, became the first priority lien on substantially all of SPPC’s utility property in Nevada and California.
Factors Affecting Liquidity
Limitations on Indebtedness
Certain factors impact SPPC’s ability to issue debt:
| | 1. | | Financing Authority from the PUCN. In February 2006, SPPC received PUCN authorization to enter into financings of $1.36 billion which amount includes $350 million for the revolving credit facility (described above). SPPC has issued $21 million of the new debt authorized in the PUCN Order. SPPC’s remaining authority under this PUCN Order allows SPPC to use its $350 million revolving credit facility, to issue $349 million in new debt, and to refinance existing debt as specified in the order. |
| |
| | 2. | | Limits on Bondable Property. To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the General and Refunding Mortgage Indenture. As of December 31, 2006, SPPC has the capacity to issue $381 million of General and Refunding Mortgage Securities. |
| |
| | 3. | | Financial Covenants in its and SPR’s financing agreements. The terms of certain SPR debt further prohibit SPPC and NPC from incurring additional indebtedness unless certain conditions have been met. See SPR’s Limitations on Indebtedness for details of these restrictions. In addition to the SPR debt, the terms of SPPC’s Series H Notes and SPPC’s Amended and Restated Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless certain covenants are satisfied. See Note 8, Debt Covenant and Other Restrictions. |
As of December 31, 2006, the financial covenants under SPPC’s revolving credit facility, which are more restrictive than the Series H Notes restriction, would allow SPPC to issue up to $797 million of additional debt. The covenant limitations of certain SPR debt place a cap on additional indebtedness, on a consolidated basis, including SPPC and NPC, at $2.1 billion as of December 31, 2006.
Since SPR’s debt covenant limitations are calculated on a consolidated basis, SPR’s debt covenant limitations may allow for higher or lower borrowings than $2.1 billion, depending on the Utilities’ combined usage of their revolving credit facilities at the time of the covenant calculation.
Limitations on Ability to Issue General and Refunding Mortgage Bonds
SPPC’s General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of December 31, 2006, $1.4 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. As mentioned in (2) above under “Limitations on Indebtedness” additional securities may be issued under the General and Refunding Mortgage Indenture as of December 31, 2006. That amount has been determined on the basis of:
| | 1. | | 70% of net utility property additions; |
| |
| | 2. | | the principal amount of retired General and Refunding Mortgage Securities; and/or |
| |
| | 3. | | the principal amount of first mortgage bonds retired after October 2001. |
82
SPPC also has the ability to release property from the lien of the General and Refunding Mortgage Indenture 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 securities issuable under that indenture.
Credit Ratings
SPPC is rated by four Nationally Recognized Statistical Rating Organizations S&P, Moody’s, Fitch, and DBRS. As of February 23, 2007, the ratings are as follows:
| | | | | | | | | | | |
| | | | | Rating Agency |
| | | | | DBRS | | Fitch | | Moody’s | | S&P |
| SPPC | | Sr.Secured Debt | | BBB (low)* | | BBB-* | | Ba1 | | BB+ |
| | |
| * | | Ratings are investment grade |
In February 2007, DBRS, who had not previously issued ratings on SPPC, assigned new ratings to SPPC’s senior secured debt. The rating is BBB (low), which is the minimum level for investment grade. DBRS’s trend for SPPC is Stable.
In 2006, there were other changes to the ratings of SPPC’s debt. Fitch upgraded the ratings for SPPC’s senior secured debt to BBB-, the minimum level for investment grade, and revised the rating outlook for SPPC from Positive to Stable. S&P upgraded the ratings of SPPC’s senior secured debt from BB to BB+, one level below investment grade. Moody’s re-affirmed its ratings for SPPC’s senior secured debt at Ba1, one level below investment grade.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Energy Supplier Issues
With respect to SPPC’s contracts for purchased power, SPPC purchases and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that SPPC is 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 request adequate financial assurance, which, if not provided within three 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 three 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 December 31, 2006 for all suppliers continuing to provide power under a WSPP agreement would approximate a $44.5 million payment by SPPC. These contracts qualify for the normal purchases scope exception of SFAS No. 133, and as such, are not required to be marked to market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Issues
With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. 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. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, four counter-parties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utility to provide collateral to continue receiving service.
Cross Default Provisions
SPPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by SPPC upon an event of default by SPR or NPC under any of their respective financing agreements. Certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe
83
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 such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.
REGULATORY PROCEEDINGS (UTILITIES)
SPR is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, SPR and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain their books and records in accordance with Federal Energy Regulatory Commission (“FERC”) regulations and to make them available to the FERC, the Public Utilities Commission of Nevada (“PUCN”) and California Public Utility Commission (“CPUC”). In addition, the PUCN, CPUC, and the FERC have the authority to review the allocation of costs of non-power goods and administrative services among SPR and its subsidiaries. The FERC has the general authority to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between SPR, NPC and/or SPPC and/or any other affiliated company. SPR does not expect that the new PUHCA law or the regulations promulgated by the FERC will have a material impact on the company and how its public utility subsidiaries are regulated.
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 (“IRPs”) to the PUCN for approval.
Under federal law, the Utilities 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 the governmental commissions. The following regulatory proceedings have affected, or are expected to affect the utilities financial positions, results of operations and cash flows.
The Utilities are required to file annual periodic Deferred Energy Accounting Adjustment (DEAA) cases, annual Base Tariff Energy Rate (BTER) Updates and biennial General Rate Cases (GRCs) in Nevada. A DEAA case is filed to recover/refund any over/under collection of prior energy costs and the BTER update is to set rates to recover current energy costs. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital. As of December 31, 2006, NPC’s and SPPC’s balance sheet included approximately $488.9 million and $61.6 million, respectively, of deferred energy costs of which approximately $334.8 million and $33.7 million have been previously approved for collection over various periods. The remaining amounts will be requested in future regulatory filings. Refer to Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements.
The following summarizes pending and approved rate case applications filed in 2005, 2006 and 2007. Each of these rate cases, as well as other regulatory matters such as, the Utilities’ Integrated Resource Plans and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail within this section.
Pending Rate Cases
| | • | | NPC 2007 Deferred Energy Rate Case and BTER Update |
| | | | Application to create a new DEAA rate and to update the going forward BTER. In this application, NPC requests to decrease rates by $33.2 million, a decrease of 1.6% while recovering $75 million of deferred fuel and purchased power costs. NPC has requested the amortization to begin June 1, 2007 and to continue for a fourteen month period. |
| | • | | NPC 2007 Western Energy Crisis Rate Case |
Application to recover approximately $83.6 million in deferred legal and settlement costs incurred to resolve claims arising from the western energy crisis. This application requests an overall rate increase of 0.94% and to begin amortizing the costs over a four-year period beginning June 1, 2007.
In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the $83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to NPC’s 2001 Deferred Energy Case, discussed below. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
84
| | • | | NPC 2006 General Rate Case |
Application to reset General Rates. This legislatively mandated filing requests authorization to increase general rates by $172.4 million which is approximately an 8% increase. In this application, the Company requested that the Return on Equity (“ROE”) and Rate of Return (“ROR”) be set at 11.40% and 9.41%, respectively. NPC expects the new rates to be in effect on or before June 1, 2007.
In February 2007, NPC submitted its certification filing. This filing did not change the requested ROE, but the ROR decreased to 9.39% and the general revenue increase was lowered to $156.4 million.
| | • | | SPPC 2006 Nevada Electric Deferred Energy Rate Case and BTER Update |
Application to create a new electric DEAA rate and to update the electric BTER. In this application, SPPC requests to decrease rates by $7.9 million, a decrease of .86%, while recovering $18.7 million of deferred fuel and purchased power costs. SPPC is seeking recovery using a symmetrical two-year amortization period beginning July 1, 2007.
| | • | | SPPC 2006 Nevada Western Energy Crisis Rate Case |
Application to recover $22.6 million in deferred legal and settlement costs incurred to resolve claims arising from the western energy crisis. This application requests an overall rate increase of 0.53% and to begin amortizing the costs over a four-year period beginning July 1, 2007.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC further requests authority to recover carrying charges on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset established by the PUCN in a future application to change rates. The parties to the stipulation have requested that the PUCN issue an order by September 30, 2007.
Other Pending Matters
| | • | | NPC 2001 Deferred Energy Case |
In July 2006, the Supreme Court of Nevada issued a ruling that will allow NPC to recover approximately $180 million of deferred energy, which was disallowed in NPC’s 2001 Deferred Energy Case. The decision directs the District Court to remand the matter back to the PUCN to determine the appropriate rate schedule.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to the Western Energy Crisis, discussed above. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
Approved Rate Cases
| | • | | NPC 2006 Deferred Energy Rate Case and BTER Update |
Application to create a new DEAA rate and to update the going forward BTER. In April 2006, the PUCN approved a new BTER, which would increase purchased fuel and power revenues by an estimated $112 million. In June 2006, the PUCN approved a negotiated settlement of the deferred energy phase of the case, which, based on an updated forecast, reduced the previously approved BTER revenue by approximately $1.6 million and allowed full recovery of $171.5 million in deferred costs, with an effective date of May 1, 2006.
| | • | | SPPC 2006 Nevada Natural Gas and Propane Deferred Energy Rate Case and BTER Update |
Application to create a new DEAA rate and to update the BTER. In October 2006, the PUCN approved negotiated settlements to recover $1.1 million in deferred natural gas and propane costs and to set the going forward energy rates such that $1.3 million of new revenues would be collected. The settlements, combined with the expiration of a previous natural gas DEAA rate, will yield a 2.5% rate reduction for natural gas customers and a 3.3% increase for propane customers.
| | • | | SPPC 2005 Nevada Electric Deferred Energy Rate Case and BTER Update |
85
| | | | Application to create a new electric DEAA rate and to update the electric BTER. In April 2006, the PUCN approved a new Electric BTER, which will increase purchased fuel and power revenues by an estimated $31 million. In June 2006, the PUCN approved a negotiated settlement, which granted SPPC full recovery of $46.7 million in deferred costs during a two year period beginning July 2006. |
| | • | | SPPC 2005 Nevada Electric General Rate Case |
| | | | Application to reset electric general rates. In April, 2006, the PUCN authorized a 10.6% ROE and 8.96% ROR and ordered SPPC to reduce general revenues for electric services by approximately $14 million. |
| | • | | SPPC 2005 Nevada Gas General Rate Case |
| | | | Application to reset gas general rates. In April 2006, the PUCN authorized a 10.6% ROE and 7.98% ROR and ordered SPPC to increase general revenues for gas services by approximately $4.5 million. |
| | • | | SPPC 2006 California Energy Cost Adjustment Clause Rate Case |
| | | | Application to reset energy rates. The total request sought to collect an additional $11.2 million annually for deferred and going forward costs related to fuel and power purchases. The two requested rate increases total 16.5%. In October 2006, the CPUC approved the application as filed, with an effective date of November 1, 2006. |
| | • | | SPPC 2005 California General Rate Case |
| | | | Application to reset General Rates. In August 2006, the CPUC approved a settlement agreement, which beginning on September 2006, allowed SPPC to collect an estimated $4.1 million of additional general revenues. |
Nevada Matters
Nevada Power Company
2007 Deferred Energy Rate Case and BTER Update
In January 2007, NPC filed an electric DEAA rate case and BTER update application with the PUCN. The application seeks recovery of $75 million of deferred fuel and purchased power costs and requested to reset NPC’s going forward BTER to reflect anticipated changes in future energy costs. This application requests a 1.6% decrease in overall rates.
2007 Western Energy Crisis Rate Case
In January 2007, NPC filed an application to recover $83.6 million over four years in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the western energy crisis. This application requests an overall rate increase of less than 1%.
In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the $83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to NPC’s 2001 Deferred Energy Case, discussed below. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
2006 General Rate Case
In November 2006, NPC filed its statutorily required electric general rate case. This filing requests authorization to:
| | • | | Increase annual general revenues by $172.4 million which is approximately an 8% increase |
| |
| | • | | Set the Return on Equity and Rate of Return at 11.40% and 9.41%, respectively |
| |
| | • | | Recover 100% of the amortization of the 1999 NPC/SPPC merger costs rather than the 80% recovery that is currently in general rates |
| |
| | • | | Implement the PUCN’s previous orders regarding incentive ratemaking for the Chuck Lenzie Generating Station |
| |
| | • | | Implement new depreciation rates |
86
Hearings are scheduled to take place in late March and early April of 2007 with rates expected to be effective on or before June 1, 2007.
In February 2007, NPC submitted its certification filing which lowered the requested ROR to 9.39% and the general revenues increase was lowered to $156.4 million, representing an overall rate increase of 7.4%.
2006 Deferred Energy Rate Case and BTER Update
In January 2006, NPC filed an application with the PUCN seeking recovery of $171.5 million of deferred fuel and purchased power costs and to increase its going forward BTER to reflect anticipated changes in future energy costs. The application requests an overall rate increase of approximately 17%.
In April 2006, the PUCN approved an agreement among the interveners and NPC, which, effective May 1, 2006, set NPC’s BTER rates such that an estimated $112 million (revised by June 2006 DEAA agreement – see below) of new revenues would be collected for fuel and power purchases in addition to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the approximately $120 million increase represented an overall average rate increase of approximately 6.5%.
In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5 million of previously incurred purchased fuel and power costs over a one year period. In June 2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to the BTER approved in April 2006 based on an updated projection of costs and (2) granted NPC full recovery of the $171.5 million of deferred costs during a two year period beginning August 2006. However, the $171.5 million was reduced by a $16.5 million payment previously received by NPC in connection with the Lenzie acquisition. Under this agreement, the DEAA rate changes required to asymmetrically recover the deferred balance are scheduled to be implemented during a two year period such that they will be offset by the expiration of previously approved DEAA rates. As a result, no rate increase was required.
2001 Deferred Energy Case
In November 2001, NPC made a deferred energy filing with the PUCN seeking repayment 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 rate to repay 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.
In March 2002, the PUCN issued its Order on the 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. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.
In July 2006, the Supreme Court of Nevada issued a ruling that will allow NPC to recover approximately $180 million of deferred energy, which was disallowed in NPC’s 2001 Deferred Energy Case. The decision directs the District Court to remand the matter back to the PUCN to determine the appropriate rate schedule.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to the Western Energy Crisis, discussed above. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
2006 Integrated Resource Plan
In June 2006, NPC filed its 2006 triennial Integrated Resource Plan with the PUCN. The filing requested approval to develop new conventional and renewable generation resources, improve NPC’s transmission system and increase demand side initiatives. The demand side programs are intended to help customers use electricity more efficiently and also contribute to NPC’s Renewable Portfolio requirements. The following are the key elements of the filing:
| | • | | Requested approval to construct the following supply side resources: |
| | 1. | | Two 750 MW critical coal fired generation units at the proposed Ely Energy Center in White Pine County, Nevada estimated to be in service by 2011 and 2013 respectively. Also, part of this project is a 250-mile 500 kV transmission line to integrate the new generation into both NPC’s and SPPC’s systems and to allow delivery of geothermal resources from Northern Nevada to NPC and solar powered generation from Southern Nevada to SPPC. |
87
| | 2. | | Construction of 600 MW of gas fired combustion turbine peaking generation, 400 MW in service by 2008 and 200 MW in service by 2009. |
| | • | | Requested the PUCN to designate the Ely Energy Center and the 500kV transmission intertie as critical facilities under Nevada regulations and requested incentive ratemaking treatment including “CWIP in rate base” during construction and, upon completion, a 2% enhanced ROE and accumulation of depreciation expense in a regulatory asset account from the time the plants are placed in service until they are included in rates. |
| |
| | • | | Outlined initiatives, including NPC ownership positions in renewable energy projects, which are expected to enable NPC to meet Nevada’s Portfolio Standards. |
| |
| | • | | Requested approval of four new demand side programs and to increase spending on eight existing demand side programs. |
| |
| | • | | Outlined NPC’s ten-year $4.7 billion budget for all of the proposed initiatives. |
In September 2006, NPC provided testimony that modified its request for critical facility designations and associated incentive ratemaking treatments, which included the withdrawal of the following:
| | • | | Incentive ratemaking treatment for the initial $300 million project development costs. |
| |
| | • | | NPC’s request for a specific enhanced ROE in this docket; however, NPC stated it would resubmit a request for an enhanced ROE in a future filing. |
In October 2006 the PUCN approved a negotiated settlement of NPC’s 2007-2009 Energy Supply Plan, which was a component of its integrated resource plan filing.
In November 2006, the PUCN issued an order with the findings of that order listed below:
| | 1. | | PUCN granted the Utilities’ request to proceed with the development of Phase I of the Ely Energy Center and accompanying transmission line. The PUCN also approved the Utilities’ request of $300 million for development activities associated with the Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit. The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively. Furthermore, the PUCN granted NPC’s request for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date. |
| |
| | | | The PUCN also directed the Utilities, upon receipt of the air permit, to prepare and submit a subsequent filing in the form of a resource plan amendment (“Ely Energy Center Amendment”) in which they will ask for PUCN approval to proceed with the construction of the Ely Energy Center and transmission line based on detailed engineering, construction and cost estimates, and a refined project schedule. |
| |
| | 2. | | The PUCN approved NPC’s request to construct 600 MW of nominally rated quick start combustion turbine units at the Clark Station at a cost of approximately $395 million, with approximately 400 MWs of peaking capacity to be installed prior to the summer of 2008 and approximately 200 MWs of additional peaking capacity to installed prior to the summer of 2009. |
Material Amendments to NPC’s 2006 Integrated Resource Plan
In January 2007, NPC filed an amendment to its 2006 Integrated Resource Plan requesting approval to expend $60 million to install new ultra-low emission burners on the four combustion turbines serving the combined cycle units at the Clark Generating Station.
Material Amendments to NPC’s 2003 Integrated Resource Plan
Request for Authorization to Acquire Land & Land Rights for Transmission Facilities
In January 2006, NPC filed an amendment to its 2003 Integrated Resource Plan requesting approval to acquire approximately $57 million of strategic investments in land and land rights necessary for future 500 kV and 230 kV transmission facilities. NPC also requested approval to accrue a carrying charge on the investments, which would be equal to the current Allowance for Funds Used During Construction.
In April 2006, the PUCN approved a negotiated agreement that authorizes NPC to invest $37 million in land and land rights and to include authorized investments in the rate base calculation for its next general rate case.
88
Enhanced ROE Due to Early Completion of Lenzie Generating Station
The PUCN designated Lenzie a critical facility and allowed a 2% enhancement to the authorized ROE when the PUCN approved NPC’s request to acquire the facility. The PUCN further allowed up to an additional .5% enhanced ROE if the Lenzie Block #1 generator units (two combustion turbine/generators and one steam turbine/generator) were commercially operable before March 2006 and another .5% ROE enhancement if Block #2 was completed before June 2006.
In January 2006, the first 600 MW combined cycle unit (Block #1) was declared commercially operable. In April 2006, NPC announced that Lenzie Block #2 was commercially operable. NPC’s construction costs are projected to be less than the amount authorized by the PUCN. NPC believes it is eligible to receive a 3% enhancement to the otherwise authorized ROE that will be decided as a result of its GRC filing that it made in November 2006. See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements for further discussion on the accounting for the enhancement.
Sierra Pacific Power Company
2006 Electric Deferred Energy Rate Case and BTER Update
In December 2006, SPPC filed an electric DEAA rate case and BTER update application with the PUCN. The application seeks recovery of $18.7 million of deferred fuel and purchased power costs and requested to reset SPPC’s going forward BTER to reflect anticipated changes in future energy costs. This application requests a 0.86% decrease in overall rates.
2006 Western Energy Crisis Rate Case
In December 2006, SPPC filed an application to recover $22.6 million over four years in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the western energy crisis. This application requests an overall rate increase of 0.53%.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC further requests authority to recover carrying charges on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset established by the PUCN in a future application to change rates. The parties to the stipulation have requested that the PUCN issue an order by September 30, 2007.
2006 Natural Gas and Propane Deferred Energy Rate Case and BTER Update
In May 2006, SPPC’s gas distribution operation filed applications with the PUCN seeking recovery of deferred natural gas and propane costs accumulated between April 1, 2005 and March 31, 2006. The applications sought to establish a new natural gas DEAA rate to recover $2.5 million of deferred natural gas costs and a new propane DEAA rate to recover $120 thousand of deferred propane costs. SPPC also requested authorization to increase going forward natural gas and propane BTER’s to reflect forecasted gas costs.
In October 2006, the PUCN approved negotiated natural gas and propane settlements which consolidated the deferred natural gas and propane balances for collection from all gas customers and reduced the combined balance to $1.1 million. The agreements transferred approximately $1.4 million to other deferral periods and $.1 million to expense accounts. The agreements called for the cost recovery to occur over a 12 month period beginning December 2006.
The negotiated going forward natural gas rate is expected to recover an additional $1.3 million in revenue, which is a decrease from the originally requested $24.5 million. The decrease reflects more current natural gas price expectations.
These settlements, combined with the expiration of a previous natural gas DEAA rate will cause natural gas customer rates to decrease by 2.5% and cause propane customer rates to increase by 3.3 %.
2005 Electric Deferred Energy Rate Case and BTER Update
In December 2005, SPPC filed an electric deferred energy rate case application with the PUCN. The application sought to establish a rate to collect accumulated fuel and purchased power costs of $46.7 million from the December 2004 to September 2005 deferral period and $17.5 million from the previously approved unamortized deferrals, for a total $64.2 million. In June 2006, the PUCN approved a negotiated settlement, which granted SPPC full recovery of the deferred costs during a two year period beginning July 2006. Under this agreement, the DEAA rate changes required to asymmetrically recover the $46.7 million deferred balance are scheduled to be implemented such that they will be offset by the expiration of previously approved DEAA rates. As a result, no rate increase was required.
89
The application also requested an increase to the BTER. In April 2006, the PUCN issued an order authorizing SPPC to increase its BTER on May 1, 2006, such that SPPC expects to collect $31 million in new revenues for purchased power. The change represented a 3.5% increase to customer rates.
2005 Electric and Gas General Rate Cases
In October 2005, SPPC filed a gas general rate case along with its statutorily required electric general rate case. SPPC’s last gas general rate case was filed in 1992 and the last electric general rate case was filed in 2003. The following items were requested in the filings:
| | • | | Electric general revenue increase: $27 million or 3.4% effective May 1, 2006 |
| |
| | • | | Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006 |
| |
| | • | | Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively |
| |
| | • | | Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively |
| |
| | • | | Approval to continue to recover an allocated amount of the 1999 NPC/SPPC merger costs from Electric customers |
| |
| | • | | Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers |
| |
| | • | | New depreciation rates for Gas and Electric facilities |
In April 2006, the PUCN issued its order to change electric and gas general rates. Although the order differed from SPPC’s requested filing, the changes did not require material adjustments to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following significant items:
| | • | | Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006. |
| |
| | • | | Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006. |
| |
| | • | | Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively. |
| |
| | • | | Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively. |
| |
| | • | | Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Electric customers. |
| |
| | • | | Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Gas customers. |
| |
| | • | | New depreciation rates for Gas and Electric facilities. |
| |
| | • | | Deferred recovery of legal expenses related to the Enron purchased power contract litigation. |
Material Amendments to SPPC’s 2004 Integrated Resource Plan
In July 2006, SPPC filed the thirteenth amendment to its 2004 Integrated Resource Plan. The following are the key elements of the filing:
| | • | | Requested approval to construct two 750 MW critical coal fired generation units at the proposed Ely Energy Center in White Pine County, Nevada estimated to be in service by 2011 and 2013 respectively. Also, part of this project is a 250-mile 500 kV transmission line to integrate the new generation into both NPC’s and SPPC’s systems and to allow delivery of geothermal resources from Northern Nevada to NPC and solar powered generation from Southern Nevada to SPPC. The Utilities are currently estimating that 80% of the costs will be allocated to NPC and 20% will be allocated to SPPC. |
| |
| | • | | Requested the PUCN to designate the Ely Energy Center and the 500kV transmission intertie as critical facilities under Nevada regulations and requested incentive ratemaking treatment including “CWIP in rate base” during construction and, upon completion, a 2% enhanced ROE and accumulation of depreciation expense in a regulatory asset account from the time the plants are placed in service until they are included in rates. |
| |
| | • | | Requested approval to make certain enhancements to SPPC’s existing fleet of generators. |
| |
| | • | | Provided a $3.8 billion total estimate for the Ely Energy Center and outlines SPPC’s cost for other proposed initiatives totaling approximately $15 million. |
In September 2006, SPPC provided testimony that modified its request for critical facility designations and associated incentive ratemaking treatments, which included the withdrawal of the following:
| | • | | Incentive ratemaking treatment for the initial $300 million project development costs. |
| |
| | • | | SPPC’s request for a specific enhanced ROE in this docket; however, SPPC stated it would resubmit a request for an enhanced ROE in a future filing. |
In October 2006 the PUCN approved a negotiated settlement of SPPC’s 2007 Energy Supply Plan Update, which was a component of its integrated resource plan amendment.
90
In November 2006, the PUCN issued an order with the findings of that order listed below:
| | • | | Supply Side Resources |
| |
| | | | The PUCN granted the Utilities’ request to proceed with the development of Phase I of the Ely Energy Center and accompanying transmission line. The PUCN also approved the Utilities’ request of $300 million for development activities associated with the Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit. The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively. Furthermore, the PUCN granted SPPC’s request for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date. |
The PUCN also directed the Utilities, upon receipt of the air permit, to prepare and submit a subsequent filing in the form of a resource plan amendment (“Ely Energy Center Amendment”) in which they will ask for PUCN approval to proceed with the construction of the Ely Energy Center and transmission line based on detailed engineering, construction and cost estimates, and a refined project schedule.
Other Nevada Matters
Nevada Power Company and Sierra Pacific Power Company
Renewable Portfolio Compliance
In April 2006, the Utilities filed their 2005 Annual Renewable Energy Portfolio Standard Report with the PUCN (the “Report”). The Report indicates that the Utilities will meet the non-solar portfolio standard upon PUCN approval of a sale from SPPC to NPC of non-solar portfolio energy credits. The Utilities requested an exemption from the PUCN for the solar portion of the portfolio standard.
In September 2006, the PUCN approved a stipulated agreement allowing NPC to purchase from SPPC, non-solar portfolio energy credits to meet its 2005 compliance year requirements.
In January 2007, the PUCN approved the Annual Report of NPC and SPPC regarding compliance with the renewable energy portfolio standard for 2005 in accordance with a stipulated agreement that was filed with the PUCN in November 2006.
California Electric Matters
Sierra Pacific Power Company
2006 Energy Cost Adjustment Clause Rate Case
In April 2006, SPPC filed with the CPUC to reset its “balancing” rate to recover a forecasted deferred energy cost balance and to increase its “offset” rate for going-forward fuel and power purchases. The requested increase in the balancing rate is expected to result in $1.1 million additional revenue and the requested increase in the offset rate is expected to collect an additional $10.1 million. The total request represents an $11.2 million annual revenue increase or a 16.5% average increase to customer rates.
In October 2006, the CPUC authorized SPPC’s request as filed.
2005 General Rate Case
In June 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. SPPC requested that the new rates become effective on January 1, 2006.
In August 2006, the CPUC approved a settlement agreement, which beginning September 2006, allowed SPPC to collect an estimated $4.1 million of additional general revenues from its California customers.
91
Other California Matters
Sierra Pacific Power Company
Senate Bill 1368
In September 2006, California enacted Senate Bill 1368 which requires, among other things, that load bearing utilities may not undertake new long-term financial commitments for baseload generation plants if the greenhouse gas (GHG) emission rates for those plants exceed the GHG emission rate of a combined cycle gas turbine power plant. The legislation also provides that multi-jurisdictional utilities, including SPPC, will not be subject to the substantive restrictions of Senate Bill 1368 if the CPUC finds that GHG emissions by those utilities are subject to regulatory review in at least one other state. On January 25, 2007, the CPUC issued an order finding that SPPC meets this alternative compliance requirement and that SPPC need only file annual advice letters with the CPUC attesting that it continues to meet the alternative compliance requirement.
SPPC is unable to predict the impact that future California legislative or regulatory actions relating to GHG emissions may have on SPPC.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
As of December 31, 2006, 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. 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 (dollars in thousands).
December 31, 2006
Expected Maturity Date
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | Fair |
| | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | Thereafter | | Total | | Value |
| | | |
Long-term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SPR | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 549,209 | | | $ | 549,209 | | | $ | 568,541 | |
| Average Interest Rate | | | — | | | | — | | | | — | | | | — | | | | — | | | | 7.75 | % | | | 7.75 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NPC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | 15 | | | $ | 15 | | | $ | — | | | $ | — | | | $ | 364,000 | | | $ | 1,776,835 | | | $ | 2,140,865 | | | $ | 2,246,234 | |
| Average Interest Rate | | | 8.17 | % | | | 8.17 | % | | | — | | | | — | | | | 8.14 | % | | | 6.58 | % | | | 6.85 | % | | | | |
| Variable Rate | | $ | — | | | $ | — | | | $ | 15,000 | | | $ | — | | | $ | — | | | $ | 192,500 | | | $ | 207,500 | | | $ | 207,500 | |
| Average Interest Rate | | | — | | | | — | | | | 3.63 | % | | | — | | | | — | | | | 3.57 | % | | | 3.57 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SPPC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | 2,400 | | | $ | 322,400 | | | $ | 80,600 | | | $ | — | | | $ | — | | | $ | 400,000 | | | $ | 805,400 | | | $ | 819,744 | |
| Average Interest Rate | | | 6.40 | % | | | 7.99 | % | | | 5.01 | % | | | — | | | | — | | | | 6.06 | % | | | 6.73 | % | | | | |
| Variable Rate | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 268,250 | | | $ | 268,250 | | | $ | 268,250 | |
| Average Interest Rate | | | — | | | | — | | | | — | | | | — | | | | — | | | | 3.62 | % | | | 3.62 | % | | | | |
| | | |
Total Debt | | $ | 2,415 | | | $ | 322,415 | | | $ | 95,600 | | | $ | — | | | $ | 364,000 | | | $ | 3,186,794 | | | $ | 3,971,224 | | | $ | 4,110,269 | |
| | | |
92
December 31, 2005
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expected Maturity Date | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | Thereafter | | | Total | | | Value | |
Long-term Debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SPR | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 659,142 | | | $ | 659,142 | | | $ | 689,131 | |
| Average Interest Rate | | | | | | | | | | | | | | | | | | | | | | | 7.86 | % | | | 7.86 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NPC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | 15 | | | $ | 17 | | | $ | 13 | | | $ | 162,500 | | | $ | — | | | $ | 1,741,048 | | | $ | 1,903,593 | | | $ | 1,979,608 | |
| Average Interest Rate | | | 8.17 | % | | | 8.17 | % | | | 8.17 | % | | | 10.88 | % | | | | | | | 7.20 | % | | | 7.52 | % | | | | |
| Variable Rate | | | | | | | | | | | | | | $ | 15,000 | | | $ | 150,000 | | | $ | 100,000 | | | $ | 265,000 | | | $ | 265,000 | |
| Average Interest Rate | | | | | | | | | | | | | | | 1.74 | % | | | 5.50 | % | | | 1.74 | % | | | 3.87 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SPPC | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | 52,400 | | | $ | 2,400 | | | $ | 322,400 | | | $ | 80,420 | | | $ | — | | | $ | 537,250 | | | $ | 994,870 | | | $ | 1,013,385 | |
| Average Interest Rate | | | 6.73 | % | | | 6.40 | % | | | 7.99 | % | | | 5.01 | % | | | | | | | 6.75 | % | | | 7.01 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Debt | | $ | 52,415 | | | $ | 2,417 | | | $ | 322,413 | | | $ | 257,920 | | | $ | 150,000 | | | $ | 3,037,440 | | | $ | 3,822,605 | | | $ | 3,947,124 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity Price Risk
Commodity price increases due to changes in market conditions are recovered through the deferred energy mechanism. Although the Utilities actively manage energy commodity (electric, natural gas, coal and oil) price risk through their procurement strategies, the ability to recover commodity price changes through future rates substantially mitigates commodity price risk. However, the Utilities are subject to cash flow risk due to changes in the value of their open positions and are subject to regulatory risk because the PUCN may disallow recovery for any costs that it considers imprudently incurred. The Utilities mitigate both risk associated with its open positions and regulatory risk through prudent energy supply practices which include the use of long-term fuel supply agreements, long- term purchase power agreements and derivative instruments such as forwards, options and swaps to meet the anticipated fuel and power requirements. 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 and Note 13, Commitments and Contingencies, Regulatory Contingencies, of the Notes to Financial Statements, for a discussion of amounts subject to regulatory risk.
Credit Risk
The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $31.1 million as of December 31, 2006, which decreased significantly from December 31, 2005 due to lower natural gas and power prices in 2006 compared to the high prices experienced in 2005 as a result of hurricanes in the southern United States. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.
93
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| | | | | |
| | | Page | |
| Reports of Independent Registered Public Accounting Firm | | | 95 | |
| | | | | |
| Financial Statements: | | | | |
| | | | | |
| Sierra Pacific Resources: | | | | |
| Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 98 | |
| Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 99 | |
| Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004 | | | 100 | |
| Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 101 | |
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 102 | |
| Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 103 | |
| | | | | |
| Nevada Power Company: | | | | |
| Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 105 | |
| Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 106 | |
| Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004 | | | 107 | |
| Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 108 | |
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 109 | |
| Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 110 | |
| | | | | |
| Sierra Pacific Power Company: | | | | |
| Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 111 | |
| Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 112 | |
| Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004 | | | 113 | |
| Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 114 | |
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 115 | |
| Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 116 | |
| | | | | |
| Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company | | | 117 | |
94
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Sierra Pacific Resources
Reno, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Resources and subsidiaries as of December 31, 2006 and 2005, and the related consolidated income statements and statements of comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, on January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123(R), and on December 31, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Reno, Nevada
March 1, 2007
95
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of Nevada Power Company and subsidiaries as of December 31, 2006 and 2005, and the related consolidated income statements and statements of comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 1 to the consolidated financial statements, on December 31, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158.
DELOITTE & TOUCHE LLP
Reno, Nevada
March 1, 2007
96
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Reno, Nevada
We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Power Company and subsidiaries as of December 31, 2006 and 2005, and the related consolidated income statements and statements of comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 1 to the consolidated financial statements, on December 31, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158.
DELOITTE & TOUCHE LLP
Reno, Nevada
March 1, 2007
97
SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
ASSETS | | | | | | | | |
| Utility Plant at Original Cost: | | | | | | | | |
| Plant in service | | $ | 7,954,337 | | | $ | 6,801,916 | |
| Less accumulated provision for depreciation | | | 2,333,357 | | | | 2,169,316 | |
| | | | | | | |
| | | | 5,620,980 | | | | 4,632,600 | |
| Construction work-in-progress | | | 466,018 | | | | 765,005 | |
| | | | | | | |
| | | | 6,086,998 | | | | 5,397,605 | |
| | | | | | | |
| Investments and other property, net (Note 4) | | | 34,325 | | | | 82,771 | |
| | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | | 115,709 | | | | 172,735 | |
| Restricted cash and investments | | | — | | | | 67,245 | |
| Accounts receivable less allowance for uncollectible accounts: 2006-$39,566; 2005-$36,229 | | | 415,082 | | | | 413,234 | |
| Deferred energy costs — electric (Note 1) | | | 168,260 | | | | 253,697 | |
| Deferred energy costs — gas (Note 1) | | | — | | | | 5,825 | |
| Materials, supplies and fuel, at average cost | | | 103,757 | | | | 88,445 | |
| Risk management assets (Note 9) | | | 27,305 | | | | 50,226 | |
| Deferred income taxes (Note 10) | | | 55,546 | | | | — | |
| Deposits and prepayments for energy | | | 15,968 | | | | 45,054 | |
| Other | | | 31,580 | | | | 26,544 | |
| | | | | | | |
| | | | 933,207 | | | | 1,123,005 | |
| | | | | | | |
| Deferred Charges and Other Assets: | | | | | | | | |
| Goodwill (Note 18) | | | 469 | | | | 22,877 | |
| Deferred energy costs — electric (Note 1) | | | 382,286 | | | | 255,312 | |
| Deferred energy costs — gas (Note 1) | | | — | | | | 845 | |
| Regulatory tax asset (Note 10) | | | 263,170 | | | | 249,261 | |
| Regulatory asset for pension plans (Note 1) | | | 223,218 | | | | — | |
| Other regulatory assets | | | 668,624 | | | | 568,145 | |
| Risk management assets (Note 9) | | | 7,586 | | | | — | |
| Risk management regulatory assets — net (Note 9) | | | 122,911 | | | | — | |
| Unamortized debt issuance costs | | | 67,106 | | | | 63,395 | |
| Other | | | 42,176 | | | | 107,330 | |
| | | | | | | |
| | | | 1,777,546 | | | | 1,267,165 | |
| | | | | | | |
TOTAL ASSETS | | $ | 8,832,076 | | | $ | 7,870,546 | |
| | | | | | | |
CAPITALIZATION AND LIABILITIES | | | | | | | | |
| Capitalization: | | | | | | | | |
| Common shareholders’ equity | | $ | 2,622,297 | | | $ | 2,060,154 | |
| Preferred stock | | | — | | | | 50,000 | |
| Long-term debt | | | 4,001,542 | | | | 3,817,122 | |
| | | | | | | |
| | | | 6,623,839 | | | | 5,927,276 | |
| | | | | | | |
| Current Liabilities: | | | | | | | | |
| Current maturities of long-term debt | | | 8,348 | | | | 58,909 | |
| Accounts payable | | | 282,463 | | | | 263,100 | |
| Accrued interest | | | 56,426 | | | | 58,585 | |
| Dividends declared | | | 73 | | | | 1,043 | |
| Accrued salaries and benefits | | | 33,146 | | | | 32,186 | |
| Current income taxes payable (Note 10) | | | 5,914 | | | | 3,159 | |
| Deferred income taxes (Note 10) | | | — | | | | 129,041 | |
| Risk management liabilities (Note 9) | | | 123,065 | | | | 16,580 | |
| Accrued taxes | | | 6,290 | | | | 6,540 | |
| Contract termination liabilities | | | ��� | | | | 129,000 | |
| Other current liabilities | | | 60,349 | | | | 56,724 | |
| | | | | | | |
| | | | 576,074 | | | | 754,867 | |
| | | | | | | |
| Commitments and Contingencies (Note 13) | | | | | | | | |
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Deferred income taxes (Note 10) | | | 791,428 | | | | 451,924 | |
| Deferred investment tax credit | | | 35,218 | | | | 38,625 | |
| Regulatory tax liability (Note 10) | | | 34,075 | | | | 38,224 | |
| Customer advances for construction | | | 91,895 | | | | 170,061 | |
| Accrued retirement benefits | | | 226,420 | | | | 71,810 | |
| Risk management liabilities (Note 9) | | | 10,746 | | | | — | |
| Risk management regulatory liability — net (Note 9) | | | — | | | | 15,605 | |
| Regulatory liabilities (Note 1) | | | 301,903 | | | | 284,438 | |
| Other | | | 140,478 | | | | 117,716 | |
| | | | | | | |
| | | | 1,632,163 | | | | 1,188,403 | |
| | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 8,832,076 | | | $ | 7,870,546 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
98
SIERRA PACIFIC RESOURCES
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
OPERATING REVENUES: | | | | | | | | | | | | |
| Electric | | $ | 3,144,243 | | | $ | 2,850,694 | | | $ | 2,666,000 | |
| Gas | | | 210,068 | | | | 178,270 | | | | 153,752 | |
| Other | | | 1,639 | | | | 1,278 | | | | 5,044 | |
| | | | | | | | | | |
| | | | 3,355,950 | | | | 3,030,242 | | | | 2,824,796 | |
| | | | | | | | | | |
OPERATING EXPENSES: | | | | | | | | | | | | |
| Operation: | | | | | | | | | | | | |
| Purchased power | | | 1,109,440 | | | | 1,315,986 | | | | 1,069,302 | |
| Fuel for power generation | | | 800,585 | | | | 510,736 | | | | 459,478 | |
| Gas purchased for resale | | | 160,739 | | | | 140,850 | | | | 121,526 | |
| Deferred energy costs disallowed | | | — | | | | — | | | | 1,586 | |
| Deferral of energy costs — electric – net | | | 139,365 | | | | (37,558 | ) | | | 143,033 | |
| Deferral of energy costs — gas – net | | | 6,947 | | | | (749 | ) | | | (4,136 | ) |
| Impairment of goodwill | | | — | | | | — | | | | 11,695 | |
| Reinstatement of deferred energy (Note 13) | | | (178,825 | ) | | | — | | | | — | |
| Other | | | 367,198 | | | | 363,802 | | | | 335,998 | |
| Maintenance | | | 93,172 | | | | 78,730 | | | | 78,907 | |
| Depreciation and amortization | | | 228,875 | | | | 214,662 | | | | 205,922 | |
| Taxes: | | | | | | | | | | | | |
| Income taxes (Note 10) | | | 91,571 | | | | 39,185 | | | | 22,739 | |
| Other than income | | | 48,086 | | | | 45,920 | | | | 44,888 | |
| | | | | | | | | | |
| | | | 2,867,153 | | | | 2,671,564 | | | | 2,490,938 | |
| | | | | | | | | | |
OPERATING INCOME | | | 488,797 | | | | 358,678 | | | | 333,858 | |
| | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | |
| Allowance for other funds used during construction | | | 18,226 | | | | 20,322 | | | | 5,948 | |
| Interest accrued on deferred energy | | | 27,898 | | | | 27,442 | | | | 25,332 | |
| Early debt conversion fees | | | — | | | | (54,000 | ) | | | — | |
| Disallowed merger costs | | | — | | | | — | | | | (5,890 | ) |
| Disallowed plant costs | | | — | | | | — | | | | (47,092 | ) |
| Carrying charge for Lenzie (Note 1) | | | 33,440 | | | | — | | | | — | |
| Gain on sale of investment | | | 62,927 | | | | — | | | | — | |
| Other income | | | 37,123 | | | | 41,200 | | | | 35,313 | |
| Other expense | | | (23,497 | ) | | | (18,645 | ) | | | (13,770 | ) |
| Income (taxes) / benefits (Note 10) | | | (54,034 | ) | | | (3,933 | ) | | | 4,689 | |
| | | | | | | | | | |
| | | | 102,083 | | | | 12,386 | | | | 4,530 | |
| | | | | | | | | | |
| Total Income Before Interest Charges | | | 590,880 | | | | 371,064 | | | | 338,388 | |
| | | | | | | | | | | | | |
INTEREST CHARGES: | | | | | | | | | | | | |
| Long-term debt | | | 294,488 | | | | 302,668 | | | | 313,305 | |
| Interest for Energy Suppliers (Note 13) | | | — | | | | (17,221 | ) | | | (35,170 | ) |
| Other | | | 33,719 | | | | 24,171 | | | | 37,998 | |
| Allowance for borrowed funds used during construction | | | (17,119 | ) | | | (24,691 | ) | | | (8,587 | ) |
| | | | | | | | | | |
| | | | 311,088 | | | | 284,927 | | | | 307,546 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | | 279,792 | | | | 86,137 | | | | 30,842 | |
| | | | | | | | | | | | | |
DISCONTINUED OPERATIONS: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Gain on the sale of discontinued operations (net of income taxes of ($877)) | | | — | | | | — | | | | 1,629 | |
| | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARY AND PREMIUM ON REDEMPTION | | | 2,341 | | | | 3,900 | | | | 3,900 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | |
NET INCOME APPLICABLE TO COMMON STOCK | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Amount per share basic and diluted — (Note 16) | | | | | | | | | | | | |
| Income from continuing operations | | $ | 1.34 | | | $ | 0.46 | | | $ | 0.17 | |
| Gain on sale of discontinued operations | | $ | — | | | $ | — | | | $ | 0.01 | |
| Net income applicable to common stock | | $ | 1.33 | | | $ | 0.44 | | | $ | 0.16 | |
| | | | | | | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding — basic | | | 208,531,134 | | | | 185,548,314 | | | | 183,080,475 | |
| | | | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding — diluted | | | 209,020,896 | | | | 185,932,504 | | | | 183,400,303 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
99
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
NET INCOME APPLICABLE TO COMMON STOCK | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | |
| Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $1,155 and ($950) in 2005 and 2004, respectively) | | | — | | | | (2,146 | ) | | | 1,763 | |
| Minimum pension liability adjustment (Net of taxes of ($1,132), $1,569 and ($15,486) in 2006, 2005 and 2004, respectively) | | | 2,106 | | | | (4,311 | ) | | | 29,404 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS) | | | 2,106 | | | | (6,457 | ) | | | 31,167 | |
| | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 279,557 | | | $ | 75,780 | | | $ | 59,738 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements
100
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
Common Stock: | | | | | | | | | | | | |
| Balance at Beginning of Year | | $ | 200,792 | | | $ | 117,469 | | | $ | 117,236 | |
| Stock issuance/exchange, CSIP, DRP, ESPP and other | | | 20,238 | | | | 83,323 | | | | 233 | |
| | | | | | | | | | |
| Balance at end of year | | | 221,030 | | | | 200,792 | | | | 117,469 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Other Paid-In Capital: | | | | | | | | | | | | |
| Balance at Beginning of Year | | | 2,220,896 | | | | 1,818,453 | | | | 1,815,202 | |
| Premium on issuance/exchange of common stock | | | 260,600 | | | | 405,767 | | | | 563 | |
| Common Stock issuance costs | | | (857 | ) | | | (6,486 | ) | | | — | |
| Revaluation of investment | | | — | | | | 119 | | | | 1,690 | |
| Value of derivative transferred to equity | | | — | | | | — | | | | — | |
| CSIP, DRP, ESPP and other | | | 2,605 | | | | 3,043 | | | | 998 | |
| | | | | | | | | | |
| Balance at End of Year | | | 2,483,244 | | | | 2,220,896 | | | | 1,818,453 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Retained Earnings (Deficit): | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (355,883 | ) | | | (438,112 | ) | | | (466,683 | ) |
| Net Income applicable to Common Stock | | | 277,451 | | | | 82,237 | | | | 28,571 | |
| Common stock dividends declared, net of adjustments | | | — | | | | (8 | ) | | | — | |
| | | | | | | | | | |
| Balance at End of Year | | | (78,432 | ) | | | (355,883 | ) | | | (438,112 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Accumulated Other Comprehensive Income (Loss): | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (5,651 | ) | | | 806 | | | | (30,361 | ) |
| Adoption of SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities | | | | | | | | | | | | |
| Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $1,155 and ($950) in 2005 and 2004, respectively) | | | — | | | | (2,146 | ) | | | 1,763 | |
| Minimum pension liability adjustment (Net of taxes of ($1,132), $1,569 and ($15,486) in 2006, 2005 and 2004, respectively) | | | 2,106 | | | | (4,311 | ) | | | 29,404 | |
| | | | | | | | | | |
| Balance at End of Year | | | (3,545 | ) | | | (5,651 | ) | | | 806 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Total Common Shareholders’ Equity at End of Year | | $ | 2,622,297 | | | $ | 2,060,154 | | | $ | 1,498,616 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements
101
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | For the Year Ended December 31 | |
| | | 2006 | | | 2005 | | | 2004 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net Income applicable to common stock | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| Non-cash items included in net income (loss): | | | | | | | | | | | | |
| Depreciation and amortization | | | 228,875 | | | | 214,662 | | | | 205,922 | |
| Deferred taxes and deferred investment tax credit | | | 136,026 | | | | 41,609 | | | | 33,690 | |
| AFUDC | | | (18,226 | ) | | | (45,013 | ) | | | (14,536 | ) |
| Amortization of deferred energy costs – electric | | | 166,821 | | | | 188,221 | | | | 265,418 | |
| Amortization of deferred energy costs – gas | | | 6,234 | | | | 1,446 | | | | 3,242 | |
| Deferred energy costs disallowed | | | — | | | | — | | | | 1,586 | |
| Goodwill impairment | | | — | | | | — | | | | 11,695 | |
| Plant costs disallowed | | | — | | | | — | | | | 47,092 | |
| Reinstatement of deferred energy | | | (178,825 | ) | | | — | | | | — | |
| Carrying charge on Lenzie plant | | | (33,440 | ) | | | — | | | | — | |
| Gain on sale of investment | | | (62,927 | ) | | | — | | | | — | |
| Impairment of assets of subsidiary | | | — | | | | — | | | | 10,997 | |
| Gain on sale of discontinued operations | | | — | | | | — | | | | (2,506 | ) |
| Other | | | 24,650 | | | | (219) | | | | (23,453) | |
| Changes in certain assets and liabilities: | | | | | | | | | | | | |
| Accounts receivable | | | (43,214 | ) | | | (92,452 | ) | | | (19,198 | ) |
| Deferral of energy costs – electric | | | (54,737 | ) | | | (241,103 | ) | | | (152,140 | ) |
| Deferral of energy costs – gas | | | 436 | | | | (2,519 | ) | | | (7,480 | ) |
| Deferral of energy costs — terminated suppliers | | | 8,741 | | | | 218,040 | | | | 4,551 | |
| Materials, supplies and fuel | | | (15,312 | ) | | | (12,251 | ) | | | 3,331 | |
| Other current assets | | | 24,050 | | | | 20,663 | | | | 5,721 | |
| Accounts payable | | | (2,739 | ) | | | 55,985 | | | | 13,623 | |
| Payment to terminating supplier | | | (65,368 | ) | | | — | | | | (61,129 | ) |
| Proceeds from claim on terminating supplier | | | 41,365 | | | | — | | | | — | |
| Other current liabilities | | | 2,356 | | | | (162,416 | ) | | | 20,306 | |
| Risk Management assets and liabilities | | | (5,950 | ) | | | (6,685 | ) | | | 8,487 | |
| Other assets | | | (10,122 | ) | | | (9,950 | ) | | | 6,168 | |
| Other liabilities | | | 3,297 | | | | (15,659 | ) | | | (42,476 | ) |
| | | | | | | | | | |
| Net Cash from Operating Activities | | | 429,442 | | | | 234,596 | | | | 347,482 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS USED BY INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Additions to utility plant | | | (986,019 | ) | | | (686,394 | ) | | | (614,411 | ) |
| AFUDC | | | 18,226 | | | | 45,013 | | | | 14,536 | |
| Customer advances for construction | | | 17,348 | | | | 27,358 | | | | 16,197 | |
| Contributions in aid of construction | | | 38,792 | | | | 23,351 | | | | 26,457 | |
| Proceeds from sale of investment | | | 99,730 | | | | — | | | | — | |
| Proceeds from sale of discontinued operations | | | — | | | | — | | | | 4,471 | |
| Investments in subsidiaries and other property — net | | | 8,423 | | | | 10,200 | | | | 16,299 | |
| | | | | | | | | | |
| Net Cash used by Investing Activities | | | (803,500 | ) | | | (580,472 | ) | | | (536,451 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Increase in short-term borrowings | | | — | | | | — | | | | (25,000 | ) |
| Change in restricted cash and investments | | | 3,612 | | | | 23,711 | | | | 27,382 | |
| Proceeds from issuance of long-term debt | | | 2,491,883 | | | | 370,211 | | | | 965,000 | |
| Retirement of long-term debt | | | (2,407,745 | ) | | | (373,938 | ) | | | (693,538 | ) |
| Redemption of preferred stock | | | (51,366 | ) | | | — | | | | — | |
| Sale of common stock, net of issuance cost | | | 282,594 | | | | 236,208 | | | | 3,488 | |
| Dividends paid | | | (1,945 | ) | | | (3,911 | ) | | | (3,821 | ) |
| | | | | | | | | | |
| Net Cash from Financing Activities | | | 317,033 | | | | 252,281 | | | | 273,511 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (57,025 | ) | | | (93,595 | ) | | | 84,542 | |
| Beginning Balance in Cash and Cash Equivalents | | | 172,734 | | | | 266,330 | | | | 181,789 | |
| | | | | | | | | | |
| Ending Balance in Cash and Cash Equivalents | | $ | 115,709 | | | $ | 172,735 | | | $ | 266,331 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Cash paid during period for: | | | | | | | | | | | | |
| Interest | | $ | 338,665 | | | $ | 330,889 | | | $ | 339,718 | |
| Income taxes | | $ | 4,726 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
Noncash Activities: | | | | | | | | | | | | |
| Exchange of Convertible Debt for SPR Common Stock | | $ | — | | | $ | 248,168 | | | $ | — | |
The accompanying notes are an integral part of the financial statements
102
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
| | | | | | | | | |
| | | December 31 | |
| | | 2006 | | | 2005 | |
Common Shareholder’s Equity: | | | | | | | | |
| Common stock, $1.00 par value, authorized 350 million; issued and outstanding 2006: 221,030,000 shares; issued and outstanding 2005: 200,792,000 shares issued and outstanding | | $ | 221,030 | | | $ | 200,792 | |
| Other paid-in capital | | | 2,483,244 | | | | 2,220,896 | |
| Retained Deficit | | | (78,432 | ) | | | (355,883 | ) |
| Accumulated other comprehensive Income (Loss) | | | (3,545 | ) | | | (5,651 | ) |
| | | | | | | |
| Total Common Shareholder’s Equity | | | 2,622,297 | | | | 2,060,154 | |
| | | | | | | |
Preferred Stock of Subsidiaries: | | | | | | | | |
| Not subject to mandatory redemption; 2005: 2,000,000 shares outstanding; $25 stated value | | | | | | | | |
| SPPC Class A Series 1; $1.95 dividend | | | — | | | | 50,000 | |
| | | | | | | |
Long-Term Debt: | | | | | | | | |
Secured Debt | | | | | | | | |
| First Mortgage Bonds | | | | | | | | |
| 8.50% NPC Series Z due 2023 | | | — | | | | 35,000 | |
| Debt Secured by First Mortgage Bonds | | | | | | | | |
| Revenue Bonds | | | | | | | | |
| Nevada Power Company | | | | | | | | |
| 6.60% NPC Series 1992B due 2019 | | | — | | | | 39,500 | |
| 6.70% NPC Series 1992A due 2022 | | | — | | | | 105,000 | |
| 7.20% NPC Series 1992C due 2022 | | | — | | | | 78,000 | |
| Sierra Pacific Power Company | | | | | | | | |
| 6.35% SPPC Series 1992B due 2012 | | | — | | | | 1,000 | |
| 6.55% SPPC Series 1987 due 2013 | | | — | | | | 39,500 | |
| 6.30% SPPC Series 1987 due 2014 | | | — | | | | 45,000 | |
| 6.65% SPPC Series 1987 due 2017 | | | — | | | | 92,500 | |
| 6.55% SPPC Series 1990 due 2020 | | | — | | | | 20,000 | |
| 6.30% SPPC Series 1992A due 2022 | | | — | | | | 10,250 | |
| 5.90% SPPC Series 1993A due 2023 | | | — | | | | 9,800 | |
| 5.90% SPPC Series 1993B due 2023 | | | — | | | | 30,000 | |
| 6.70% SPPC Series 1992 due 2032 | | | — | | | | 21,200 | |
| Medium Term Notes | | | | | | | | |
| Sierra Pacific Power Company | | | | | | | | |
| 6.62% to 6.83% SPPC Series C due 2006 | | | — | | | | 50,000 | |
| 6.95% to 8.61% SPPC Series A due 2022 | | | — | | | | 110,000 | |
| 7.10% to 7.14% SPPC Series B due 2023 | | | — | | | | 58,000 | |
| | | | | | | |
| Subtotal | | | — | | | | 744,750 | |
| | | | | | | |
| | | | | | | | | |
| Debt Secured by General and Refunding Mortgage Securities | | | | | | | | |
| Nevada Power Company | | | | | | | | |
| 10.88% NPC Series E due 2009 | | | — | | | | 162,500 | |
| 8.25% NPC Series A due 2011 | | | 350,000 | | | | 350,000 | |
| 6.50% NPC Series I due 2012 | | | 130,000 | | | | 130,000 | |
| 9.00% NPC Series G due 2013 | | | 227,500 | | | | 227,500 | |
| 5.875% NPC Series L due 2015 | | | 250,000 | | | | 250,000 | |
| 5.95% NPC Series M due 2016 | | | 210,000 | | | | — | |
| 6.65% NPC Series N due 2036 | | | 370,000 | | | | — | |
| 6.50% NPC Series O due 2018 | | | 325,000 | | | | — | |
| | | | | | | |
| Subtotal | | | 1,862,500 | | | | 1,120,000 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
(Continued)
103
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
| | | | | | | | | |
| | | December 31 | |
| | | 2006 | | | 2005 | |
| Sierra Pacific Power Company | | | | | | | | |
| 8.00% SPPC Series A due 2008 | | | 320,000 | | | | 320,000 | |
| 6.25% SPPC Series H due 2012 | | | 100,000 | | | | 100,000 | |
| 6.00% SPPC Series M due 2016 | | | 300,000 | | | | — | |
| 5.00% SPPC Series 2001 due 2036 | | | 80,000 | | | | 80,000 | |
| | | | | | | |
| Subtotal | | | 800,000 | | | | 500,000 | |
| | | | | | | |
| Variable Rate Notes | | | | | | | | |
| Nevada Power Company | | | | | | | | |
| NPC PCRB Series 2000B due 2009 | | | 15,000 | | | | 15,000 | |
| NPC IDRB Series 2000A due 2020 | | | 100,000 | | | | 100,000 | |
| NPC PCRB Series 2006 due 2036 | | | 39,500 | | | | — | |
| NPC PCRB Series 2006A due 2032 | | | 40,000 | | | | — | |
| NPC PCRB Series 2006B due 2039 | | | 13,000 | | | | — | |
| NPC Revolving Credit Facility | | | — | | | | 150,000 | |
| | | | | | | |
| Subtotal | | | 207,500 | | | | 265,000 | |
| | | | | | | |
| Sierra Pacific Power Company | | | | | | | | |
| SPPC PCRB Series 2006 due 2029 | | | 49,750 | | | | — | |
| SPPC PCRB Series 2006A due 2031 | | | 58,700 | | | | — | |
| SPPC PCRB Series 2006B due 2036 | | | 75,000 | | | | — | |
| SPPC PCRB Series 2006C due 2036 | | | 84,800 | | | | — | |
| | | | | | | |
| Subtotal | | | 268,250 | | | | — | |
| | | | | | | |
| | | | | | | | | |
Unsecured Debt | | | | | | | | |
| Revenue Bonds | | | | | | | | |
| Nevada Power Company | | | | | | | | |
| 5.30% NPC Series 1995D due 2011 | | | 14,000 | | | | 14,000 | |
| 5.35% NPC Series 1995E due 2022 | | | — | | | | 13,000 | |
| 5.45% NPC Series 1995D due 2023 | | | 6,300 | | | | 6,300 | |
| 5.50% NPC Series 1995C due 2030 | | | 44,000 | | | | 44,000 | |
| 5.60% NPC Series 1995A due 2030 | | | 76,750 | | | | 76,750 | |
| 5.90% NPC Series 1995B due 2030 | | | 85,000 | | | | 85,000 | |
| 5.80% NPC Series 1997B due 2032 | | | — | | | | 20,000 | |
| 5.90% NPC Series 1997A due 2032 | | | 52,285 | | | | 52,285 | |
| 6.38% NPC Series 1996 due 2036 | | | — | | | | 20,000 | |
| | | | | | | |
| Subtotal | | | 278,335 | | | | 331,335 | |
| | | | | | | |
| Other Notes | | | | | | | | |
| Sierra Pacific Resources | | | | | | | | |
| 7.803% SPR Senior Notes due 2012 | | | 74,170 | | | | 99,142 | |
| 8.625% SPR Notes due 2014 | | | 250,039 | | | | 335,000 | |
| 6.75% SPR Senior Notes due 2017 | | | 225,000 | | | | 225,000 | |
| | | | | | | |
| Subtotal, excluding current portion | | | 549,209 | | | | 659,142 | |
| | | | | | | |
| Unamortized bond premium and discount, net | | | (11,813 | ) | | | (3,495 | ) |
| | | | | | | |
| | | | | | | | | |
| Nevada Power Company | | | | | | | | |
| 8.2% Junior Subordinated Debentures of NPC, due 2037 | | | — | | | | 122,548 | |
| 7.75% Junior Subordinated Debentures of NPC, due 2038 | | | — | | | | 72,165 | |
| | | | | | | |
| Subtotal | | | — | | | | 194,713 | |
| | | | | | | |
| Obligations under capital leases | | | 50,479 | | | | 56,921 | |
| Current maturities and sinking fund requirements | | | (8,348 | ) | | | (58,909 | ) |
| | | | | | | | | |
| Other, excluding current portion | | | 5,430 | | | | 7,665 | |
| | | | | | | |
| Total Long-Term Debt | | | 4,001,542 | | | | 3,817,122 | |
| | | | | | | |
TOTAL CAPITALIZATION | | $ | 6,623,839 | | | $ | 5,927,276 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
(Concluded)
104
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
ASSETS | | | | | | | | |
| Utility Plant at Original Cost: | | | | | | | | |
| Plant in service | | $ | 5,187,665 | | | $ | 4,106,489 | |
| Less accumulated provision for depreciation | | | 1,276,192 | | | | 1,128,209 | |
| | | | | | | |
| | | | 3,911,473 | | | | 2,978,280 | |
| Construction work-in-progress | | | 238,518 | | | | 698,206 | |
| | | | | | | |
| | | | 4,149,991 | | | | 3,676,486 | |
| | | | | | | |
| | | | | | | | | |
| Investments and other property, net (Note 4) | | | 22,176 | | | | 29,249 | |
| | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | | 36,633 | | | | 98,681 | |
| Restricted cash | | | — | | | | 52,374 | |
| Accounts receivable less allowance for uncollectible accounts: | | | | | | | | |
| 2006-$32,834; 2005-$30,386 | | | 244,623 | | | | 232,086 | |
| Accounts receivable, affiliated companies | | | — | | | | 3,738 | |
| Deferred energy costs — electric (Note 1) | | | 129,304 | | | | 186,355 | |
| Materials, supplies and fuel, at average cost | | | 60,754 | | | | 46,835 | |
| Risk management assets (Note 9) | | | 16,378 | | | | 22,404 | |
| Deferred income taxes (Note 10) | | | 72,294 | | | | — | |
| Deposits and prepayments for energy | | | 7,056 | | | | 16,303 | |
| Other | | | 19,901 | | | | 16,075 | |
| | | | | | | |
| | | | 586,943 | | | | 674,851 | |
| | | | | | | |
| | | | | | | | | |
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred energy costs — electric (Note 1) | | | 359,589 | | | | 214,587 | |
| Regulatory tax asset (Note 10) | | | 153,471 | | | | 155,304 | |
| Regulatory asset for pension plans (Note 1) | | | 113,646 | | | | | |
| Other regulatory assets (Note 1) | | | 440,369 | | | | 362,567 | |
| Risk management assets | | | 5,379 | | | | — | |
| Risk management regulatory assets — net (Note 9) | | | 83,886 | | | | — | |
| Unamortized debt issuance costs | | | 38,856 | | | | 37,157 | |
| Other | | | 33,209 | | | | 23,720 | |
| | | | | | | |
| | | | 1,228,405 | | | | 793,335 | |
| | | | | | | |
TOTAL ASSETS | | $ | 5,987,515 | | | $ | 5,173,921 | |
| | | | | | | |
| | | | | | | | | |
CAPITALIZATION AND LIABILITIES | | | | | | | | |
| Capitalization: | | | | | | | | |
| Common shareholder’s equity | | $ | 2,172,198 | | | $ | 1,762,089 | |
| Long-term debt | | | 2,380,139 | | | | 2,214,063 | |
| | | | | | | |
| | | | 4,552,337 | | | | 3,976,152 | |
| | | | | | | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Current maturities of long-term debt | | | 5,948 | | | | 6,509 | |
| Accounts payable | | | 148,003 | | | | 164,169 | |
| Accounts payable, affiliated companies | | | 20,656 | | | | — | |
| Accrued interest | | | 37,010 | | | | 33,031 | |
| Dividends declared | | | 13,545 | | | | 397 | |
| Accrued salaries and benefits | | | 14,989 | | | | 15,537 | |
| Current income taxes payable (Note 10) | | | 3,981 | | | | 3,159 | |
| Intercompany Income taxes payable | | | 884 | | | | — | |
| Deferred income taxes (Note 10) | | | — | | | | 57,392 | |
| Risk management liabilities (Note 9) | | | 84,674 | | | | 10,125 | |
| Accrued taxes | | | 2,671 | | | | 2,817 | |
| Contract termination liabilities | | | — | | | | 89,784 | |
| Other current liabilities | | | 48,225 | | | | 46,425 | |
| | | | | | | |
| | | | 380,586 | | | | 429,345 | |
| | | | | | | |
| | | | | | | | | |
| Commitments and Contingencies (Note 13) | | | | | | | | |
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Deferred income taxes (Note 10) | | | 599,747 | | | | 362,973 | |
| Deferred investment tax credit | | | 15,213 | | | | 16,832 | |
| Regulatory tax liability (Note 10) | | | 13,451 | | | | 15,068 | |
| Customer advances for construction | | | 60,040 | | | | 98,056 | |
| Accrued retirement benefits | | | 90,474 | | | | 22,203 | |
| Risk management liabilities (Note 9) | | | 7,061 | | | | — | |
| Risk management regulatory liability — net (Note 9) | | | — | | | | 590 | |
| Regulatory liabilities (Note 1) | | | 171,298 | | | | 173,527 | |
| Other | | | 97,308 | | | | 79,175 | |
| | | | | | | |
| | | | 1,054,592 | | | | 768,424 | |
| | | | | | | |
| | | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 5,987,515 | | | $ | 5,173,921 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
105
NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
OPERATING REVENUES: | | | | | | | | | | | | |
| Electric | | $ | 2,124,081 | | | $ | 1,883,267 | | | $ | 1,784,092 | |
| | | | | | | | | | | | | |
OPERATING EXPENSES: | | | | | | | | | | | | |
| Operation: | | | | | | | | | | | | |
| Purchased power | | | 764,850 | | | | 963,888 | | | | 764,347 | |
| Fuel for power generation | | | 552,959 | | | | 277,083 | | | | 235,404 | |
| Deferred energy costs disallowed | | | — | | | | — | | | | 1,586 | |
| Deferral of energy costs-net | | | 92,322 | | | | (45,668 | ) | | | 135,973 | |
| Reinstatement of deferred energy (Note 13) | | | (178,825 | ) | | | — | | | | — | |
| Other | | | 218,120 | | | | 211,039 | | | | 183,736 | |
| Maintenance | | | 61,899 | | | | 52,040 | | | | 57,030 | |
| Depreciation and amortization | | | 141,585 | | | | 124,098 | | | | 118,841 | |
| Taxes: | | | | | | | | | | | | |
| Income taxes (Note 10) | | | 91,781 | | | | 46,425 | | | | 45,135 | |
| Other than income | | | 28,118 | | | | 25,535 | | | | 25,550 | |
| | | | | | | | | | |
| | | | 1,772,809 | | | | 1,654,440 | | | | 1,567,602 | |
| | | | | | | | | | |
OPERATING INCOME | | | 351,272 | | | | 228,827 | | | | 216,490 | |
| | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | |
| Allowance for other funds used during construction | | | 11,755 | | | | 18,683 | | | | 4,230 | |
| Interest accrued on deferred energy | | | 21,902 | | | | 20,350 | | | | 20,199 | |
| Disallowed merger costs | | | — | | | | — | | | | (3,961 | ) |
| Carrying charge for Lenzie (Note 1) | | | 33,440 | | | | — | | | | — | |
| Other income | | | 16,992 | | | | 25,626 | | | | 22,844 | |
| Other expense | | | (8,480 | ) | | | (8,525 | ) | | | (6,665 | ) |
| Income taxes (Note 10) | | | (25,729 | ) | | | (17,570 | ) | | | (11,437 | ) |
| | | | | | | | | | |
| | | | 49,880 | | | | 38,564 | | | | 25,210 | |
| | | | | | | | | | |
| Total Income Before Interest Charges | | | 401,152 | | | | 267,391 | | | | 241,700 | |
| | | | | | | | | | | | | |
INTEREST CHARGES: | | | | | | | | | | | | |
| Long-term debt | | | 171,188 | | | | 159,106 | | | | 152,764 | |
| Interest for Energy Suppliers (Note 13) | | | — | | | | (14,825 | ) | | | (24,171 | ) |
| Other | | | 17,038 | | | | 13,563 | | | | 14,533 | |
| Allowance for borrowed funds used during construction | | | (11,614 | ) | | | (23,187 | ) | | | (5,738 | ) |
| | | | | | | | | | |
| | | | 176,612 | | | | 134,657 | | | | 137,388 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
NET INCOME | | $ | 224,540 | | | $ | 132,734 | | | $ | 104,312 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
106
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
NET INCOME | | $ | 224,540 | | | $ | 132,734 | | | $ | 104,312 | |
| | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | | | | | | | | | | | | |
| Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785, and ($688) in 2005 and 2004, respectively) | | | — | | | | (1,460 | ) | | | 1,277 | |
| Minimum pension liability adjustment (Net of taxes of ($520), $740 and ($1,205) in 2006, 2005 and 2004, respectively) | | | 965 | | | | (2,769 | ) | | | 2,239 | |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS) | | | 965 | | | | (4,229 | ) | | | 3,516 | |
| | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 225,505 | | | $ | 128,505 | | | $ | 107,828 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements
107
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
Common Stock: | | | | | | | | | | | | |
| Balance at Beginning of Year and End of Year | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| | | | | | | | | | | | | |
Other Paid-In Capital: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | 1,808,848 | | | | 1,576,794 | | | | 1,377,106 | |
| Transfer of Goodwill | | | — | | | | — | | | | 197,998 | |
| Revaluation of investment | | | — | | | | 119 | | | | 1,690 | |
| Transfer of pension assets | | | 33,521 | | | | — | | | | — | |
| Capital infusion from parent | | | 200,000 | | | | 231,935 | | | | — | |
| | | | | | | | | | |
| Balance at End of Year | | | 2,042,369 | | | | 1,808,848 | | | | 1,576,794 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Retained Earnings (Deficit): | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (43,422 | ) | | | (140,898 | ) | | | (199,837 | ) |
| Income for the year | | | 224,540 | | | | 132,734 | | | | 104,312 | |
| Common stock dividends declared | | | (48,917 | ) | | | (35,258 | ) | | | (45,373 | ) |
| | | | | | | | | | |
| Balance at End of Year | | | 132,201 | | | | (43,422 | ) | | | (140,898 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Accumulated Other Comprehensive Income (Loss): | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (3,338 | ) | | | 891 | | | | (2,625 | ) |
| Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785 and ($688) in 2005 and 2004, respectively) | | | — | | | | (1,460 | ) | | | 1,277 | |
| Minimum pension liability adjustment (Net of taxes of ($520), $740 and ($1,205) in 2006, 2005 and 2004, respectively) | | | 965 | | | | (2,769 | ) | | | 2,239 | |
| | | | | | | | | | |
| Balance at End of Year | | | (2,373 | ) | | | (3,338 | ) | | | 891 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Total Common Shareholder’s Equity at End of Year | | $ | 2,172,198 | | | $ | 1,762,089 | | | $ | 1,436,788 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
108
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net Income | | $ | 224,540 | | | $ | 132,734 | | | $ | 104,312 | |
| Non-cash items included in net loss: | | | | | | | | | | | | |
| Depreciation and amortization | | | 141,585 | | | | 124,098 | | | | 118,841 | |
| Deferred taxes and deferred investment tax credit | | | 107,392 | | | | 86,910 | | | | 57,066 | |
| AFUDC | | | (11,755 | ) | | | (41,870 | ) | | | (9,969 | ) |
| Amortization of deferred energy costs | | | 120,499 | | | | 131,471 | | | | 228,765 | |
| Deferred energy costs disallowed | | | — | | | | — | | | | 1,586 | |
| Reinstatement of deferred energy | | | (178,825 | ) | | | — | | | | | |
| Carrying charge on Lenzie plant | | | (33,440 | ) | | | — | | | | | |
| Other | | | 3,394 | | | | (7,433 | ) | | | (44,149 | ) |
| Changes in certain assets and liabilities: | | | | | | | | | | | | |
| Accounts receivable | | | (35,191 | ) | | | (57,746 | ) | | | (7,247 | ) |
| Deferral of energy costs | | | (49,982 | ) | | | (186,338 | ) | | | (117,543 | ) |
| Deferral of energy costs — terminated suppliers | | | 3,896 | | | | 155,119 | | | | 4,551 | |
| Materials, supplies and fuel | | | (13,919 | ) | | | (1,977 | ) | | | (3,782 | ) |
| Other current assets | | | 5,421 | | | | 14,434 | | | | 14,522 | |
| Accounts payable | | | (2,431 | ) | | | 30,855 | | | | 10,350 | |
| Payment to terminating supplier | | | (37,410 | ) | | | — | | | | (50,311 | ) |
| Proceeds from claim on terminating supplier | | | 26,391 | | | | — | | | | — | |
| Other current liabilities | | | 5,083 | | | | (107,575 | ) | | | 10,504 | |
| Risk Management assets and liabilities | | | (2,219 | ) | | | (6,597 | ) | | | 4,454 | |
| Other assets | | | (9,902 | ) | | | (9,950 | ) | | | 6,168 | |
| Other liabilities | | | (2,946 | ) | | | (31,926 | ) | | | 14,522 | |
| | | | | | | | | | |
| Net Cash from Operating Activities | | | 260,181 | | | | 224,209 | | | | 342,640 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS USED BY INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Additions to utility plant | | | (670,441 | ) | | | (546,748 | ) | | | (482,484 | ) |
| AFUDC | | | 11,755 | | | | 41,870 | | | | 9,969 | |
| Customer advances for construction | | | 10,417 | | | | 18,813 | | | | 8,067 | |
| Contributions in aid of construction | | | 21,241 | | | | 8,544 | | | | 10,703 | |
| Investments in subsidiaries and other property — net | | | 7,363 | | | | 1,875 | | | | 5,404 | |
| | | | | | | | | | |
| Net Cash used by Investing Activities | | | (619,665 | ) | | | (475,646 | ) | | | (448,341 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Change in restricted cash and investments | | | — | | | | — | | | | 2,600 | |
| Proceeds from issuance of long-term debt | | | 1,687,726 | | | | 150,000 | | | | 530,000 | |
| Retirement of long-term debt | | | (1,554,521 | ) | | | (238,486 | ) | | | (283,498 | ) |
| Additional investment by parent company | | | 200,000 | | | | 230,541 | | | | — | |
| Dividends paid | | | (35,769 | ) | | | (35,260 | ) | | | (44,975 | ) |
| | | | | | | | | | |
| Net Cash from Financing Activities | | | 297,436 | | | | 106,795 | | | | 204,127 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (62,048 | ) | | | (144,642 | ) | | | 98,426 | |
| Beginning Balance in Cash and Cash Equivalents | | | 98,681 | | | | 243,323 | | | | 144,897 | |
| | | | | | | | | | |
| Ending Balance in Cash and Cash Equivalents | | $ | 36,633 | | | $ | 98,681 | | | $ | 243,323 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Cash paid during period for: | | | | | | | | | | | | |
| Interest | | $ | 190,023 | | | $ | 173,775 | | | $ | 161,126 | |
| Income taxes | | $ | 4,714 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
Noncash Activities: | | | | | | | | | | | | |
| Transfer of Regulatory Asset | | $ | — | | | $ | — | | | $ | 197,998 | |
The accompanying notes are an integral part of the financial statements
109
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
| | | | | | | | | |
| | | December 31 | |
| | | 2006 | | | 2005 | |
Common Shareholder’s Equity: | | | | | | | | |
| Common stock, $1.00 par value, 1,000 shares authorized, issued and Outstanding | | $ | 1 | | | $ | 1 | |
| Other paid-in capital | | | 2,042,369 | | | | 1,808,848 | |
| Retained Earning (Deficit) | | | 132,201 | | | | (43,422 | ) |
| Accumulated other comprehensive Income (Loss) | | | (2,373 | ) | | | (3,338 | ) |
| | | | | | | |
| Total Common Shareholder’s Equity | | | 2,172,198 | | | | 1,762,089 | |
| | | | | | | |
Long-Term Debt: | | | | | | | | |
Secured Debt | | | | | | | | |
| First Mortgage Bonds | | | | | | | | |
| 8.50% Series Z due 2023 | | | — | | | | 35,000 | |
| Debt Secured by First Mortgage Bonds | | | | | | | | |
| Revenue Bonds | | | | | | | | |
| 6.60% Series 1992B due 2019 | | | — | | | | 39,500 | |
| 6.70% Series 1992A due 2022 | | | — | | | | 105,000 | |
| 7.20% Series 1992C due 2022 | | | — | | | | 78,000 | |
| | | | | | | |
| Subtotal | | | — | | | | 257,500 | |
| | | | | | | |
| Debt Secured by General and Refunding Mortgage Securities | | | | | | | | |
| 10.88% Series E due 2009 | | | — | | | | 162,500 | |
| 8.25% Series A due 2011 | | | 350,000 | | | | 350,000 | |
| 6.50% Series I due 2012 | | | 130,000 | | | | 130,000 | |
| 9.00% Series G due 2013 | | | 227,500 | | | | 227,500 | |
| 5.875% Series L due 2015 | | | 250,000 | | | | 250,000 | |
| 5.95% Series M due 2016 | | | 210,000 | | | | — | |
| 6.65% Series N due 2036 | | | 370,000 | | | | — | |
| 6.00% Series O due 2018 | | | 325,000 | | | | — | |
| | | | | | | |
| Subtotal | | | 1,862,500 | | | | 1,120,000 | |
| | | | | | | |
| Variable Rate Notes | | | | | | | | |
| PCRB Series 2000B due 2009 | | | 15,000 | | | | 15,000 | |
| IDRB Series 2000A due 2020 | | | 100,000 | | | | 100,000 | |
| PCRB Series 2006 due 2036 | | | 39,500 | | | | — | |
| PCRB Series 2006A due 2032 | | | 40,000 | | | | — | |
| PCRB Series 2006B due 2039 | | | 13,000 | | | | — | |
| Revolving Credit Facility | | | — | | | | 150,000 | |
| | | | | | | |
| Subtotal | | | 207,500 | | | | 265,000 | |
| | | | | | | |
Unsecured Debt | | | | | | | | |
| Revenue Bonds | | | | | | | | |
| 5.30% Series 1995D due 2011 | | | 14,000 | | | | 14,000 | |
| 5.35% Series 1995E due 2022 | | | — | | | | 13,000 | |
| 5.45% Series 1995D due 2023 | | | 6,300 | | | | 6,300 | |
| 5.50% Series 1995C due 2030 | | | 44,000 | | | | 44,000 | |
| 5.60% Series 1995A due 2030 | | | 76,750 | | | | 76,750 | |
| 5.90% Series 1995B due 2030 | | | 85,000 | | | | 85,000 | |
| 5.80% Series 1997B due 2032 | | | — | | | | 20,000 | |
| 5.90% Series 1997A due 2032 | | | 52,285 | | | | 52,285 | |
| 6.38% Series 1996 due 2036 | | | — | | | | 20,000 | |
| | | | | | | |
| Subtotal | | | 278,335 | | | | 331,335 | |
| | | | | | | |
| Unamortized bond premium and discount, net | | | (12,757 | ) | | | (4,942 | ) |
| | | | | | | |
| 8.2% Junior Subordinated Debentures due 2037 | | | — | | | | 122,548 | |
| 7.75% Junior Subordinated Debentures due 2038 | | | — | | | | 72,165 | |
| | | | | | | |
| Subtotal | | | — | | | | 194,713 | |
| | | | | | | |
| Obligations under capital leases | | | 50,479 | | | | 56,921 | |
| Current maturities and sinking fund requirements | | | (5,948 | ) | | | (6,509 | ) |
| Other, excluding current portion | | | 30 | | | | 45 | |
| | | | | | | |
| Total Long-Term Debt | | | 2,380,139 | | | | 2,214,063 | |
| | | | | | | |
TOTAL CAPITALIZATION | | $ | 4,552,337 | | | $ | 3,976,152 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
110
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
ASSETS | | | | | | | | |
| Utility Plant at Original Cost: | | | | | | | | |
| Plant in service | | $ | 2,766,672 | | | $ | 2,695,427 | |
| Less accumulated provision for depreciation | | | 1,057,165 | | | | 1,041,107 | |
| | | | | | | |
| | | | 1,709,507 | | | | 1,654,320 | |
| Construction work-in-progress | | | 227,500 | | | | 66,799 | |
| | | | | | | |
| | | | 1,937,007 | | | | 1,721,119 | |
| | | | | | | |
| | | | | | | | | |
| Investments and other property, net (Note 4) | | | 609 | | | | 842 | |
| | | | | | | |
| | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | | 53,260 | | | | 38,153 | |
| Restricted cash | | | — | | | | 14,871 | |
| Accounts receivable less allowance for uncollectible accounts: | | | | | | | | |
| 2006-$6,732; 2005-$5,842 | | | 170,106 | | | | 180,973 | |
| Accounts receivable, affiliated companies | | | — | | | | 40,278 | |
| Deferred energy costs — electric (Note 1) | | | 38,956 | | | | 67,342 | |
| Deferred energy costs — gas (Note 1) | | | — | | | | 5,825 | |
| Materials, supplies and fuel, at average cost | | | 42,990 | | | | 41,608 | |
| Risk management assets (Note 9) | | | 10,927 | | | | 27,822 | |
| Deposits and prepayments for energy | | | 8,912 | | | | 28,751 | |
| Other | | | 11,184 | | | | 9,547 | |
| | | | | | | |
| | | | 336,335 | | | | 455,170 | |
| | | | | | | |
| | | | | | | | | |
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred energy costs — electric (Note 1) | | | 22,697 | | | | 40,725 | |
| Deferred energy costs — gas (Note 1) | | | — | | | | 845 | |
| Regulatory tax asset (Note 10) | | | 109,699 | | | | 93,957 | |
| Regulatory asset for pension plans (Note 1) | | | 106,666 | | | | — | |
| Other regulatory assets | | | 228,255 | | | | 205,578 | |
| Risk management assets (Note 9) | | | 2,207 | | | | — | |
| Risk management regulatory assets – net (Note 9) | | | 39,025 | | | | — | |
| Unamortized debt issuance costs | | | 17,981 | | | | 12,693 | |
| Other | | | 7,356 | | | | 15,372 | |
| | | | | | | |
| | | | 533,886 | | | | 369,170 | |
| | | | | | | |
TOTAL ASSETS | | $ | 2,807,837 | | | $ | 2,546,301 | |
| | | | | | | |
CAPITALIZATION AND LIABILITIES | | | | | | | | |
| Capitalization: | | | | | | | | |
| Common shareholder’s equity | | $ | 884,737 | | | $ | 727,777 | |
| Preferred stock | | | — | | | | 50,000 | |
| Long-term debt | | | 1,070,858 | | | | 941,804 | |
| | | | | | | |
| | | | 1,955,595 | | | | 1,719,581 | |
| | | | | | | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Current maturities of long-term debt | | | 2,400 | | | | 52,400 | |
| Accounts payable | | | 89,743 | | | | 56,661 | |
| Accounts payable, affiliated companies | | | 11,769 | | | | — | |
| Accrued interest | | | 7,200 | | | | 10,993 | |
| Dividends declared | | | 6,736 | | | | 968 | |
| Accrued salaries and benefits | | | 15,209 | | | | 14,032 | |
| Intercompany income taxes payable (Note 10) | | | 9,055 | | | | 49,673 | |
| Deferred income taxes (Note 10) | | | 8,881 | | | | 21,832 | |
| Risk management liabilities (Note 9) | | | 38,391 | | | | 6,455 | |
| Accrued taxes | | | 3,407 | | | | 3,541 | |
| Contract termination liabilities | | | — | | | | 39,216 | |
| Other current liabilities | | | 12,125 | | | | 10,299 | |
| | | | | | | |
| | | | 204,916 | | | | 266,070 | |
| | | | | | | |
| | | | | | | | | |
| Commitments and Contingencies (Note 13) | | | | | | | | |
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Deferred income taxes (Note 10) | | | 278,515 | | | | 244,244 | |
| Deferred investment tax credit | | | 20,005 | | | | 21,793 | |
| Regulatory tax liability (Note 10) | | | 20,624 | | | | 23,156 | |
| Customer advances for construction | | | 31,855 | | | | 72,005 | |
| Accrued retirement benefits | | | 124,254 | | | | 40,269 | |
| Risk management liabilities (Note 9) | | | 3,685 | | | | — | |
| Risk management regulatory liability — net (Note 9) | | | — | | | | 15,015 | |
| Regulatory liabilities (Note 1) | | | 130,605 | | | | 110,911 | |
| Other | | | 37,783 | | | | 33,257 | |
| | | | | | | |
| | | | 647,326 | | | | 560,650 | |
| | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 2,807,837 | | | $ | 2,546,301 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
111
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
OPERATING REVENUES: | | | | | | | | | | | | |
| Electric | | $ | 1,020,162 | | | $ | 967,427 | | | $ | 881,908 | |
| Gas | | | 210,068 | | | | 178,270 | | | | 153,752 | |
| | | | | | | | | | |
| | | | 1,230,230 | | | | 1,145,697 | | | | 1,035,660 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
OPERATING EXPENSES: | | | | | | | | | | | | |
| Operation: | | | | | | | | | | | | |
| Purchased power | | | 344,590 | | | | 352,098 | | | | 304,955 | |
| Fuel for power generation | | | 247,626 | | | | 233,653 | | | | 224,074 | |
| Gas purchased for resale | | | 160,739 | | | | 140,850 | | | | 121,526 | |
| Deferral of energy costs — electric — net | | | 47,043 | | | | 8,110 | | | | 7,060 | |
| Deferral of energy costs — gas — net | | | 6,947 | | | | (749 | ) | | | (4,136 | ) |
| Other | | | 141,350 | | | | 131,901 | | | | 128,091 | |
| Maintenance | | | 31,273 | | | | 26,690 | | | | 21,877 | |
| Depreciation and amortization | | | 87,279 | | | | 90,569 | | | | 86,806 | |
| Taxes: | | | | | | | | | | | | |
| Income taxes (Note 10) | | | 23,570 | | | | 26,038 | | | | 14,978 | |
| Other than income | | | 19,796 | | | | 20,233 | | | | 19,184 | |
| | | | | | | | | | |
| | | | 1,110,213 | | | | 1,029,393 | | | | 924,415 | |
| | | | | | | | | | |
OPERATING INCOME | | | 120,017 | | | | 116,304 | | | | 111,245 | |
| | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | |
| Allowance for other funds used during construction | | | 6,471 | | | | 1,639 | | | | 1,718 | |
| Interest accrued on deferred energy | | | 5,996 | | | | 7,092 | | | | 5,133 | |
| Disallowed merger costs | | | — | | | | — | | | | (1,929 | ) |
| Plant costs disallowed | | | — | | | | — | | | | (47,092 | ) |
| Other income | | | 9,412 | | | | 5,940 | | | | 3,406 | |
| Other expense | | | (8,422 | ) | | | (7,493 | ) | | | (5,726 | ) |
| Income (taxes) / benefits (Note 10) | | | (4,259 | ) | | | (2,341 | ) | | | 14,653 | |
| | | | | | | | | | |
| | | | 9,198 | | | | 4,837 | | | | (29,837 | ) |
| | | | | | | | | | |
| Total Income Before Interest Charges | | | 129,215 | | | | 121,141 | | | | 81,408 | |
| | | | | | | | | | | | | |
INTEREST CHARGES: | | | | | | | | | | | | |
| Long-term debt | | | 71,869 | | | | 69,240 | | | | 71,312 | |
| Interest for Energy Suppliers (Note 13) | | | — | | | | (2,396 | ) | | | (10,999 | ) |
| Other | | | 5,142 | | | | 3,727 | | | | 5,367 | |
| Allowance for borrowed funds used during construction and capitalized interest | | | (5,505 | ) | | | (1,504 | ) | | | (2,849 | ) |
| | | | | | | | | | |
| | | | 71,506 | | | | 69,067 | | | | 62,831 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
NET INCOME | | | 57,709 | | | | 52,074 | | | | 18,577 | |
| | | | | | | | | | | | | |
| Dividend Requirements and premium on redemption of preferred stock | | | 2,341 | | | | 3,900 | | | | 3,900 | |
| | | | | | | | | | |
| Earnings applicable to common stock | | $ | 55,368 | | | $ | 48,174 | | | $ | 14,677 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
112
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
NET INCOME | | $ | 57,709 | | | $ | 52,074 | | | $ | 18,577 | |
| | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | | | | | | | | | | | | |
| Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $370 and ($323) in 2005 and 2004, respectively) | | | — | | | | (686 | ) | | | 600 | |
| Minimum pension liability adjustment (net of taxes of ($462), $632 and $65 in 2006, 2005 and 2004, respectively) | | | 861 | | | | (1,173 | ) | | | (123 | ) |
| | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS) | | | 861 | | | | (1,859 | ) | | | 477 | |
| | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 58,570 | | | $ | 50,215 | | | $ | 19,054 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements
113
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
Common Stock: | | | | | | | | | | | | |
| Balance at Beginning of Year and End of Year | | $ | 4 | | | $ | 4 | | | $ | 4 | |
| | | | | | | | | | | | | |
Other Paid-In Capital: | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | 810,103 | | | | 810,103 | | | | 713,633 | |
| Transfer of Goodwill (Note 19) | | | 18,888 | | | | — | | | | 96,470 | |
| Transfer of pension assets | | | 31,462 | | | | — | | | | — | |
| Capital infusion from parent | | | 75,000 | | | | — | | | | — | |
| | | | | | | | | | |
| Balance at End of Year | | | 935,453 | | | | 810,103 | | | | 810,103 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Retained Earnings (Deficit): | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (80,538 | ) | | | (104,779 | ) | | | (119,456 | ) |
| Income (Loss) from continuing operations before preferred dividends | | | 57,709 | | | | 52,074 | | | | 18,577 | |
| Preferred stock redemption | | | (1,366 | ) | | | — | | | | — | |
| Preferred stock dividends declared | | | (975 | ) | | | (3,900 | ) | | | (3,900 | ) |
| Common stock dividends declared | | | (24,619 | ) | | | (23,933 | ) | | | — | |
| | | | | | | | | | |
| Balance at End of Year | | | (49,789 | ) | | | (80,538 | ) | | | (104,779 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Accumulated Other Comprehensive Income (Loss): | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at Beginning of Year | | | (1,792 | ) | | | 67 | | | | (410 | ) |
| Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $370 and ($323) in 2005 and 2004, respectively) | | | — | | | | (686 | ) | | | 600 | |
| Minimum pension liability adjustment (Net of taxes of ($462), $632 and $65 in 2006, 2005 and 2004, respectively) | | | 861 | | | | (1,173 | ) | | | (123 | ) |
| | | | | | | | | | |
| Balance at End of Year | | | (931 | ) | | | (1,792 | ) | | | 67 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Total Common Shareholder’s Equity at End of Year | | $ | 884,737 | | | $ | 727,777 | | | $ | 705,395 | |
| | | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
114
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | For the Year Ended December 31 | |
| | | 2006 | | | 2005 | | | 2004 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net Income | | $ | 57,709 | | | $ | 52,074 | | | $ | 18,577 | |
| Non-cash items included in net income (loss): | | | | | | | | | | | | |
| Depreciation and amortization | | | 87,279 | | | | 90,569 | | | | 86,806 | |
| Deferred taxes and deferred investment tax credit | | | (39,361 | ) | | | 209 | | | | 11,640 | |
| AFUDC | | | (6,471 | ) | | | (3,143 | ) | | | (4,567 | ) |
| Amortization of deferred energy costs — electric | | | 46,322 | | | | 56,750 | | | | 36,653 | |
| Amortization of deferred energy costs — gas | | | 6,234 | | | | 1,446 | | | | 3,241 | |
| Plant costs disallowed | | | — | | | | — | | | | 47,092 | |
| Other | | | 16,935 | | | | 318 | | | | 474 | |
| Changes in certain assets and liabilities: | | | | | | | | | | | | |
| Accounts receivable | | | 36,171 | | | | (11,631 | ) | | | (19,677 | ) |
| Deferral of energy costs – electric | | | (4,755 | ) | | | (54,765 | ) | | | (34,598 | ) |
| Deferral of energy costs – gas | | | 436 | | | | (2,519 | ) | | | (7,480 | ) |
| Deferral of energy costs – terminated suppliers | | | 4,845 | | | | 62,921 | | | | — | |
| Materials, supplies and fuel | | | (1,382 | ) | | | (10,272 | ) | | | 7,113 | |
| Other current assets | | | 18,204 | | | | 3,106 | | | | (10,086 | ) |
| Accounts payable | | | 19,670 | | | | 11,573 | | | | 2,153 | |
| Payment to terminating supplier | | | (27,958 | ) | | | — | | | | (10,818 | ) |
| Proceeds from claim on terminating supplier | | | 14,974 | | | | — | | | | — | |
| Other current liabilities | | | (925 | ) | | | (48,603 | ) | | | 5,567 | |
| Risk Management assets and liabilities | | | (3,731 | ) | | | (88 | ) | | | 4,033 | |
| Other assets | | | (220 | ) | | | — | | | | — | |
| Other liabilities | | | 6,461 | | | | 12,186 | | | | (8,844 | ) |
| | | | | | | | | | |
| Net Cash from Operating Activities | | | 230,437 | | | | 160,131 | | | | 127,279 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS (USED BY) INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Additions to utility plant | | | (315,578 | ) | | | (139,646 | ) | | | (131,927 | ) |
| AFUDC | | | 6,471 | | | | 3,143 | | | | 4,567 | |
| Customer advances for construction | | | 6,931 | | | | 8,545 | | | | 8,130 | |
| Contributions in aid of construction | | | 17,551 | | | | 14,807 | | | | 15,754 | |
| Investments in subsidiaries and other property — net | | | 233 | | | | 157 | | | | (82 | ) |
| | | | | | | | | | |
| Net Cash used by Investing Activities | | | (284,392 | ) | | | (112,994 | ) | | | (103,558 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Decrease in short-term borrowings | | | — | | | | — | | | | (25,000 | ) |
| Change in restricted cash and investments | | | 3,612 | | | | 2,034 | | | | 3,130 | |
| Proceeds from issuance of long-term debt | | | 804,157 | | | | — | | | | 100,000 | |
| Retirement of long-term debt | | | (742,514 | ) | | | (2,504 | ) | | | (99,491 | ) |
| Redemption of preferred stock | | | (51,366 | ) | | | — | | | | — | |
| Investment by parent company | | | 75,000 | | | | — | | | | — | |
| Dividends paid | | | (19,827 | ) | | | (27,833 | ) | | | (3,900 | ) |
| | | | | | | | | | |
| Net Cash from (used by) Financing Activities | | | 69,062 | | | | (28,303 | ) | | | (25,261 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents: | | | 15,107 | | | | 18,834 | | | | (1,540 | ) |
| Beginning Balance in Cash and Cash Equivalents: | | | 38,153 | | | | 19,319 | | | | 20,859 | |
| | | | | | | | | | |
| Ending Balance in Cash and Cash Equivalents | | $ | 53,260 | | | $ | 38,153 | | | $ | 19,319 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Cash paid during period for: | | | | | | | | | | | | |
| Interest | | $ | 83,327 | | | $ | 71,496 | | | $ | 77,529 | |
| Income taxes | | $ | 12 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | |
Noncash Activities: | | | | | | | | | | | | |
| Transfer of Regulatory Asset (Note 18) | | $ | 18,888 | | | $ | — | | | $ | 96,470 | |
The accompanying notes are an integral part of the financial statements
115
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands, Except Per Share Amounts)
| | | | | | | | | |
| | | December 31 | |
| | | 2006 | | | 2005 | |
Common Shareholder’s Equity: | | | | | | | | |
| Common stock, $3.75 par value, 20,000,000 shares authorized, 1,000 shares issued and outstanding | | $ | 4 | | | $ | 4 | |
| Other paid-in capital | | | 935,453 | | | | 810,103 | |
| Retained Deficit | | | (49,789 | ) | | | (80,538 | ) |
| Accumulated other comprehensive Income (Loss) | | | (931 | ) | | | (1,792 | ) |
| | | | | | | |
| Total Common Shareholder’s Equity | | | 884,737 | | | | 727,777 | |
| | | | | | | |
Cumulative Preferred Stock: | | | | | | | | |
| Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value | | | — | | | | 50,000 | |
| | | | | | | |
| SPPC Class A Series 1; $1.95 dividend | | | | | | | | |
Long-Term Debt: | | | | | | | | |
Secured Debt | | | | | | | | |
| Debt Secured by First Mortgage Bonds | | | | | | | | |
| Revenue Bonds | | | | | | | | |
| 6.35% Series 1992B due 2012 | | | — | | | | 1,000 | |
| 6.55% Series 1987 due 2013 | | | — | | | | 39,500 | |
| 6.30% Series 1987 due 2014 | | | — | | | | 45,000 | |
| 6.65% Series 1987 due 2017 | | | — | | | | 92,500 | |
| 6.55% Series 1990 due 2020 | | | — | | | | 20,000 | |
| 6.30% Series 1992A due 2022 | | | — | | | | 10,250 | |
| 5.90% Series 1993A due 2023 | | | — | | | | 9,800 | |
| 5.90% Series 1993B due 2023 | | | — | | | | 30,000 | |
| 6.70% Series 1992 due 2032 | | | — | | | | 21,200 | |
| Medium Term Notes | | | | | | | | |
| 6.62% to 6.83% Series C due 2006 | | | — | | | | 50,000 | |
| 6.95% to 8.61% Series A due 2022 | | | — | | | | 110,000 | |
| 7.10% to 7.14% Series B due 2023 | | | — | | | | 58,000 | |
| | | | | | | |
| Subtotal | | | — | | | | 487,250 | |
| | | | | | | |
| Debt Secured by General and Refunding Mortgage Securities | | | | | | | | |
| 8.00% Series A due 2008 | | | 320,000 | | | | 320,000 | |
| 6.25% Series H due 2012 | | | 100,000 | | | | 100,000 | |
| 6.00% Series M due 2016 | | | 300,000 | | | | — | |
| 5.00% Series 2001 due 2036 | | | 80,000 | | | | 80,000 | |
| | | | | | | |
| Subtotal | | | 800,000 | | | | 500,000 | |
| | | | | | | |
| Variable Rate Notes | | | | | | | | |
| PCRB Series 2006 due 2029 | | | 49,750 | | | | — | |
| PCRB Series 2006A due 2031 | | | 58,700 | | | | — | |
| PCRB Series 2006B due 2036 | | | 75,000 | | | | — | |
| PCRB Series 2006C due 2036 | | | 84,800 | | | | — | |
| | | | | | | |
| Subtotal | | | 268,250 | | | | — | |
| | | | | | | |
| | | | | | | | | |
Unsecured Debt | | | | | | | | |
| Unamortized bond premium and discount, net | | | (392 | ) | | | (666 | ) |
| Current maturities and sinking fund requirements | | | (2,400 | ) | | | (52,400 | ) |
| Other, excluding current portion | | | 5,400 | | | | 7,620 | |
| | | | | | | |
| Total Long-Term Debt | | | 1,070,858 | | | | 941,804 | |
| | | | | | | |
TOTAL CAPITALIZATION | | $ | 1,955,595 | | | $ | 1,719,581 | |
| | | | | | | |
The accompanying notes are an integral part of the financial statements.
116
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:
Basis of Presentation
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). In 2004, certain operations of SPC are discontinued operations and as such are reported separately in the financial statements. 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.
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.
NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 68% of the consolidated assets of SPR at December 31, 2006. NPC provides electricity to approximately 807,000 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 NPC’s wholly-owned subsidiary, Nevada Electric Investment Company (NEICO).
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 31% of the consolidated assets of SPR at December 31, 2006. SPPC provides electricity to approximately 361,000 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. SPPC also provides natural gas service in Nevada to approximately 146,000 customers in an area of about 600 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, Piñon Pine Corporation, Piñon 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 was 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 accounted for its joint venture interest under the equity method. In December 2006, TGPC sold its partnership interest in the joint venture, see Note 4, Investment in Subsidiaries and Other Property. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada.
Reclassifications
Certain reclassifications of prior year’s information have been made for comparative purposes but have not affected previously reported results of operations or common shareholders’ equity.
Regulatory Accounting and Other Regulatory Assets
The Utilities’ rates are currently subject to the approval of the Public Utilities Commission of Nevada (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 deferral 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) regulated rates are designed to recover the specific costs of the regulated products or
117
services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers. Management periodically assesses whether the requirements for application of SFAS No. 71 are satisfied.
In addition to the deferral of energy costs discussed below, items to which SPR and the Utilities apply regulatory accounting are included in the tables below.
Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current and 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 could 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.
SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES
| | | | | | | | | | | | | | | | | | | | | | | |
| | | AS OF DECEMBER 31, 2006 | | | As of | |
| | | Remaining | | Receiving Regulatory Treatment | | | Pending | | | | | | | December | |
| (dollars in thousands) | | Amortization | | Earning a | | | Not Earning | | | Regulatory | | | 2006 | | | 31, 2005 | |
| DESCRIPTION | | Period | | Return(1) | | | a Return | | | Treatment | | | Total | | | Total | |
| Regulatory Assets | | | | | | | | | | | | | | | | | | | | | | |
| Loss on reacquired debt | | Term of Related Debt | | $ | 87,154 | | | $ | — | | | $ | — | | | $ | 87,154 | | | $ | 57,804 | |
| Lenzie | | | | | | | | | | | | | 52,456 | | | | 52,456 | | | | — | |
| Mohave plant and deferred costs | | 2026 | | | 21,582 | | | | — | | | | (3,747 | ) | | | 17,835 | | | | 28,280 | |
| Clark Units 1-3 | | Various thru 2015 | | | 11,545 | | | | — | | | | 5,190 | | | | 16,735 | | | | 13,136 | |
| Piñon Pine | | Various thru 2029 | | | 35,236 | | | | 6,155 | | | | 610 | | | | 42,001 | | | | 43,502 | |
| Plant assets | | Various thru 2031 | | | 2,876 | | | | — | | | | — | | | | 2,876 | | | | 3,058 | |
| Asset Retirement Obligations | | | | | | | | | — | | | | 16,112 | | | | 16,112 | | | | 14,904 | |
| Nevada divestiture costs | | 2012 | | | 23,983 | | | | — | | | | — | | | | 23,983 | | | | 28,497 | |
| Merger transition/transaction costs | | 2016 | | | — | | | | 28,916 | | | | — | | | | 28,916 | | | | 32,569 | |
| Merger severance/relocation | | 2016 | | | — | | | | 15,884 | | | | — | | | | 15,884 | | | | 17,951 | |
| Merger goodwill | | 2046 | | | — | | | | 293,199 | | | | — | | | | 293,199 | | | | 281,739 | |
| California restructure costs | | Thru 2009 | | | 979 | | | | 880 | | | | — | | | | 1,859 | | | | 2,459 | |
| Conservation programs | | Thru 2012 | | | 2,574 | | | | — | | | | 50,701 | | | | 53,275 | | | | 24,144 | |
| Legal Costs | | | | | — | | | | — | | | | 8,376 | | | | 8,376 | | | | 9,558 | |
| Other costs | | Thru 2017 | | | 1,708 | | | | 2,363 | | | | 3,892 | | | | 7,963 | | | | 10,544 | |
| | | | | | | | | | | | | | | | | | |
| Subtotal | | | | $ | 187,637 | | | $ | 347,397 | | | $ | 133,590 | | | $ | 668,624 | | | $ | 568,145 | |
| | | | | | | | | | | | | | | | | | | |
| Pensions-SFAS 158 | | | | | — | | | | — | | | | 223,218 | | | | 223,218 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory assets | | | | $ | 187,637 | | | $ | 347,397 | | | $ | 356,808 | | | $ | 891,842 | | | $ | 568,145 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Regulatory Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| Cost of Removal | | Various | | $ | 283,641 | | | $ | — | | | $ | — | | | $ | 283,641 | | | $ | 246,960 | |
| Gain on Property Sales | | Various thru 2008 | | | 4,531 | | | | — | | | | — | | | | 4,531 | | | | 11,285 | |
| SO2 Allowances | | Various thru 2012 | | | 745 | | | | — | | | | — | | | | 745 | | | | 536 | |
| Gas Transportation Contract | | | | | — | | | | — | | | | — | | | | — | | | | 17,542 | |
| Plant liability | | 2008 | | | 1,038 | | | | — | | | | — | | | | 1,038 | | | | 2,049 | |
| Impact Charge | | 2008 | | | 2,722 | | | | — | | | | — | | | | 2,722 | | | | 6,066 | |
| Depreciation-Customer Advances | | | | | — | | | | — | | | | 8,775 | | | | 8,775 | | | | — | |
| Other | | 2008 | | | — | | | | 326 | | | | 125 | | | | 451 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory liabilities | | | | $ | 292,677 | | | $ | 326 | | | $ | 8,900 | | | $ | 301,903 | | | $ | 284,438 | |
| | | | | | | | | | | | | | | | | | |
118
NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
| | | | | | | | | | | | | | | | | | | | | | | |
| | | AS OF DECEMBER 31, 2006 | | | As of | |
| | | Remaining | | Receiving Regulatory Treatment | | | Pending | | | | | | | December | |
| (dollars in thousands) | | Amortization | | Earning a | | | Not Earning | | | Regulatory | | | 2006 | | | 31, 2005 | |
| DESCRIPTION | | Period | | Return (1) | | | a Return | | | Treatment | | | Total | | | Total | |
| Regulatory Assets | | | | | | | | | | | | | | | | | | | | | | |
| Loss on reacquired debt | | Term of Related Debt | | $ | 60,026 | | | $ | — | | | $ | — | | | $ | 60,026 | | | $ | 39,392 | |
| Lenzie | | | | | — | | | | — | | | | 52,456 | | | | 52,456 | | | | — | |
| Mohave plant and deferred costs | | 2026 | | | 21,582 | | | | — | | | | (3,747 | ) | | | 17,835 | | | | 28,280 | |
| Clark Units 1-3 | | Various thru 2015 | | | 11,545 | | | | — | | | | 5,190 | | | | 16,735 | | | | 13,136 | |
| Asset Retirement Obligations | | | | | — | | | | — | | | | 11,081 | | | | 11,081 | | | | 10,204 | |
| Nevada divestiture costs | | 2012 | | | 14,665 | | | | — | | | | — | | | | 14,665 | | | | 17,459 | |
| Merger transition/transaction costs | | 2014 | | | — | | | | 20,237 | | | | — | | | | 20,237 | | | | 22,838 | |
| Merger severance/relocation | | 2014 | | | — | | | | 7,397 | | | | — | | | | 7,397 | | | | 8,417 | |
| Merger Goodwill | | 2044 | | | — | | | | 184,386 | | | | — | | | | 184,386 | | | | 189,088 | |
| Conservation programs | | | | | — | | | | — | | | | 42,636 | | | | 42,636 | | | | 19,048 | |
| Legal Costs | | | | | — | | | | — | | | | 8,376 | | | | 8,376 | | | | 9,558 | |
| Other costs | | 2008 | | | 649 | | | | — | | | | 3,890 | | | | 4,539 | | | | 5,147 | |
| | | | | | | | | | | | | | | | | | |
| Subtotal | | | | $ | 108,467 | | | $ | 212,020 | | | $ | 119,882 | | | $ | 440,369 | | | $ | 362,567 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Pensions-SFAS 158 | | | | | — | | | | — | | | $ | 113,646 | | | $ | 113,646 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory assets | | | | $ | 108,467 | | | $ | 212,020 | | | $ | 233,528 | | | $ | 554,015 | | | $ | 362,567 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Regulatory Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| Cost of Removal | | Various | | $ | 162,196 | | | $ | — | | | $ | — | | | $ | 162,196 | | | $ | 144,164 | |
| Gain on Property Sales | | Various thru 2008 | | | 4,531 | | | | — | | | | — | | | | 4,531 | | | | 11,285 | |
| SO2 Allowances | | Various thru 2012 | | | 745 | | | | — | | | | — | | | | 745 | | | | 536 | |
| Gas Transportation Contract | | | | | — | | | | — | | | | — | | | | — | | | | 17,542 | |
| Depreciation-Customer Advances | | | | | — | | | | — | | | | 3,701 | | | | 3,701 | | | | — | |
| Other | | | | | — | | | | — | | | | 125 | | | | 125 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory liabilities | | | | $ | 167,472 | | | $ | — | | | $ | 3,826 | | | $ | 171,298 | | | $ | 173,527 | |
| | | | | | | | | | | | | | | | | | |
119
SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES
| | | | | | | | | | | | | | | | | | | | | | | |
| | | AS OF DECEMBER 31, 2006 | | | As of | |
| | | Remaining | | Receiving Regulatory Treatment | | | Pending | | | | | | | December | |
| (dollars in thousands) | | Amortization | | Earning a | | | Not Earning | | | Regulatory | | | 2006 | | | 31, 2005 | |
| DESCRIPTION | | Period | | Return (1) | | | a Return | | | Treatment | | | Total | | | Total | |
| Regulatory assets | | | | | | | | | | | | | | | | | | | | | | |
| Loss on reacquired debt | | Term of Related Debt | | $ | 27,128 | | | $ | — | | | $ | — | | | $ | 27,128 | | | $ | 18,412 | |
| Piñon Pine | | Various thru 2029 | | | 35,236 | | | | 6,155 | | | | 610 | | | | 42,001 | | | | 43,502 | |
| Plant assets | | Various thru 2031 | | | 2,876 | | | | — | | | | — | | | | 2,876 | | | | 3,058 | |
| Asset Retirement Obligations | | | | | — | | | | — | | | | 5,031 | | | | 5,031 | | | | 4,700 | |
| Nevada divestiture costs | | 2012 | | | 9,318 | | | | — | | | | — | | | | 9,318 | | | | 11,038 | |
| Merger transition/transaction costs | | 2016 | | | — | | | | 8,679 | | | | — | | | | 8,679 | | | | 9,731 | |
| Merger severance/relocation | | 2016 | | | — | | | | 8,487 | | | | — | | | | 8,487 | | | | 9,534 | |
| Merger goodwill | | 2046 | | | — | | | | 108,813 | | | | — | | | | 108,813 | | | | 92,651 | |
| California Restructure Costs | | Thru 2009 | | | 979 | | | | 880 | | | | — | | | | 1,859 | | | | 2,459 | |
| Conservation Programs | | Thru 2012 | | | 2,574 | | | | — | | | | 8,065 | | | | 10,639 | | | | 5,096 | |
| Other costs | | Various thru 2017 | | | 1,059 | | | | 2,363 | | | | 2 | | | | 3,424 | | | | 5,397 | |
| | | | | | | | | | | | | | | | | | |
| Subtotal | | | | $ | 79,170 | | | $ | 135,377 | | | $ | 13,708 | | | $ | 228,255 | | | $ | 205,578 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Pensions-SFAS 158 | | | | | — | | | | — | | | | 106,666 | | | | 106,666 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory assets | | | | $ | 79,170 | | | $ | 135,377 | | | $ | 120,374 | | | $ | 334,921 | | | $ | 205,578 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Regulatory Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| |
| Cost of Removal | | Various | | $ | 121,445 | | | $ | — | | | $ | — | | | $ | 121,445 | | | $ | 102,796 | |
| Plant liability | | 2008 | | | 1,038 | | | | — | | | | — | | | | 1,038 | | | | 2,049 | |
| Impact Charge | | 2008 | | | 2,722 | | | | — | | | | — | | | | 2,722 | | | | 6,066 | |
| Depreciation-Customer Advances | | | | | — | | | | — | | | | 5,074 | | | | 5,074 | | | | — | |
| Other | | 2008 | | | — | | | | 326 | | | | — | | | | 326 | | | | — | |
| | | | | | | | | | | | | | | | | | |
| Total regulatory liabilities | | | | $ | 125,205 | | | $ | 326 | | | $ | 5,074 | | | $ | 130,605 | | | $ | 110,911 | |
| | | | | | | | | | | | | | | | | | |
(1) Earning a return includes either a carrying charge on the asset / liability balance, or a return as a component of weighted cost of capital.
Deferral of Energy Costs
Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel, and purchased power.
In January 2000, in accordance with a PUCN order, SPPC resumed using deferred energy accounting for its gas operations.
In April 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369 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 in March 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.
Pursuant to AB 369, Nevada Revised Statute (NRS) 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, NRS 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.
120
The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):
| | | | | | | | | | | | | | | | | | | |
| | | | | December 31, 2006 | |
| | | | | NPC | | | SPPC | | | SPPC | | | SPR | |
| Description | | | | Electric | | | Electric | | | Gas | | | Total | |
| Unamortized balances approved for collection in current rates | | | | | | | | | | | | | | | | |
| Electric — NPC Period 1 | | (Reinstatement of deferred energy)(1) | | $ | 178,825 | | | $ | — | | | $ | — | | | $ | 178,825 | |
| Electric — NPC Period 3 | | (effective 4/05, 2 years) | | | (4,067 | ) | | | — | | | | — | | | | (4,067 | ) |
| Electric — SPPC Period 3 | | (effective 6/05, 27 months) | | | — | | | | 6,034 | | | | — | | | | 6,034 | |
| Electric — NPC Period 4 | | (effective 4/05, 2 years) | | | 6,347 | | | | — | | | | — | | | | 6,347 | |
| Electric — NPC Period 5 | | (effective 8/06, 2 years) | | | 153,720 | | | | — | | | | — | | | | 153,720 | |
| Electric — SPPC Period 5 | | (effective 7/06, 2 years) | | | — | | | | 27,657 | | | | — | | | | 27,657 | |
| Nat. Gas — Per 6, LPG — Per 5 | | (effective 12/06, 1 year) | | | — | | | | — | | | | 902 | | | | 902 | |
| Balances pending PUCN approval | | | | | 72,280 | | | | 16,220 | | | | — | | | | 88,500 | |
| Cumulative CPUC Balance | | | | | — | | | | 9,956 | | | | — | | | | 9,956 | |
| Balances accrued since end of periods submitted for PUCN approval | | | 1,693 | | | | (14,479 | ) | | | (1,014 | ) | | | (13,800 | ) |
Claims for terminated supply contracts(2) | | | | | 80,095 | | | | 16,265 | | | | — | | | | 96,360 | |
| | | | | | | | | | | | | | | |
| Total | | | | $ | 488,893 | | | $ | 61,653 | | | $ | (112 | )(3) | | $ | 550,434 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Current Assets | | | | | | | | | | | | | | | | | | |
| Deferred energy costs — electric | | | | $ | 129,304 | | | $ | 38,956 | | | $ | — | | | $ | 168,260 | |
| Deferred Assets | | | | | | | | | | | | | | | | | | |
| Deferred energy costs — electric | | | | | 359,589 | | | | 22,697 | | | | — | | | | 382,286 | |
| Current Liabilities Deferred energy costs — gas | | | | | — | | | | — | | | | (112 | ) | | | (112 | ) |
| | | | | | | | | | | | | | | |
| Total | | | | $ | 488,893 | | | $ | 61,653 | | | $ | (112 | ) | | $ | 550,434 | |
| | | | | | | | | | | | | | | |
121
| | | | | | | | | | | | | | | | | | | |
| | | | | December 31, 2005 | |
| | | | | NPC | | | SPPC | | | SPPC | | | SPR | |
| Description | | | | Electric | | | Electric | | | Gas | | | Total | |
| Unamortized balances approved for collection in current rates | | | | | | | | | | | | | | | | |
| Electric — NPC Period 2 | | (effective 5/03, 3 years) | | $ | (1,199 | ) | | $ | — | | | $ | — | | | $ | (1,199 | ) |
| Electric — NPC Period 3 | | (effective 4/05, 2 years) | | | 48,564 | | | | — | | | | — | | | | 48,564 | |
| Electric — SPPC Period 3 | | (effective 6/05, 27 months) | | | — | | | | 23,208 | | | | — | | | | 23,208 | |
| Electric — NPC Period 4 | | (effective 4/05, 2 years) | | | 71,490 | | | | — | | | | — | | | | 71,490 | |
| Electric — SPPC Period 4 | | (effective 6/05, 1 year) | | | — | | | | 9,101 | | | | — | | | | 9,101 | |
| Natural Gas — Period 5 | | (effective 11/05, 1 year) | | | — | | | | — | | | | 4,454 | | | | 4,454 | |
| LPG Gas Period 3 | | (effective 11/04, 2 years) | | | — | | | | — | | | | 36 | | | | 36 | |
| LPG Gas Period 4 | | (effective 11/05, 1 year) | | | — | | | | — | | | | 130 | | | | 130 | |
| Balances pending PUCN approval | | | | | 171,447 | | | | 41,180 | | | | — | | | | 212,627 | |
| Cumulative CPUC Balance | | | | | — | | | | 6,699 | | | | — | | | | 6,699 | |
| Balances accrued since end of periods submitted for PUCN approval | | | 26,647 | | | | 6,768 | | | | 2,050 | | | | 35,465 | |
Claims for terminated supply contracts(2) | | | | | 83,993 | | | | 21,111 | | | | — | | | | 105,104 | |
| | | | | | | | | | | | | | | |
| Total | | | | $ | 400,942 | | | $ | 108,067 | | | $ | 6,670 | | | $ | 515,679 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Current Assets | | | | | | | | | | | | | | | | | | |
| Deferred energy costs — electric | | | | $ | 186,355 | | | $ | 67,342 | | | $ | — | | | $ | 253,697 | |
| Deferred energy costs — gas | | | | | — | | | | — | | | | 5,825 | | | | 5,825 | |
| Deferred Assets | | | | | | | | | | | | | | | | | | |
| Deferred energy costs — electric | | | | | 214,587 | | | | 40,725 | | | | — | | | | 255,312 | |
| Deferred energy costs — gas | | | | | — | | | | — | | | | 845 | | | | 845 | |
| | | | | | | | | | | | | | | |
| Total | | | | $ | 400,942 | | | $ | 108,067 | | | $ | 6,670 | | | $ | 515,679 | |
| | | | | | | | | | | | | | | |
| | |
| (1) | | Amount not in current rates. As discussed in Note 13, Commitments and Contingencies, Nevada Power Company 2001 Deferred Energy Case. |
| |
| (2) | | Amounts related to claims for terminated supply contracts are discussed in Note 13, Commitments and Contingencies. |
| |
| (3) | | 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 |
Carrying Charge on the Lenzie Generating Station
In 2004, the Public Utility Commission of Nevada (PUCN) granted NPC’s request to designate the Chuck Lenzie Generating Station (“Lenzie”) as a critical facility and allowed a 2% enhanced Return on Equity (ROE) to be applied to the Lenzie construction costs expended after acquisition. The order allowed for an additional 1% enhanced ROE if the two Lenzie generating units were brought on line early. In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”), until the plant is included in rates.
Units 1 and 2 were declared commercially operable in January 2006 and April 2006, respectively, qualifying for the incentive ROE treatment. Based on the regulatory order, through December 31, 2006, NPC has accumulated approximately $38.9 million in carrying charges; however, $5.5 million of this amount has not been recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through regulated rates. For financial reporting purposes, through December 31, 2006, NPC recognized $33.4 million in other income, and recorded a corresponding regulatory asset, which represents only the carrying charge component associated with incurred debt costs. NPC has requested recovery of the $38.9 million in carrying charges its 2006 general rate case filed in November 2006.
Utility Plant
The cost of additions, including betterments and replacements of units of property, are charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The cost of current repairs and minor replacements are charged to maintenance expense when incurred, with the exception of long term service agreements. These agreements may have annual payment amounts for repairs which could vary over the life of the agreement between maintenance expense and amounts to be capitalized. To ensure consistency in annual expense for
122
rate making purposes, the amounts to be charged to maintenance expense are smoothed over the life of the contract, with an offset to a regulatory asset account. Amounts prepaid for capital expenditure are recorded in a prepaid asset account.
In addition to direct labor and material costs, certain other direct and indirect costs are capitalized. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, post retirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC) which includes the cost of debt and equity capital associated with construction activity.
Allowance for Funds Used During Construction
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, however, 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 rate used during 2006, 2005 and 2004 was 9.03%. SPPC’s AFUDC rates used during 2006, 2005 and 2004 were 8.97%, 8.96%, and 9.26% respectively. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific 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. Depreciation expense 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 2006, 2005, and 2004, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 3.15%, 3.15% and 3.05% respectively. SPPC’s depreciation provision for 2006, 2005 and 2004, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 3.08%, 3.3% and 3.35% respectively.
Impairment of Long-Lived Assets
SPR, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in SFAS No. 144 “Accounting for the Disposal or Impairment of Long-Lived Assets.” (SFAS 144) See Note 17, Discontinued Operations and Disposal and Impairment of Long-Lived Assets.
Accounting For Goodwill
SFAS No. 142 “Goodwill and Other Intangible Assets”, adopted by SPR, NPC and SPPC in January 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. See Note 18, Goodwill and Other Merger Costs, for further discussion.
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.
Restricted Cash
At December 31, 2005, SPR had approximately $67.2 million of restricted cash in SPR’s consolidated balance sheets, primarily consisting of an aggregate $49 million and $11 million in cash collateral deposited by NPC and SPPC, respectively, into escrow in connection with the stay of the Enron Judgment, as described in Note 13, Commitments and Contingencies. The cash collateral plus interest was returned to the Utilities in January 2006.
123
Federal Income Taxes
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. 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 basis 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.
Deferred investment tax credits are being amortized over the estimated service lives of the related properties. Investment tax credits are no longer available to the Utilities.
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. Accounts receivable as of December 31, 2006, include unbilled receivables of $92 million and $83 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2005, include unbilled receivables of $80 million and $77 million for NPC and SPPC, respectively.
Asset Retirement Obligations
SFAS No. 143 “Accounting for Asset Retirement Obligations” provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are 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 is classified as 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. SPR, NPC and SPPC adopted SFAS No. 143 in January 2003.
Management’s methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. Management 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. Provisions of the lease require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases.
In March, 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 as clarification to SFAS No. 143. This Interpretation was effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises). The Interpretation clarified the term conditional retirement obligation as used in SFAS No. 143 as well as when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
Similar to the methodology used to assess legal obligations under SFAS 143, management reviewed the inventory of assets by system and components, as well as rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. Management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations of FIN 47.
124
As such, included in NPC’s and SPPC’s Other Liabilities accounts as of December 31, 2006 are approximately $12.9 million and $5.3 million of ARO’s. As of December 31, 2005, the amounts were approximately $12.1 million and $5.0 million. As the Utilities are subject to SFAS 71, accounting treatment, the cumulative effect of these ARO’s were recorded in Other Regulatory Assets.
Cost of Removal
In addition to the legal asset retirement obligations booked under SFAS 143 and FIN 47, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets, in accordance with accepted accounting practices. The amounts of such accruals included in regulatory liabilities in 2006 are approximately $162 million and $121 million for NPC and SPPC, respectively. In 2005, the amounts were approximately $144 million and $103 million.
Variable Interest Entities
In December 2003, the FASB issued a revised Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46 (R)), which elaborates on Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” Among other requirements, FIN 46 (R) provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. As of December 2003, SPR, NPC and SPPC adopted FIN 46 (R) for special purpose entities. As of March 2004, SPR, NPC and SPPC adopted FIN 46 (R) for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with qualifying facilities (QFs), jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven QFs with long-term purchase power contracts that are variable interests. However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FIN 46 (R) due to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary. The Utilities have requested financial information from these QFs but have not been successful in obtaining the information. The Utilities’ maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. The Utilities have not identified any other significant variable interests that require consolidation as of December 31, 2006.
Recent Pronouncements
SFAS 123 (R)
SPR adopted Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share Based Payment” (SFAS 123 R) in the first quarter of 2006 using the modified prospective method. The Company had previously applied the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, in accounting for its stock compensation plans and in accordance with the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”, and the updated disclosure requirements set forth in SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure”. Accordingly, no compensation cost had been recognized previously.
SPR’s executive long-term incentive plan for key management employees permits the following types of grants, separately or in combination: non-qualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares and bonus stock. SPR currently issues Performance Shares and Non Qualified Stock Options (NQSO) under this plan. In addition, the Company also has an Employee Stock Purchase Plan (ESPP). Please refer to Note 12, Stock Compensation Plans in the Notes to Consolidated Financial Statements for additional information.
The adoption of SFAS 123 (R) did not have a material impact on the results of operations for SPR.
SFAS 157
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for SPR and the Utilities beginning January 2008. SPR and the Utilities are currently evaluating the impact of the adoption of SFAS 157 on their consolidated financial statements.
SFAS 158
In September 2006, the FASB issued SFAS 158 (“SFAS 158”) “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132-(R).”
125
SFAS 158 requires SPR and the Utilities to recognize the overfunded or underfunded status of defined benefit postretirement plans in their Consolidated Balance Sheets. An overfunded status would result in the recognition of an asset and an underfunded status would result in the recognition of a liability. The adjustment to record an asset or liability would result in a charge or credit to Accumulated Other Comprehensive Income (AOCI), net of income tax effects. SFAS 158’s requirement to recognize the funded status of a benefit plan and new disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SPR and the Utilities have recorded amounts that otherwise would be charged/credited to AOCI upon application of SFAS 158 as Other Regulatory Asset/Liabilities as they believe these amounts will be recovered through rates similar to expenses related to SFAS 87 Employers’ Accounting for Pensions and SFAS 106 Employers’ Accounting for Other Postretirement Expense other than Pensions. At December 31, 2006, SPR, NPC and SPPC recorded $223.2 million, $113.6 million and $106.7 million, respectively in Other Regulatory Assets.
The following tables provide details of the effects of implementing SFAS Statement No. 158 (dollars in thousands):
Pension
Incremental effect of adopting SFAS No. 158 as of December 31, 2006
| | | | | | | | | | | | | | | | | |
| | | | | | | Adjustments to | | | Regulatory | | | | |
| | | Before | | | Adopt SFAS | | | Accounting | | | Balance after | |
| | | Adoption | | | 158 | | | Adjustments | | | Adoption | |
| ASSETS | | | | | | | | | | | | | | | | |
| Non-current Benefit Asset | | $ | 55,921 | | | $ | (55,921 | ) | | $ | — | | | $ | — | |
| Regulatory Asset | | $ | — | | | $ | — | | | $ | 114,261 | | | $ | 114,261 | |
| | | | | | | | | | | | | | | | | |
| LIABILITIES | | | | | | | | | | | | | | | | |
| Current Benefit Liability | | $ | — | | | $ | (1,482 | ) | | $ | — | | | $ | (1,482 | ) |
| Non-current Benefit Liability | | $ | (9,809 | ) | | $ | (99,454 | ) | | $ | — | | | $ | (109,263 | ) |
| | | | | | | | | | | | | | | | | |
| SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | |
| Accumulated Other Comprehensive (Income) Loss | | $ | (46,112 | ) | | $ | 156,857 | | | $ | (114,261 | ) | | $ | (3,516 | ) |
Other Benefits
Incremental effect of adopting SFAS No. 158 as of December 31, 2006
| | | | | | | | | | | | | | | | | |
| | | | | | | Adjustments to | | | Regulatory | | | | |
| | | Before | | | Adopt SFAS | | | Accounting | | | Balance after | |
| | | Adoption | | | 158 | | | Adjustment | | | Adoption | |
| ASSETS | | | | | | | | | | | | | | | | |
| Non-current Benefit Asset | | $ | 10,182 | | | $ | (10,182 | ) | | $ | — | | | $ | — | |
| Regulatory Asset | | $ | — | | | $ | — | | | $ | 108,956 | | | $ | 108,956 | |
| | | | | | | | | | | | | | | | | |
| LIABILITIES | | | | | | | | | | | | | | | | |
| Non-current Benefit Liability | | $ | (52,778 | ) | | $ | (56,178 | ) | | $ | — | | | $ | (108,956 | ) |
| | | | | | | | | | | | | | | | | |
| SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | |
| Accumulated Other Comprehensive (Income) Loss | | $ | 42,596 | | | $ | 66,360 | | | $ | (108,956 | ) | | $ | — | |
At December 31, 2006 SPR, NPC and SPPC recorded pension liabilities of $110.7 million, $66.1 million and $34.9 million, respectively, as a result of the adoption of SFAS No. 158. In addition, SPR, NPC and SPPC also recorded liabilities of $109.0 million, $21.5 million and $87.9 million, respectively, for the other postretirement benefit plan as a result of the adoption of SFAS No. 158. At December 31, 2005 SPR, NPC and SPPC had pension liabilities of $16.4 million, $4.0 million and $5.8 million, respectively, and additional minimum liabilities of $7.9 million, $4.4 million and $2.8 million, respectively, under the provisions of SFAS No. 87 for the pension plan. SPR, NPC and SPPC had liabilities of $36.3 million, $14.1 million and $31.7 million, respectively, at December 31, 2005 for the other post retirement benefit plan.
FIN 46(R)-6
In April 2006, the FASB issued FASB Staff Position (“FSP”) FIN 46R-6,Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R).This FSP addresses certain implementation issues related to FASB Interpretation No. 46 (Revised December 2003),Consolidation of Variable Interest Entities.Specifically, FSP FIN 46R-6 addresses how a reporting enterprise should determine the variability to be considered in applying FIN 46R. The variability that is considered in applying FIN 46R affects the determination of (a) whether an entity is a variable interest entity (“VIE”), (b) which interests are “variable interests” in the entity, and (c) which party, if any, is the primary beneficiary of the VIE. That variability affects any calculation of expected losses and expected residual returns, if such a calculation is necessary. SPR and the Utilities are required to apply the guidance in this FSP prospectively to all entities (including newly created entities) and to all entities previously required to be analyzed under FIN 46R when a “reconsideration event” has occurred, beginning July 2006. SPR and the Utilities will evaluate the impact of this Staff Position at the time any such “reconsideration event” occurs, and for any new entities.
FIN 48
In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”, to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006. SPR and the Utilities are in the process of evaluating the impact FIN 48 will have on their consolidated financial statements.
SAB 108
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108), to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires that SPR and the Utilities quantify misstatements based on their impact on each of its financial statements and related disclosures. SAB 108 is effective as of December 31, 2006, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have an effect on the consolidated financial statements of SPR or the Utilities.
126
NOTE 2. SEGMENT INFORMATION
SPR’s Utilities operate three business segments (as defined by SFAS 131, “Disclosure about Segments of an Enterprise and Related Information”); which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.
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 (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | NPC | | SPPC | | Total | | | | | | | | | | Reconciling | | |
| December 31, 2006 | | Electric | | Electric | | Electric | | Gas | | All Other | | Eliminations | | Consolidated |
| Operating Revenues | | $ | 2,124,081 | | | $ | 1,020,162 | | | | 3,144,243 | | | $ | 210,068 | | | $ | 1,639 | | | | — | | | $ | 3,355,950 | |
| Operating income | | | 351,272 | | | | 108,908 | | | | 460,180 | | | | 11,109 | | | | 17,508 | | | | — | | | | 488,797 | |
| Operating income taxes | | | 91,781 | | | | 20,020 | | | | 111,801 | | | | 3,550 | | | | (23,780 | ) | | | — | | | | 91,571 | |
| Depreciation | | | 141,585 | | | | 79,580 | | | | 221,165 | | | | 7,699 | | | | 11 | | | | — | | | | 228,875 | |
| Interest expense on long term debt | | | 171,188 | | | | 66,416 | | | | 237,604 | | | | 5,453 | | | | 51,431 | | | | — | | | | 294,488 | |
| Assets | | | 5,987,515 | | | | 2,476,483 | | | | 8,463,998 | | | | 275,294 | | | | 36,724 | | | | 56,060 | | | | 8,832,076 | |
| Capital expenditures | | | 670,441 | | | | 282,641 | | | | 953,082 | | | | 32,937 | | | | — | | | | — | | | | 986,019 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | NPC | | | SPPC | | | Total | | | | | | | | | | | Reconciling | | | | |
| December 31, 2005 | | Electric | | | Electric | | | Electric | | | Gas | | | All Other | | | Eliminations | | | Consolidated | |
| Operating Revenues | | $ | 1,883,267 | | | $ | 967,427 | | | $ | 2,850,694 | | | $ | 178,270 | | | $ | 1,278 | | | | — | | | $ | 3,030,242 | |
| Operating income | | | 228,827 | | | | 107,213 | | | | 336,040 | | | | 9,091 | | | | 13,547 | | | | — | | | | 358,678 | |
| Operating income taxes | | | 46,425 | | | | 24,209 | | | | 70,634 | | | | 1,829 | | | | (33,278 | ) | | | — | | | | 39,185 | |
| Depreciation | | | 124,098 | | | | 82,676 | | | | 206,774 | | | | 7,893 | | | | (5 | ) | | | — | | | | 214,662 | |
| Interest expense on long term debt | | | 159,106 | | | | 63,040 | | | | 222,146 | | | | 6,200 | | | | 74,322 | | | | — | | | | 302,668 | |
| Assets | | | 5,173,921 | | | | 2,218,938 | | | | 7,392,859 | | | | 245,707 | | | | 150,324 | | | | 81,656 | | | | 7,870,546 | |
| Capital expenditures | | | 546,748 | | | | 121,767 | | | | 668,515 | | | | 17,879 | | | | — | | | | — | | | | 686,394 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | NPC | | | SPPC | | | Total | | | | | | | | | | | Reconciling | | | | |
| December 31, 2004 | | Electric | | | Electric | | | Electric | | | Gas | | | All Other | | | Eliminations | | | Consolidated | |
| Operating Revenues | | $ | 1,784,092 | | | $ | 881,908 | | | $ | 2,666,000 | | | $ | 153,752 | | | $ | 5,044 | | | | — | | | $ | 2,824,796 | |
| Operating income | | | 216,490 | | | | 103,513 | | | | 320,003 | | | | 7,732 | | | | 6,123 | | | | — | | | | 333,858 | |
| Operating income taxes | | | 45,135 | | | | 12,740 | | | | 57,875 | | | | 2,238 | | | | (37,374 | ) | | | — | | | | 22,739 | |
| Depreciation | | | 118,841 | | | | 79,298 | | | | 198,139 | | | | 7,508 | | | | 275 | | | | — | | | | 205,922 | |
| Interest expense on long term debt | | | 152,764 | | | | 64,729 | | | | 217,493 | | | | 6,583 | | | | 89,229 | | | | — | | | | 313,305 | |
| Assets | | | 4,883,540 | | | | 2,226,949 | | | | 7,110,489 | | | | 232,092 | | | | 120,607 | | | | 65,279 | | | | 7,528,467 | |
| Capital expenditures | | | 482,484 | | | | 117,329 | | | | 599,813 | | | | 14,598 | | | | — | | | | — | | | | 614,411 | |
The reconciliation of segment assets at December 31, 2006, 2005, and 2004 to the consolidated total includes the following unallocated amounts:
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Cash | | $ | 53,260 | | | $ | 53,024 | | | $ | 35,783 | |
| Other regulatory assets | | | — | | | | 19,265 | | | | 21,124 | |
| Deferred charges-other | | | 2,800 | | | | 9,367 | | | | 8,372 | |
| | | | | | | | | | |
| | | $ | 56,060 | | | $ | 81,656 | | | $ | 65,279 | |
| | | | | | | | | | |
127
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 (IRPs) to the PUCN for approval.
Under federal law, the Utilities 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 Department of Air Quality and Environmental Management (DAQEM) 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
The Utilities began using deferred energy accounting for their respective electric operations in March 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel.
Nevada Matters
Nevada Power Company
2006 General Rate Case
In November 2006, NPC filed its statutorily required electric general rate case. This filing request authorization to:
| | • | | Increase annual general revenues by $172.4 million which is approximately an 8% increase |
| |
| | • | | Set the Return on Equity and Rate of Return at 11.40% and 9.41%, respectively |
| |
| | • | | Recover 100% of the amortization of the 1999 NPC/SPPC merger costs rather than the 80% recovery that is currently in general rates |
| |
| | • | | Implement the PUCN’s previous orders regarding incentive ratemaking for the Chuck Lenzie Generating Station |
| |
| | • | | Implement new depreciation rates |
Hearings are scheduled to take place in late March and early April of 2007 with rates expected to be effective on or before June 1, 2007.
In February 2007, NPC submitted its certification filing which lowered the requested ROR to 9.39% and the general revenues increase was lowered to $156.4 million, representing an overall rate increase of 7.4%.
2007 Deferred Energy Rate Case and BTER Update
In January 2007, NPC filed an electric DEAA rate case and BTER update application with the PUCN. The application seeks recovery of $75 million of deferred fuel and purchased power costs and requested to reset NPC’s going forward BTER to reflect anticipated changes in future energy costs. This application requests a 1.6% decrease in overall rates.
2007 Western Energy Crisis Rate Case
In January 2007, NPC filed an application to recover $83.6 million over four years in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the western energy crisis. This application requests an overall rate increase of less than 1%.
In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the $83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation is expressly conditioned upon the PUCN’s acceptance of the
128
concurrently filed stipulation related to NPC’s 2001 Deferred Energy Case, discussed below. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
2006 Deferred Energy Rate Case and BTER Update
In January 2006, NPC filed a DEAA rate case with the PUCN seeking recovery of deferred fuel and purchased power costs accumulated between October 1, 2004 and November 30, 2005, and to increase its going forward Base Tariff Energy Rate (BTER) to reflect anticipated changes in future energy costs. NPC requested a one year amortization period to recover the deferred balance.
NPC requested that the BTER increase become effective on May 1, 2006. The BTER change represented an 8% increase for the average customer and is expected to generate $138 million of new revenues for fuel and power purchases.
NPC requested authorization to begin a one year recovery of the $171.5 million deferred balance in August 2006. The requested DEAA adjustment represents an additional rate increase of approximately 9.3%.
In April 2006, the PUCN approved an agreement among the interveners and NPC, which, effective May 1, 2006, set NPC’s BTER rates such that an estimated $112 million (revised by June 2006 DEAA agreement – see below) of new revenues would be collected for fuel and power purchases in addition to the start of an $8.4 million collection related to a previous DEAA rate case. Combined, the approximately $120 million increase represented an overall average rate increase of approximately 6.5%.
In the Deferred Energy portion of the case, NPC had requested authorization to recover $171.5 million of previously incurred purchased fuel and power costs over a one year period. In June 2006, the PUCN approved a negotiated settlement, which specified (1) a reduction of $1.6 million to the BTER approved in April 2006 based on an updated projection of costs and (2) granted NPC full recovery of the $171.5 million of deferred costs during a two year period beginning August 2006. However, the $171.5 million was reduced by a $16.5 million payment previously received by NPC in connection with the Lenzie acquisition. Under this agreement, the DEAA rate changes required to asymmetrically recover the deferred balance are scheduled to be implemented during a two year period such that they will be offset by the expiration of previously approved DEAA rates. As a result, no rate increase was required.
2005 BTER Update
In June 2005, NPC filed a request to increase its BTER to reflect forecasted energy costs. NPC expected the request would increase revenue by $66.9 million for the 12 month period October 1, 2005 to September 30, 2006 and more closely correlate fuel and purchased power revenues with fuel and purchased power costs. In September 2005, the PUCN issued an order approving the BTER rate changes requested in NPC’s filing.
2004 Deferred Energy Rate Case
In November 2004, NPC filed an application with the PUCN seeking recovery of deferred fuel and purchased power costs accumulated between October 1, 2003 and September 30, 2004. The application sought to establish a rate to collect accumulated fuel and purchased power costs of $116 million, with a carrying charge. The application requested that the 2004 DEAA recovery begin with the expiration of the 2002 DEAA recovery, which was expected to occur in May 2006 and for the 2004 DEAA recovery period to be 22 months.
The application also requested an increase to NPC’s BTER.
In concert with this 2004 DEAA filing, NPC filed a petition with the PUCN requesting that other pending DEAA rate changes be synchronized to change in April 2005 in order to stabilize rates and reduce the number of rate changes. In December 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer previously approved DEAA rate changes until April 2005 coincident with the DEAA rate change that will result from the 2004 DEAA case.
The combined effect of the requested synchronization of multiple rate changes (going forward BTER increase, 2001 DEAA expiration, and 2003 DEAA initiation) resulted in a request for an overall rate decrease of 2.4%.
In February 2005, a stipulation of the parties was filed with the PUCN resolving all issues in the case. The stipulation provided for an overall decrease of 0.6% in total rates with no disallowances. The PUCN approved the stipulation in total in March 2005.
2003 Deferred Energy Rate Case
In November 2003, NPC filed an application with the PUCN seeking recovery of deferred fuel and purchased power costs accumulated between October 1, 2002 and September 30, 2003, as required by law. The application sought to establish a rate to collect accumulated fuel and purchased power costs of $93 million. In March 2004, the PUCN granted approval for NPC to increase
129
its going forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4 million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of the $4 million disallowed, $1.6 million was charged to income in the current period as the remaining amount had no impact on earnings or was charged to income in prior periods. The PUCN ordered the change in going forward rates to take effect April 2004 and delayed the implementation of the deferred energy balance recovery until January 2005 when recovery of the 2001 deferred balance was expected to have been completed.
In December 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer the 2003 DEAA rate change until April 2005, which will be coincident with the DEAA rate change that will result from the 2004 DEAA case.
2002 Deferred Energy Rate Case
In November 2002, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application sought to establish a rate to collect 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 requested a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments resulted in a request for an overall rate reduction of approximately 6.3%.
The decision on this case was issued in May 2003, and authorized the following:
| | • | | recovery of $147.6 million, with a carrying charge, and a $48.1 million disallowance; |
| |
| | • | | a three-year amortization of the balance commencing on May 19, 2003; |
| |
| | • | | a reduction in the Base Tariff Energy Rate (BTER) to an effective non-residential rate of $0.04322 per kWh, and an effective residential rate of $0.04186 per kWh. |
The new rates went into effect in May 2003.
The BCP filed a Petition that challenged the recovery of all costs with the District Court of Clark County, Nevada, for Judicial Review of the PUCN Order in August 2003, against PUCN, Case No. A471928. In September 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites a number of affirmative defenses to the allegations contained in the BCP petition and asks that the court dismiss the BCP petition. The BCP filed its opening brief in January 2004 and responding briefs were filed in March 2004. The court has not yet ruled on this matter.
2001 Deferred Energy Rate Case
In November 2001, NPC filed an application with the PUCN seeking repayment 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 rate to repay 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.
In March 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. NPC and the BCP both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court.
In July 2006, the Supreme Court of Nevada ruled NPC is allowed to recover approximately $180 million of the deferred energy costs and directed the District Court to remand the issue back to the PUCN to determine the rate schedule that will be used to recover this amount. In all other respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance. In 2006, as a result of the Nevada Supreme Court decision, NPC recorded approximately $180 million, before tax, of the previously deferred energy costs in its Income Statements as “Reinstatement of Deferred Energy.” NPC is unable to predict the terms of the rate schedule that the PUCN will provide for recovery of this amount.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to the Western Energy Crisis, discussed above. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
130
Sierra Pacific Power Company
2005 Electric and Gas General Rate Cases
In October 2005, SPPC filed a Gas general rate case along with its statutorily required Electric general rate case. SPPC’s last Gas general rate case was filed in 1992 and the last electric general rate case was filed in 2003. The following items are requested in the filings:
| | • | | Electric general revenue increase: $27 million or 3.4% effective May 1, 2006 |
| |
| | • | | Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006 |
| |
| | • | | Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively |
| |
| | • | | Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively |
| |
| | • | | Approval to continue to recover an allocated amount of the 1999 NPC/SPPC merger costs from Electric customers |
| |
| | • | | Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers |
| |
| | • | | New depreciation rates for Gas and Electric facilities |
SPPC submitted its certification filing for cost of capital and depreciation rates in December 2005 and its revenue requirements and rate design certification filing in January 2006. These filings did not change the requested ROE, ROR or depreciation rates, but did adjust the requested electric revenue increase to $3.2 million.
In January 2006, the interveners filed direct testimony addressing return on equity, overall rate of return and depreciation rates. The PUCN Staff has recommended a 10.28% ROE for Electric and Gas operations, an 8.97% Electric ROR, an 8.06% Gas ROR and depreciation rates that would result in decreased depreciation expenses. Other interveners are recommending ROE’s ranging from 9.1% to 10.9%, Electric ROR’s from 8.35% to 9.08% and Gas ROR’s from 7.52% to 8.10%. The other interveners have also suggested depreciation rates lower than SPPC’s filing.
In February 2006, the interveners filed direct testimony addressing overall revenue requirements, including the effects of their ROE, ROR and depreciation rate recommendations. The PUCN Staff recommended a $15 million decrease to current electric revenues and a $3.6 million increase to gas revenues. The Bureau of Consumer Protection (BCP) recommended a $32 million reduction to current electric revenues and a $0.6 million increase to current gas revenues. The Nevada Resort Association recommended a $12 million decrease to current electric revenues.
In April 2006, the PUCN issued its order to change electric and gas general rates. Although the order differed from SPPC’s requested filing, the changes did not require material adjustments to net income for the six months ended June 30, 2006. The PUCN vote resulted in the following significant items:
| | • | | Electric general revenue decrease: approximately $14 million annually or 1.5% effective May 1, 2006. |
| |
| | • | | Gas general revenue increase: $4.5 million annually or 2.3%, effective May 1, 2006. |
| |
| | • | | Electric Return on Equity and Rate of Return: 10.6% and 8.96% respectively. |
| |
| | • | | Gas Return on Equity and Rate of Return: 10.6% and 7.98% respectively. |
| |
| | • | | Approval to continue recovery of SPPC’s allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Electric customers. |
| |
| | • | | Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs and goodwill from Gas customers. |
| |
| | • | | New depreciation rates for Gas and Electric facilities. |
| |
| | • | | Deferred recovery of legal expenses related to the Enron purchased power contract litigation |
2003 Electric General Rate Case
SPPC filed its biennial general rate case in December 2003, as required by law. SPPC requested an $87 million increase in the annual revenue requirement for general rates. In April 2004, SPPC, the Staff of the PUCN and other interveners in SPPC’s 2003 general rate case negotiated a settlement agreement that resolved most of the issues in the revenue requirement and cost of capital portions of SPPC’s case. The agreement, which has been approved by the PUCN, includes the following provisions:
| | • | | SPPC was allowed to recover a $40 million increase in annual rates. |
131
| | • | | SPPC was allowed a Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.26%, an improvement over SPPC’s previous ROE and ROR, which were 10.17% and 8.61%, respectively. SPPC had sought an ROE of 12.4% and ROR of 10.03%. |
| |
| | • | | The agreement accepted SPPC’s requested accounting treatment as filed in its application for purposes of recording revenues, expenses and assets with the following exception. Accounting issues common to SPPC’s general rate case and NPC’s general rate case that was decided by the PUCN in March 2004, in Docket No. 03-10001, are treated as set forth in the PUCN’s Order on NPC’s general rate case, except for merger costs. The accounting treatment for merger costs and goodwill established in the NPC decision will apply to the recovery of these costs by SPPC, except that SPPC will include in rates 100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general rate application. |
| |
| | • | | Required SPPC to file a set of recommended quality of service and customer service measurements to be used in future general rate case proceedings. In July 2004, SPPC and NPC jointly filed with the PUCN their recommended quality of service and customer service measurements. |
The parties also reached a stipulated agreement that resolved the rate design issues in the case.
Investments in the Piñon Pine generating facility were not addressed by the stipulation. SPPC had sought recovery of its investment of approximately $96 million ($90 million associated with the Nevada jurisdiction) for costs associated with this facility over an extended period (between 10 and 25 years). The recovery of these costs would be in addition to the $40 million annual increase provided for by the stipulation agreement.
In May 2004, the PUCN issued an order accepting the two stipulations, discussed above, and responding to SPPC’s request for recovery of the Piñon investments. The PUCN permitted recovery of approximately $37 million (Nevada jurisdictional) of the costs plus a carrying charge to be amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to SPPC’s general revenues.
As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for impairment under the provisions of SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs”. As a result of this evaluation, SPPC recognized an impairment loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized consists of disallowed costs of approximately $43 million and an additional $4 million loss because the PUCN did not permit a carrying charge on $11 million of the costs to be recovered.
SPPC filed a petition for judicial review of the PUCN’s Piñon Decision in the Second Judicial District Court of Nevada in June 2004. The petition is based on existing resource planning statutes and regulations as they apply to the Piñon project. The Piñon project was approved by the PUCN in SPPC’s 1992 Integrated Resource Plan as presented.
In January 2006, the court vacated the PUCN’s disallowance in Sierra Pacific’s 2003 General Rate Case and remanded the case back to the PUCN for further review whether the costs were justly and reasonably incurred. In March 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. In June 2006, the District Court granted PUCN’s motion to stay the Order. In July 2006, the Supreme Court issued an order questioning the finality of the District Court’s decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this matter. The BCP and PUCN responded in early August, 2006. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and in January 2007 the matter was remitted back to the District Court, which, consistent with its January 2006 order, will remand the matter back to the PUCN for further review. A procedural schedule for this review has not yet been established.
132
2006 Electric Deferred Energy Rate Case and BTER Update
In December 2006, SPPC filed an electric DEAA rate case and BTER update application with the PUCN. The application seeks recovery of $18.7 million of deferred fuel and purchased power costs and requested to reset SPPC’s going forward BTER to reflect anticipated changes in future energy costs. This application requests a 0.86% decrease in overall rates.
2006 Western Energy Crisis Rate Case
In December 2006, SPPC filed an application to recover $22.6 million over four years in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the western energy crisis. This application requests an overall rate increase of less than 1%.
In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC further requests authority to recover carrying charges on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset established by the PUCN in a future application to change rates. The parties to the stipulation have requested that the PUCN issue an order by September 30, 2007.
December 2005 Deferred Energy Rate Cases and Base Tariff Energy Rate Updates
In December 2005, SPPC filed an electric deferred energy rate case application with the PUCN. The application sought to establish a rate to collect accumulated fuel and purchased power costs of $46.7 million from the December 2004 to September 2005 deferral period and $17.5 million from the previously approved unamortized deferrals, for a total $64.2 million. In June 2006, the PUCN approved a negotiated settlement, which granted SPPC full recovery of the deferred costs during a two year period beginning July 2006. Under this agreement, the DEAA rate changes required to asymmetrically recover the $46.7 million deferred balance are scheduled to be implemented such that they will be offset by the expiration of previously approved DEAA rates. As a result, no rate increase was required
The application also requested an increase to the BTER. In April 2006, the PUCN issued an order authorizing SPPC to increase its BTER on May 1, 2006, such that SPPC expects to collect $31 million in new revenues for purchased power. The change represented a 3.5% increase to customer rates.
July 2005 Electric Base Tariff Energy Rate Update
In July 2005, SPPC filed a request to increase its BTER to reflect forecasted energy costs. The request was expected to increase revenue by $32.3 million for the period October 1, 2005 to September 30, 2006 and was intended to more closely correlate fuel and purchased power revenues with fuel and purchased power costs.
In October 2005, the PUCN voted to approve a new electric BTER effective November 1, 2005. The new rate represented a 7.3% overall electric rate increase and was expected to produce $64 million additional revenues during the following 12 months.
January 2005 Electric Deferred Energy Rate Case Filing
In January, 2005, SPPC filed an application with the PUCN seeking recovery of deferred fuel and purchased power costs accumulated between December 2003 and November 2004, as required by law. The application also requested an increase to the BTER or going-forward energy rate.
The PUCN issued its order in May, 2005 granting $27.1 million deferred expense recovery ($27.7 million requested less $0.6 million), modifying the amortization period from the two years requested to one year and approving a BTER rate based on the historical costs methodology as provided for in the Nevada Administrative Code. The overall rate increase was 5.15%.
SPPC 2004 Deferred Energy Case
In January, 2004, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances of approximately $42 million for purchased fuel and power costs accumulated between December 1, 2002, and November 30, 2003.
In July, 2004, the PUCN ruled on the deferred energy case, and approved a full recovery of the fuel and purchased power costs. The PUCN order delayed the start of the deferred balance recovery until April 2005, which corresponds with the expected repayment of previous deferred balances. The PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy purchases) than that requested by SPPC. The higher BTER rate represents an overall increase of 4.4% in electric rates for SPPC and became effective in July 2004.
133
2006 Natural Gas and Propane Deferred Energy Rate Case and BTER Update
In May, 2006, SPPC’s gas distribution operation filed applications with the PUCN seeking recovery of deferred natural gas and propane costs accumulated between April 1, 2005 and March 31, 2006. The applications sought to establish a new natural gas DEAA rate to recover $2.5 million of deferred natural gas costs and a new propane DEAA rate to recover $120 thousand of deferred propane costs. SPPC also requested authorization to increase going forward natural gas and propane BTER’s to reflect forecasted gas costs.
In October, 2006, the PUCN approved negotiated natural gas and propane settlements which consolidated the deferred natural gas and propane balances for collection from all gas customers and reduced the combined balance to $1.1 million. The agreements transferred approximately $1.4 million to other deferral periods and $.1 million to expense accounts. The agreements called for the cost recovery to occur over a 12 month period beginning in December, 2006.
The negotiated going forward natural gas rate is expected to recover an additional $1.3 million in revenue, which is a decrease from the originally requested $24.5 million. The decrease reflects more current natural gas price expectations.
These settlements, combined with the expiration of a previous natural gas DEAA rate will cause natural gas customer rates to decrease by 2.5% and cause propane customer rates to increase by 3.3 %.
2005 Gas Deferred Energy Rate Case and Base Tariff Energy Rate Update
In May, 2005, SPPC filed a gas deferred energy rate case requesting recovery of $6.9 million of deferred energy costs. The filing requested a two-year amortization of the deferred energy balance which represents a 3.2% average increase for all customers.
In July, 2005, SPPC filed a proposed gas BTER, which represented an average increase of 19.5% for all customer classes. The estimated BTER revenue would not change SPPC’s operating income.
In October, 2005, the PUCN voted to approve recovery of $6.9 million of deferred energy costs with a one year amortization and set a new gas BTER rate, both effective in November, 2005. The new BTER was expected to produce $34.1 million additional revenues during a 12 month period. The combined increases represented a 25.3% overall gas rate increase.
SPPC Natural Gas Distribution 2004 Annual Purchased Gas Cost Adjustment
In May, 2004, SPPC filed its annual application for Purchased Gas Cost Adjustment for its natural gas local distribution company. In the application, SPPC asked for an increase of $0.09456 per therm to its Base Purchased Gas Rate to recover its expected going forward gas costs. SPPC also requested that $0.02857 per therm be added to the Balancing Account Adjustment (BAA) rate to amortize an approximate $3.9 million balance of deferred gas costs, which were accumulated during the accounting period. Combined with the simultaneous expiration of past BAA charges, the new BAA rate would be $0.03869 per therm less than the current BAA rate. Overall, this request would result in a rate increase of approximately 5%.
The parties agreed to a stipulation, which recommended the PUCN approve the requested rates and the PUCN issued an order approving the rate increase in November, 2004.
California Electric Matters (Sierra Pacific Power Company)
2006 Energy Cost Adjustment Clause Rate Case
In April, 2006, SPPC filed with the CPUC to reset its “balancing” rate to recover a forecasted deferred energy cost balance and to increase its “offset” rate for going-forward fuel and power purchases. The requested increase in the balancing rate is expected to result in $1.1 million additional revenue and the requested increase in the offset rate is expected to collect an additional $10.1 million. The total request represents an $11.2 million annual revenue increase or a 16.5% average increase to customer rates.
In October, 2006, the CPUC authorized SPPC’s request as filed.
2005 General Rate Case
In June, 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. SPPC requested that the new rates become effective in January, 2006.
134
In August, 2006, the CPUC approved a settlement agreement, which beginning in September, 2006, allowed SPPC to collect an estimated $4.1 million of additional general revenues from its California customers.
2004 Energy Cost Adjustment Clause Rate Case
In May, 2004, SPPC filed its annual Energy Cost Adjustment Clause (ECAC) in California. The filing updated its estimated fuel and purchase power costs for its California customers and sought to recover or refund any deferred amounts projected through September, 2004. The filing requests $8.3 million or a 14.8% overall increase consisting of $3.9 million increase in the base rate and $4.4 million for the projected balance. In November, 2004, the CPUC approved SPPC’s adjusted request and the increase became effective in December, 2004.
Rate Stabilization Plan
In June 2001, SPPC filed with the CPUC a Rate Stabilization Plan, which included two phases. Phase One, which was also filed in June 2001, was an emergency electric rate increase of $10.2 million annually or 26%. In July 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. Rates went into effect July 2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC in April 2002, and included a general rate case and requested the CPUC to reinstate the ECAC, which would allow SPPC to file for annual rate adjustments to reflect its actual costs for wholesale energy supplies. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually.
In January 2004, the CPUC issued Decision No. 04-01-027, which approved a settlement agreement that included an increase of $3.02 million or 5.8%, adopted a rate design methodology and re-instituted the ECAC mechanism. The rate increase was effective January 16, 2004.
FERC Matters
Sierra Pacific Power Company 2004 Transmission Rate Case
In October 2004, the Utilities filed with the FERC revised rates for transmission service offered by SPPC under Docket No. ER05-14. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. The participants in the proceeding filed a Settlement Agreement with the FERC, which was certified by the Settlement Judge. In May 2005, the FERC issued an order approving the negotiated settlement.
Nevada Power Company 2003 Transmission Rate Case
In September 2003, the Utilities filed with the FERC revised rates for transmission service offered by NPC under Docket No. ER03-1328. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. In November 2003, FERC accepted the revised tariff sheets, made rates effective in November 2003, subject to refund, and established hearing procedures. The active participants in the proceeding reached a settlement in principle of all issues. The Certification of Uncontested Offer of Settlement was issued in June 2004. The FERC issued an Order approving the uncontested settlement in July 2004. Refunds were issued within thirty days as required by FERC.
Nevada Power Company
Based on the FERC’s orders to date, NPC believes the recalculated energy prices for NPC sales to the California Independent System Operator (CAISO) and the bankrupt California Power Exchange (CALPX) would result in an approximate $19 million refund. The FERC has also allowed for energy sellers to provide cost justification in the event the recalculated energy prices fall below sellers’ costs. NPC’s developed and filed a cost based filing, which justified a $6 million reduction to the estimated refunds resulting in a $13 million refund.
The CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the same timeframe and a $13 million refund would reduce the amount owed to Nevada Power to $6 million. NPC previously recorded a reserve against the $19 million receivable in 2001.
Sierra Pacific Power Company
Based on the FERC’s orders to date, SPPC believes the recalculated energy prices for sales to the CAISO and CALPX during the October 2, 2000 to June 20, 2001 timeframe would result in a $4 million refund.
135
The CAISO and CALPX currently owe SPPC approximately $1 million for power delivered during the same timeframe and SPPC recorded a reserve against the $1 million receivable in 2001. In 2004, SPPC recorded an additional $3 million liability for this item.
NOTE 4. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY
Investments in subsidiaries and other property consisted of (dollars in thousands):
Sierra Pacific Resources
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
| Investment in Tuscarora Gas Transmission Company (1) | | $ | 590 | | | $ | 30,898 | |
| Cash Value-Life Insurance | | | 12,891 | | | | 13,281 | |
| Non-utility property of NEICO | | | 5,101 | | | | 4,948 | |
| NVPCT-I & NVPCT-III | | | — | | | | 5,841 | |
| Decatur/Gilmore/Cheyenne/Centennial | | | 4,184 | | | | 5,179 | |
| Other non-utility Property | | | 11,559 | | | | 22,624 | |
| | | | | | | |
| | | $ | 34,325 | | | $ | 82,771 | |
| | | | | | | |
| | |
| (1) | | Tuscarora Gas Pipeline Company (TGPC), which is wholly owned by SPR, sold its interest in Tuscarora Gas Transmission Company during December 2006 for approximately $100 million. The gain on the sale of the investment was approximately $40.9 million after taxes. |
Nevada Power
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
| Cash Value-Life Insurance | | $ | 12,891 | | | $ | 13,281 | |
| Non-utility property of NEICO | | | 5,101 | | | | 4,948 | |
| NVPCT–I & NVPCT-III | | | — | | | | 5,841 | |
| Decatur/Gilmore/Cheyenne/Centennial | | | 4,184 | | | | 5,179 | |
| | | | | | | |
| | | $ | 22,176 | | | $ | 29,249 | |
| | | | | | | |
Sierra Pacific Power
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
| Non-utility Property | | $ | 609 | | | $ | 842 | |
| | | | | | | |
NOTE 5. JOINTLY OWNED FACILITIES
At December 31, 2006, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Construction | |
| | | % | | | Plant | | | Accumulated | | | Net Plant | | | Work in | |
| Joint Facility | | Owned | | | in Service | | | Depreciation | | | in Service | | | Progress | |
| NPC | | | | | | | | | | | | | | | | | | | | |
| Navajo Facility | | | 11.3 | | | $ | 240,350 | | | $ | 127,507 | | | $ | 112,843 | | | $ | 562 | |
| Reid Gardner No. 4 | | | 32.2 | | | | 127,970 | | | | 79,425 | | | | 48,545 | | | | 7,538 | |
| Silverhawk | | | 75.0 | | | | 235,241 | | | | 27,097 | | | | 208,144 | | | | 60 | |
| | | | | | | | | | | | | | | | | |
| Total NPC | | | | | | $ | 603,561 | | | $ | 234,029 | | | $ | 369,532 | | | $ | 8,160 | |
| SPPC | | | | | | | | | | | | | | | | | | | | |
| Valmy Facility | | | 50.0 | | | $ | 293,236 | | | $ | 171,660 | | | $ | 121,576 | | | $ | 9,132 | |
The amounts for Navajo include NPC’s share of transmission systems, general plant equipment and 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
136
facilities. NPC’s share of operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Income Statements.
NPC is the operator of the Silverhawk generating station, which is jointly owned with Southern Nevada Water Authority. NPC owns 75% and its share of direct operation and maintenance expense is included in its accompanying Consolidated Income Statements.
NPC has an approximate 14% ownership in the Mohave Generating Station (“Mohave”). Southern California Edison is the operating partner of Mohave. On December 31, 2005, Mohave ceased operations due to unresolved legal matters, as such it was reclassified from Plant-in-Service to Other Regulatory Assets as of December 31, 2005. See Note 13, Commitments and Contingencies, for further discussion of Mohave.
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 Income Statements.
NOTE 6. LONG-TERM DEBT
As of December 31, 2006, 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 and thereafter are shown below (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | SPR Holding Co. and | | | | |
| | | NPC | | | SPPC | | | Other Subs. | | | SPR Consolidated | |
| 2007 | | $ | 5,948 | | | $ | 2,400 | | | $ | — | | | $ | 8,348 | |
| 2008 | | | 7,068 | | | | 322,400 | | | | — | | | | 329,468 | |
| 2009 | | | 22,138 | | | | 80,600 | | | | — | | | | 102,738 | |
| 2010 | | | 7,843 | | | | — | | | | — | | | | 7,843 | |
| 2011 | | | 369,734 | | | | — | | | | — | | | | 369,734 | |
| | | | | | | | | | | | | |
| | | | 412,731 | | | | 405,400 | | | | — | | | | 818,131 | |
| Thereafter | | | 1,986,113 | | | | 668,250 | | | | 549,209 | | | | 3,203,572 | |
| | | | | | | | | | | | | |
| | | | 2,398,844 | | | | 1,073,650 | | | | 549,209 | | | | 4,021,703 | |
| Unamortized Premium (Discount) Amount | | | (12,757 | ) | | | (392 | ) | | | 1,336 | | | | (11,813 | ) |
| | | | | | | | | | | | | |
| Total | | $ | 2,386,087 | | | $ | 1,073,258 | | | $ | 550,545 | | | $ | 4,009,890 | |
| | | | | | | | | | | | | |
The preceding table includes obligations related to capital lease obligations discussed under lease commitments within this note.
Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under which their respective General and Refunding Mortgage bonds are issued.
Nevada Power Company
Pollution Control Refunding Revenue Bonds, Series 2006, 2006A and 2006B
In August 2006, on behalf of NPC, Clark County, Nevada (Clark County) issued $39.5 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due January 2036. On the same date, on behalf of NPC, Coconino County, Arizona Pollution Control Corporation (Coconino County) issued $40 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006A, due September 2032, and $13 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006B, due March 2039.
In connection with the issuance of these Bonds, NPC entered into financing agreements with Clark County and Coconino County, pursuant to which Clark County and Coconino County loaned the proceeds from the sales of the bonds to NPC. NPC’s payment obligations under the financing agreements are secured by NPC’s General and Refunding Mortgage Notes, Series P.
The interest rates of the Bonds were initially determined by an auction. The method of determining the interest rate on the Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offering were used to refund the following, all of which were previously issued for the benefit of NPC:
| | • | | $39.5 million principal amount of Clark County’s Pollution Control Refunding Revenue Bonds, Series 1992B, |
| |
| | • | | $20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1996, |
| |
| | • | | $20 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1997B, and |
| |
| | • | | $13 million principal amount of Coconino County’s Pollution Control Revenue Bonds, Series 1995E. |
137
General and Refunding Mortgage Notes, Series O
In May 2006, NPC issued and sold $250 million in aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018. The Series O Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:
| | • | | fund the early redemption of $78 million aggregate principal amounts of NPC’s 7.2% Industrial Development Revenue Bonds, Series 1992 C, due 2022, |
| |
| | • | | fund the early redemption, in June 2006, of approximately $72.2 million aggregate principal amount of NPC’s 7.75% Junior Subordinated Debentures due 2038 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred Securities of NVP Capital III, a wholly-owned subsidiary of NPC), |
| |
| | • | | repay amounts outstanding under NPC’s revolving credit facility. |
In June 2006, NPC issued an additional $75 million in aggregate principal amount of its 6.5% General and Refunding Mortgage Notes, Series O, as part of the same series as the original Series O Notes. The aggregate principal amount of 6.5% General and Refunding Mortgage Notes, Series O, due 2018, outstanding is $325 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $120 million of NPC’s 6.65% General and Refunding Mortgage Notes, Series N, due 2036 (described below) were used to pay the total consideration for the tender offer for the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series N
In April 2006, NPC issued and sold $250 million of its 6.65% General and Refunding Mortgage Notes, Series N, due April 2036. The Series N Notes were issued with registration rights. Proceeds of the offering, together with available cash, were utilized to:
| | • | | fund the early redemption of $35 million aggregate principal amount of NPC’s 8.50% Series Z First Mortgage Bonds due 2023 plus approximately $1 million of associated redemption premiums, |
| |
| | • | | fund the early redemption of $105 million aggregate principal amount of 6.70% Industrial Development Revenue Bonds, due 2022, and |
| |
| | • | | fund the early redemption of approximately $122.5 million aggregate principal amount of NPC’s 8.20% Junior Subordinated Debentures due 2037 (when the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I, a wholly-owned subsidiary of NPC). |
In June 2006, NPC issued an additional $120 million in aggregate principal amount of its 6.65% General and Refunding Mortgage Notes, Series N, as part of the same series as the original Series N Notes. The aggregate principal amount of 6.65% General and Refunding Mortgage Notes, Series N, due 2036, outstanding is $370 million as of December 31, 2006. The proceeds from the second issuance, along with the proceeds from an offering of $75 million of NPC’s 6.5% General and Refunding Mortgage Notes, Series O, due 2018 (described above) were used to pay the total consideration for the tender offer on the 10.875% General and Refunding Mortgage Notes, Series E, described below.
General and Refunding Mortgage Notes, Series M
In January 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 2016. The Series M Notes were issued with registration rights. In February 2006 the net proceeds of the issuance plus available cash were used to repay $210 million of amounts outstanding under NPC’s revolving credit facility, which were borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Generating Facility.
Revolving Credit Facility
In November 2005, NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility and on the amounts borrowed, increasing the size of the facility to $500 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by at least two of the three rating agencies: Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). Currently, the base rate is Prime, and NPC’s applicable base rate margin is zero. The Eurodollar margin is 0.875%.
138
In April 2006, NPC increased the size of the credit facility to $600 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2006, NPC had $55 million of letters of credit outstanding and had no borrowings outstanding under the revolving credit facility. As of February 23, 2007, NPC had $48.7 million of letters of credit outstanding and had $75 million borrowed under the revolving credit facility.
The NPC Credit Agreement contains two financial maintenance covenants. The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2006, NPC was in compliance with these covenants.
The NPC Credit Agreement provides for an event of default if there is a failure under NPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.
Other Redemptions
General and Refunding Mortgage Notes, Series G
In July 2005, NPC redeemed $122,500,000 aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013. This redemption constituted 35% of the principal amount outstanding. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt.
General and Refunding Mortgage Notes, Series E
In July 2005, NPC redeemed $87,500,000 aggregate principal amount of its 10.875% General and Refunding Mortgage Notes, Series E, due 2009. This redemption constituted 35% of the principal amount outstanding. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $9.5 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemption with the proceeds of an equity contribution of approximately $230.5 million from SPR.
Tender Offer for General and Refunding Mortgage Notes, Series E
In June 2006, NPC commenced a tender offer for the remaining 10.875% General and Refunding Mortgage Notes, Series E, due 2009. In conjunction with that offer, NPC solicited the consent of holders of a majority in aggregate principal amount of the Series E Notes to eliminate substantially all of the restrictive covenants contained in the officer’s certificate governing the Series E Notes. Approximately $150 million of $162.5 million Series E Notes outstanding were validly tendered and accepted by NPC. Those holders who tendered the Series E Notes and delivered their consents by June 14, 2006 were entitled to receive a consent payment of $30 per $1,000 principal amount of Series E Notes, plus tender consideration for each $1,000 principal amount of Series E Notes validly tendered. Those holders who tendered the Series E Notes after June 14, 2006, but prior to June 28, 2006, were entitled to receive the tender consideration only. This tender consideration was $1,038.45 in cash plus accrued and unpaid interest up to the June 2006 settlement date per $1,000 principal amount of the Series E Notes tendered. Proceeds from the June 2006 issuance of Series N and Series O Notes (discussed above) were used to fund the tender offer. The total consideration (including the consent payment and accrued interest) paid in June 2006 was approximately $163.6 million. In October 2006, NPC redeemed the remaining $12.6 million aggregate principal amount of the Series E Notes, plus accrued interest, using available cash on hand.
NVP Capital I Trust
In April 2006, NPC’s 8.20% Junior Subordinated Debentures due 2037 were redeemed. When the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 8.20% Cumulative Quarterly Preferred Securities of NVP Capital I.
NVP Capital III Trust
In June 2006, NPC’s 7.75% Junior Subordinated Debentures due 2038 were redeemed. When the debentures were repaid upon redemption, the proceeds from the repayment were used to simultaneously redeem an equal amount of the 7.75% Cumulative Quarterly Preferred Securities of NVP Capital III.
139
Sierra Pacific Power Company
Pollution Control and Gas and Water Facilities Refunding Revenue Bonds, Series 2006, 2006A, 2006B and 2006C
In November 2006, on behalf of SPPC, Humboldt County, Nevada (Humboldt County) issued $49.75 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, Series 2006, due October 2029. On the same date, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $58.7 million aggregate principal amount of it Gas Facilities Refunding Revenue Bonds, Series 2006A, due August 2031; $75 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2006B, due March 2036; and $84.8 million aggregate principal amount of its Gas and Water Facilities Refunding Revenue Bonds, Series 2006C, due March 2036.
In connection with the issuance of these Bonds, SPPC entered into financing agreements with Humboldt County and Washoe County, pursuant to which Humboldt County and Washoe County loaned the proceeds from the sales of the bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series N.
The interest rates of the Bonds were initially determined by an auction. The method of determining the interest rate on the Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.
The proceeds of the offerings were used to refund the following, all of which were previously issued for the benefit of SPPC:
| | • | | $17.5 million principal amount of 6.65% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $20 million principal amount of 6.55% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1990 |
| |
| | • | | $21.2 million principal amount of 6.70% Washoe County’s Gas Facilities Refunding Revenue Bonds, Series 1992 |
| |
| | • | | $75 million principal amount of 6.65% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $45 million principal amount of 6.30% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $30 million principal amount of 5.90% Washoe County’s Gas and Water Facilities Refunding Revenue Bonds, Series 1993B |
| |
| | • | | $9.8 million principal amount of 5.90% Washoe County’s Water Facilities Refunding Revenue Bonds, Series 1993A |
| |
| | • | | $39.5 million principal amount of 6.55% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1987 |
| |
| | • | | $10.25 million principal amount of 6.30% Humboldt County’s Pollution Control Refunding Revenue Bonds, Series 1992A |
Humboldt County Pollution Control Refunding Revenue Bonds
In October 2006, the 6.35% Humboldt County Pollution Control Refunding Revenue Bonds, Series 1992B, due August 2022, in the amount of $1 million were redeemed at 100% of the stated principal amount, plus accrued interest.
General and Refunding Mortgage Notes, Series M
In March 2006, SPPC issued and sold $300 million of its 6.00% General and Refunding Mortgage Notes, Series M, due May 2016. The Series M Notes were issued with registration rights. Proceeds of the offering were used to repay $173 million borrowed under the revolving credit facility that was utilized to:
| | • | | fund the early redemption of $110 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.95% to 8.61% Series A Notes due 2022; |
| |
| | • | | fund the early redemption of $58 million aggregate principal amount of SPPC’s Collateralized Medium Term 7.10% to 7.14% Series B Notes due 2023; |
| |
| | • | | pay for maturing debt of $30 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.81% to 6.83% Series C Notes due 2006; |
| |
| | • | | pay for $51 million in connection with the redemption of $50 million of SPPC’s Series A Preferred Stock (two million shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends to the redemption date of $.4875 per share); and |
| |
| | • | | pay for maturing debt of $20 million aggregate principal amount of SPPC’s Collateralized Medium Term 6.62% to 6.65% Series C Notes due 2006. |
Revolving Credit Facility
In November 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility, and on the amounts borrowed, increasing the size of the facility to $250 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar
140
rate, plus a margin that varies based upon SPPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime and SPPC’s applicable base rate margin is zero. The current Eurodollar margin is 0.875%.
In April 2006, SPPC increased the size of its credit facility to $350 million. The facility will provide additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2006, SPPC had $9.4 million of letters of credit outstanding and had no amounts borrowed under the revolving credit facility. As of February 23, 2007, SPPC had $18.9 million of letters of credit and had no amounts borrowed under the revolving credit facility.
The SPPC Credit Agreement contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2006, SPPC was in compliance with these covenants.
The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC’s other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.
The SPPC Credit Agreement, similar to SPPC’s Series H Notes, places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.
Sierra Pacific Resources
Tender Offer
In November 2006, SPR commenced tender offers for up to $110 million aggregate principal amount of its 7.803% Senior Notes due 2012, its 8.625% Senior Notes due 2014, and its 6.75% Senior Notes due 2017. Each of the offers was conditioned on SPR purchasing no more than an aggregate principal amount of $110 million of all notes validly tendered. To meet this condition, SPR terminated the offer for the 6.75% Notes. In December 2006 approximately $25 million of the 7.803% Senior Notes outstanding, and approximately $85 million of the 8.625% Senior Notes outstanding were validly tendered and accepted by SPR. The total consideration paid was approximately $120.6 million (which included an early tender premium and accrued interest). As of December 31, 2006, the outstanding balances for the 7.803% Senior Notes and 8.625% Senior Notes were $ 74.2 million and $250.0 million, respectively.
7.803% Senior Notes
In May 2005, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the Premium Income Equity Securities (Old PIES), which were originally issued in November 2001. SPR successfully remarketed these notes in June 2005. In connection with the remarketing, the interest rate of the senior notes was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature in June 2012. In December 2006, a portion of these Notes were tendered. (See Tender Offer above). As of December 31, 2006, $74.2 million aggregate principal amount of the 7.803% Senior Notes remain outstanding.
6.75% Senior Notes
In August 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes due 2017. The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with the Old PIES, pay approximately $54 million in premiums associated with the conversion of the 7.25% Notes and fund the associated fees and expenses; and to provide additional liquidity to SPR.
8.625% Senior Notes
In March 2004, SPR issued and sold $335 million 8.625% Senior Unsecured Notes due March 2014. The Senior Unsecured Notes, which were issued with registration rights, were exchanged for registered notes in October 2004. The proceeds of the issuance were used to fund the repurchase of approximately $174 million in principal amount of SPR’s 8.75% Notes due 2005 at a price equal to approximately 107.225% of the principal amount thereof that were tendered pursuant to SPR’s tender offer.
The balance of the net proceeds were used in May 2004 to legally extinguish the approximately $126 million of remaining principal amount of SPR’s 8.75% Notes due 2005 which were not tendered, and to pay associated interest and fees and expenses associated with the tender offer and the Notes offering. The total cost to extinguish the debt was approximately $23.7 million consisting of tender fees, interest costs and unamortized debt issuance costs.
In December 2006, a portion of the 8.625% Senior Unsecured Notes were tendered (See Tender Offer above). As of December 31, 2006, $250 million aggregate principal amount of the 8.625% Senior Notes remain outstanding.
141
Lease Commitments
In 1984, NPC entered into a 30-year capital lease with five-year renewal options beginning in year 2015. The fixed rental obligation for the first 30 years is $5.1 million per year. Also, NPC has a power purchase 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 capital leases, combined, as of December 31, 2006, were as follows (dollars in thousands):
| | | | | |
| 2007 | | $ | 5,933 | |
| 2008 | | | 7,053 | |
| 2009 | | | 7,138 | |
| 2010 | | | 7,843 | |
| 2011 | | | 5,734 | |
| Thereafter | | | 16,778 | |
NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The December 31, 2006, carrying amount of 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, 2006, is estimated to be $2.5 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 $2.2 billion at December 31, 2005.
The total fair value of SPPC’s consolidated long-term debt at December 31, 2006, is estimated to be $1.1 billion (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 $1.0 billion as of December 31, 2005.
The total fair value of SPR’s consolidated long-term debt at December 31, 2006 is estimated to be $4.1 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 $3.9 billion as of December 31, 2005.
NOTE 8. DEBT COVENANT AND OTHER RESTRICTIONS
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 impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In the PUCN order for Docket 05-10024 and 05-10025, issued in February 2006, a dividend restriction was instituted for both Utilities. Under this restriction, the combined amount that NPC and SPPC may pay to SPR each year is limited to the actual cash necessary to service SPR’s debt for the year. At the time of the order, SPR and the Utilities were only rated by Standard & Poor’s (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings Ltd. (“Fitch”). The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. In February 2007, Dominion Bond Rating Service (“DBRS”), who had not previously issued ratings on the companies, assigned ratings for SPR, NPC and SPPC. DBRS and Fitch currently rate NPC and SPPC’s senior secured debt at the minimum level for investment grade. It is not clear what effect, if any, the DBRS rating will have on the PUCN dividend restriction. See “Credit Ratings” below for discussion of current ratings.
In addition, certain agreements entered into by the Utilities set restrictions on certain restricted payments, including the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid.
In addition, covenants of certain SPR, NPC and SPPC debt limit the company’s ability to incur additional debt. Material restrictions on dividends and on debt incurrence, contained in SPR’s and the Utilities’ financing agreements are summarized below. All securities issued by NPC and SPPC must be authorized by the PUCN.
Limits on Restricted Payments
Sierra Pacific Resources
SPR has paid no dividends since 2002. 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, as well as dividend restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014, 7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017. 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 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.
142
Certain of SPR debt contain covenants that limit restricted payments, which include dividends. If SPR were to resume paying a dividend, these restrictive covenants must first be satisfied. SPR must be able to incur additional indebtedness, as determined under a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is less than (i) 50% of the Consolidated Net Income for SPR for the period from April 1, 2004 to the end of the most recently ended fiscal quarter for which internal financial statements are available at the time of such payment, plus (ii) 100% of SPR’s net cash proceeds from the issuance or sale of its equity interests, including common stock. Since SPR meets the 2 to 1 fixed charge coverage ratio test, it could dividend up to a maximum of $740 million as of December 31, 2006. Under its most restrictive covenants, SPR can additionally pay up to an aggregate of $50 million in dividends during the period from April 1, 2004 to the end of the most recently ended fiscal quarter.
Material Dividend Restrictions Applicable to Nevada Power Company
| | • | | The following notes and credit agreement limit the amount of payments in respect of common stock that NPC may make to SPR: |
| | o | | NPC’s 57/8 General and Refunding Mortgage Notes, Series L, due 2015, which were issued in November 2004, |
| |
| | o | | NPC’s Revolving Credit Agreement, which was amended and restated in November 2005, |
| |
| | o | | NPC’s 61/2% General and Refunding Mortgage Notes, Series I, due 2012, which were issued in April 2004, and |
| |
| | o | | NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued in August 2003. |
However, the dividend payment limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses, 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 various series of Notes, and the Revolving Credit Agreement also permit NPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed:
| | o | | under the Series G, Series I and Series L Notes, $25 million from the date of the issuance of the Series G, Series I and Series L Notes, respectively. |
| |
| | o | | Under the Second Amended and Restated Revolving Credit Facility, $50 million from the date of the establishment of the Amended and Restated Revolving Credit Facility. |
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:
| | i. | | there are no defaults or events of default with respect to the Series G, I and L Notes or the Revolving NPC Credit Agreement, |
| |
| | ii. | | 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 to 1, and |
| |
| | iii. | | the total amount of such dividends is less than: |
| | • | | the sum of 50% of NPC’s consolidated net income measured on a annual basis cumulative of all quarters from the date of issuance of the applicable series of Notes, the Bond or Credit Agreement, plus |
| |
| | • | | 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 |
| |
| | • | | the lesser of cash return of capital or the initial amount of certain restricted investments, plus |
| |
| | • | | the fair market value of NPC’s investment in certain subsidiaries. |
Since NPC meets (i) and (ii) above, NPC would be able to pay up to a maximum of $609 million to SPR as of December 31, 2006. However, the total amount of dividends that NPC can pay to SPR under its financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under its financing agreements is greater than the amount that NPC can pay under the PUCN dividend restriction.
If NPC’s Series, Series G Notes, Series I Notes, or Series L Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remains investment grade (see Credit Ratings below).
143
Material Dividend Restrictions Applicable to Sierra Pacific Power Company
| | • | | The following notes and credit facility limit the amount of payments in respect of common stock that SPPC may make to SPR: |
| | o | | SPPC’s Revolving Credit Agreement, which was amended and restated in November 2005, and |
| |
| | o | | SPPC’s 61/4 % General and Refunding Mortgage Notes, Series H, due 2012, which were issued in April 2004. |
However, the dividend payment limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses provided that:
| | o | | those payments do not exceed $50 million for any one calendar year, |
| |
| | o | | those payments comply with any regulatory restrictions then applicable to SPPC, and |
| |
| | o | | the ratio of consolidated cash flow to fixed charges for SPPC’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 H Notes also permit SPPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed $25 million from the date of the issuance of the Series H Notes.
The terms of the Amended and Restated Revolving Credit Facility also permit SPPC to make payments to SPR in excess of the amounts payable above in an aggregate amount not to exceed $50 million from the date of the establishment of the Amended and Restated Revolving Credit Facility.
In addition, SPPC 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:
| | i. | | there are no defaults or events of default with respect to the Series H Notes or the SPPC Revolving Credit Agreement, |
| |
| | ii. | | SPPC has a ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2 to 1, and |
| |
| | iii. | | the total amount of such dividends is less than: |
| | • | | the sum of 50% of SPPC’s consolidated net income measured on a annual basis cumulative of all quarters from the date of issuance of the Series H Notes or the establishment of the Revolving Credit Agreement, plus |
| |
| | • | | 100% of SPPC’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 SPPC, plus |
| |
| | • | | the lesser of cash return of capital or the initial amount of certain restricted investments, plus |
| |
| | • | | the fair market value of SPPC’s investment in certain subsidiaries. |
Since SPPC meets (i) and (ii) above, SPPC would be able to pay up to a maximum of $126 million to SPR as of December 31, 2006. However, the total amount of dividends that SPPC can pay to SPR under its financing agreements does not currently significantly restrict their ability to pay dividends because the maximum amount of dividends that can be paid under its financing agreements is greater than the amount that SPPC can pay under the PUCN dividend restriction.
If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade (see Credit Ratings below).
Dividend Restrictions Applicable to the Utilities
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 their capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.
Limitations on Indebtedness
Sierra Pacific Resources
Certain debt of SPR places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of December 31, 2006, SPR would be allowed to incur up to $2.1 billion of additional indebtedness on a consolidated basis.
144
Notwithstanding this restriction, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two utilities’ integrated resource plans. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.
If the debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remains investment grade (see Credit Ratings below).
Nevada Power Company
Certain debt of NPC places restrictions on debt incurrence, liens and dividends, unless, 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. Under this covenant restriction, as of December 31, 2006, NPC would be allowed to incur $2.2 billion of additional indebtedness. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $2.1 billion of additional indebtedness SPR could incur on a consolidated basis.
Under the terms of NPC’s debt, NPC would also be permitted to incur debt, including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to NPC’s 2006 Integrated Resource Plan.
If the debt containing these covenants is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable debt remains investment grade (see Credit Ratings below).
Sierra Pacific Power Company
Certain debt of SPPC places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of December 31, 2006, SPPC would be allowed to incur up to $797 million of additional indebtedness on a consolidated basis. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $2.1 billion of additional indebtedness SPR could incur on a consolidated basis.
Under the terms of SPPC’s debt, SPPC would also be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to SPPC’s 2004 Integrated Resource Plan.
If the debt containing these covenants is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable debt remains investment grade (see Credit Ratings below).
Credit Ratings
SPR, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations S&P, Moody’s, Fitch, and Dominion Bond Rating Service (“DBRS”). As of February 23, 2007, the ratings are as follows:
| | | | | | | | | | | |
| | | | | Rating Agency |
| | | | | DBRS | | Fitch | | Moody’s | | S&P |
| SPR | | Sr. Unsecured Debt | | BB (low) | | BB- | | B1 | | B |
| NPC | | Sr. Secured Debt | | BBB (low)* | | BBB-* | | Bal | | BB+ |
| NPC | | Sr. Unsecured Debt | | Not rated | | BB | | Not rated | | B |
| SPPC | | Sr. Secured Debt | | BBB (low)* | | BBB-* | | Bal | | BB+ |
| | |
| * | | Ratings are investment grade |
In February 2007, DBRS, who had not previously issued ratings on the companies, assigned new ratings to SPR, NPC and SPPC. The ratings for the senior secured debt of NPC and SPPC are BBB (low), which is the minimum level for investment grade. The rating assigned to SPR’s senior notes is BB (low), which is non-investment grade. DBRS’s trend for all three companies is Stable.
In 2006, there were other changes to the ratings of the three companies. Fitch upgraded the ratings of SPR and the Utilities. The ratings for the senior secured debt of NPC and SPPC were increased to BBB-, the minimum level for investment grade. The senior unsecured debt for NPC was upgraded from BB- to BB, which is still non-investment grade. Fitch revised the rating outlook for SPR and the Utilities from Positive to Stable. S&P upgraded the ratings of NPC’s and SPPC’s senior secured debt from BB to
145
BB+, one level below investment grade. Moody’s re-affirmed its ratings for NPC’s and SPPC’s senior secured debt at Ba1, one level below investment grade.
At the time of the PUCN order for Dockets 05-10024 and 05-10025, (see Dividends from Subsidiaries, above) SPR and the Utilities were only rated by S&P, Moody’s and Fitch. The PUCN order states that the dividend restriction will continue until NPC’s and SPPC’s senior secured debt obtains an investment grade rating from two of the three credit rating agencies, but did not specify which rating agencies. It is not clear what effect the DBRS rating will have on the PUCN dividend restriction.
NOTE 9. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
SPR, SPPC, and NPC apply SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, SFAS No. 149 and SFAS No. 155. As amended, SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It 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 meets certain defined conditions and qualifies as an effective hedge. SFAS No. 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value. A majority of the contracts entered into by the Utilities meet the criteria specified for this exception.
The energy supply function encompasses the reliable and efficient operation of the Utilities generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. SPR’s and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price 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 from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets.
The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of SPR, NPC, and SPPC, and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS No. 133. The fair values of the open derivative positions are determined using quoted exchange prices, external dealer prices, and available market pricing curves. Due to deferred energy accounting treatment under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2006 | | December 31, 2005 |
| | | Fair Value | | Fair Value |
| | | (dollars in millions) | | (dollars in millions) |
| | | SPR | | NPC | | SPPC | | SPR | | NPC | | SPPC |
| Risk management assets- current | | $ | 27.3 | | | $ | 16.4 | | | $ | 10.9 | | | $ | 50.2 | | | $ | 22.4 | | | $ | 27.8 | |
| Risk management assets- noncurrent | | $ | 7.6 | | | $ | 5.4 | | | $ | 2.2 | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
| Total risk management assets | | $ | 34.9 | | | $ | 21.8 | | | $ | 13.1 | | | $ | 50.2 | | | $ | 22.4 | | | $ | 27.8 | |
|
|
|
|
|
|
|
|
| Risk management liabilities- current | | $ | 123.1 | | | $ | 84.7 | | | $ | 38.4 | | | $ | 16.6 | | | $ | 10.1 | | | $ | 6.5 | |
| Risk management liabilities- noncurrent | | $ | 10.8 | | | $ | 7.1 | | | $ | 3.7 | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | |
| Total risk management liabilities | | $ | 133.9 | | | $ | 91.8 | | | $ | 42.1 | | | $ | 16.6 | | | $ | 10.1 | | | $ | 6.5 | |
|
|
|
|
|
|
|
|
| Risk management regulatory net assets (liabilities) | | $ | 122.9 | | | $ | 83.9 | | | $ | 39.0 | | | $ | (15.6 | ) | | $ | (.6 | ) | | $ | (15.0 | ) |
As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities can not predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities open derivative positions with its counterparties and the changes in forward commodity prices. The decrease in net risk management assets as of December 31, 2006 as compared to December 31, 2005, is due to unfavorable open derivative positions on natural gas options held by
146
the Utilities to hedge energy price risk for their customers, resulting from lower commodity prices for natural gas in 2006 relative to contract prices.
Also included in total risk management assets were $24.0 million, $13.9 million, and $10.1 million in payments for electric and gas options by SPR, NPC, and SPPC, respectively, at December 31, 2006.
NOTE 10. INCOME TAXES (BENEFITS)
Sierra Pacific Resources
The following reflects the composition of taxes on income from continuing operations (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Provision (benefit) for income taxes | | | | | | | | | | | | |
| Current | | | | | | | | | | | | |
| Federal | | $ | 5,914 | | | $ | 3,159 | | | $ | (161 | ) |
| State | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| Total current | | | 5,914 | | | | 3,159 | | | | (161 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Deferred | | | | | | | | | | | | |
| Federal | | | 144,919 | | | | 43,833 | | | | 24,448 | |
| State | | | 494 | | | | 1,688 | | | | (775 | ) |
| | | | | | | | | | |
| Total deferred | | | 145,413 | | | | 45,521 | | | | 23,673 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Amortization of excess deferred taxes | | | (2,315 | ) | | | (2,123 | ) | | | (2,196 | ) |
| | | | | | | | | | | | | |
| Amortization of investment tax credits | | | (3,407 | ) | | | (3,439 | ) | | | (3,266 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Total provision for income taxes | | $ | 145,605 | | | $ | 43,118 | | | $ | 18,050 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income statement classification of provision (benefit) for income taxes | | | | | | | | | | | | |
| Operating income | | $ | 91,571 | | | $ | 39,185 | | | $ | 22,739 | |
| Other income | | | 54,034 | | | | 3,933 | | | | (4,689 | ) |
| | | | | | | | | | |
| Total | | $ | 145,605 | | | $ | 43,118 | | | $ | 18,050 | |
| | | | | | | | | | |
147
The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Income from continuing operations | | $ | 279,792 | | | $ | 86,137 | | | $ | 30,842 | |
| Total income tax expense (benefit) | | | 145,605 | | | | 43,118 | | | | 18,050 | |
| | | | | | | | | | |
| Pretax income | | | 425,397 | | | | 129,255 | | | | 48,892 | |
| Statutory tax rate | | | 35 | % | | | 35 | % | | | 35 | % |
| | | | | | | | | | |
| Federal income tax expense at statutory rate | | | 148,889 | | | | 45,239 | | | | 17,112 | |
| Depreciation related to difference in costs basis for tax purposes | | | 4,709 | | | | 4,559 | | | | 4,834 | |
| Allowance for funds used during construction — equity | | | (6,379 | ) | | | (7,113 | ) | | | (2,082 | ) |
| ITC amortization | | | (3,407 | ) | | | (3,439 | ) | | | (3,266 | ) |
| Goodwill | | | 2,600 | | | | 2,230 | | | | 6,332 | |
| Convertible bond mark to market and interest accretion | | | — | | | | 2,132 | | | | 2,786 | |
| Pension benefit plan | | | 338 | | | | (945 | ) | | | (3,684 | ) |
| Research and development credit | | | (3,764 | ) | | | — | | | | — | |
| Other — net | | | 2,619 | | | | 455 | | | | (632 | ) |
| | | | | | | | | | |
| Provision for income taxes before effect of income tax settlements | | $ | 145,605 | | | $ | 43,118 | | | $ | 21,400 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Effective tax rate before effect of income tax settlements | | | 34.2 | % | | | 33.3 | % | | | 43.8 | % |
| | | | | | | | | | |
| Effects of income tax settlements | | | | | | | — | | | | (3,350 | ) |
| | | | | | | | | | |
| Provision for income taxes | | $ | 145,605 | | | $ | 43,118 | | | $ | 18,050 | |
| Effective tax rate | | | 34.2 | % | | | 33.3 | % | | | 36.9 | % |
| | | | | | | | | | |
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the Internal Revenue Service (IRS) on a regular basis. The IRS is currently conducting audits of SPR for the years 1997-2004. During the first quarter of 2004, SPR reached tentative agreements with the IRS for certain matters. As a result of the tentative agreements, SPR recognized tax benefits which increased net income by approximately $3.4 million in 2004. SPR believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.
148
The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| Deferred income tax assets | | | | | | | | |
| Net operating loss and credit carryovers | | $ | 227,834 | | | $ | 247,135 | |
| Employee benefit plans | | | 71,820 | | | | 10,190 | |
| Customer advances | | | 32,163 | | | | 59,522 | |
| Gross-ups received on contribution in aid of construction and customer advances | | | 31,113 | | | | 25,862 | |
| Deferred revenues | | | 1,586 | | | | 11,303 | |
| Provision for contract termination | | | 508 | | | | 63,427 | |
| Other | | | 22,128 | | | | 19,765 | |
| | | | | | | |
| Subtotal | | | 387,152 | | | | 437,204 | |
| Deferred income tax assets associated with regulatory matters | | | | | | | | |
| Excess deferred income taxes | | | 15,111 | | | | 17,426 | |
| Unamortized investment tax credit | | | 18,964 | | | | 20,798 | |
| | | | | | | |
| Subtotal | | | 34,075 | | | | 38,224 | |
| | | | | | | |
| Total deferred income tax assets before valuation allowance | | | 421,227 | | | | 475,428 | |
| Valuation allowance | | | (732 | ) | | | (984 | ) |
| | | | | | | |
| Total deferred income tax assets after valuation allowance | | $ | 420,495 | | | $ | 474,444 | |
| | | | | | | |
| | | | | | | | | |
| Deferred income tax liabilities | | | | | | | | |
| Excess of tax depreciation over book depreciation | | $ | 540,338 | | | $ | 560,702 | |
| Deferred energy | | | 192,653 | | | | 180,488 | |
| Regulatory assets | | | 101,375 | | | | 20,139 | |
| Other | | | 64,791 | | | | 44,819 | |
| | | | | | | |
| Subtotal | | | 899,157 | | | | 806,148 | |
| Deferred income tax liabilities associated with regulatory matters | | | | | | | | |
| Tax benefits flowed through to customers | | | 263,170 | | | | 249,262 | |
| | | | | | | |
| Total deferred income tax liability | | $ | 1,162,327 | | | $ | 1,055,410 | |
| | | | | | | |
| | | | | | | | | |
| Net deferred income tax liability | | $ | 512,737 | | | $ | 369,928 | |
| Net deferred income tax liability associated with regulatory matters | | | 229,095 | | | | 211,038 | |
| | | | | | | |
| Total net deferred income tax liability | | $ | 741,832 | | | $ | 580,966 | |
| | | | | | | |
The total 2006 net deferred income tax liability of $741,832 includes $5,950 of deferred tax liability associated with accumulated depreciation on the Mohave generating station, which, on the financial statements, is included in other regulatory assets. Reference Note 13, Commitments and Contingencies, for further discussion of the Mohave Generating Station.
SPR’s balance sheets contain a net regulatory asset of $229.1 million at December 31, 2006 and $211.0 million at December 31, 2005. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and 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.
As reflected in SPR’s balance sheet (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| Tax benefits flowed through to customers | | | | | | | | |
| Related to property | | $ | 106,175 | | | $ | 98,330 | |
| Related to goodwill | | | 156,995 | | | | 150,931 | |
| | | | | | | |
| Regulatory tax asset | | | 263,170 | | | | 249,261 | |
| |
| Liberalized depreciation at rates in excess of current rates | | | 15,111 | | | | 17,426 | |
| Unamortized investment tax credits | | | 18,964 | | | | 20,798 | |
| | | | | | | |
| Regulatory tax liability | | | 34,075 | | | | 38,224 | |
| | | | | | | |
| Net regulatory tax asset | | $ | 229,095 | | | $ | 211,037 | |
| | | | | | | |
149
SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR owes NPC $20.6 million in inter-company tax payments. Additionally, per SPR’s tax sharing agreement, SPR has a current tax receivable from SPPC of $9.1 million.
The following table summarizes the tax NOL and credit carry-forwards and associated carry-forward periods, and a valuation allowance for amounts which SPR has determined that realization is uncertain (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Expiration | |
| | | Deferred Tax Asset | | | Valuation Allowance | | | Net Deferred Tax Asset | | | Period | |
| Federal NOL | | $ | 213,024 | | | $ | — | | | $ | 213,024 | | | | 2020-2023 | |
| State NOLs | | | 1,058 | | | | — | | | | 1,058 | | | | 2008-2013 | |
| Research and development credit | | | 3,764 | | | | — | | | | 3,764 | | | 2021-2025 |
| Alternative minimum tax credit | | | 8,696 | | | | — | | | | 8,696 | | | indefinite |
| Arizona coal credits | | | 1,292 | | | | 732 | | | | 560 | | | | 2007-2011 | |
| | | | | | | | | | | | | | |
| Total | | $ | 227,834 | | | $ | 732 | | | $ | 227,102 | | | | | |
| | | | | | | | | | | | | | |
At December 31, 2006, SPR has gross federal and state net operating loss carry-forwards of $608.6 million and $12.0 million, respectively.
Considering all positive and negative evidence regarding the utilization of SPR’s deferred tax assets, it has been determined that SPR is more-likely-than-not to realize all recorded deferred tax assets, except the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2006.
Nevada Power Company
The following reflects the composition of taxes on income (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Provision (benefit) for income taxes | | | | | | | | | | | | |
| Current | | | | | | | | | | | | |
| Federal | | $ | 4,865 | | | $ | 3,159 | | | $ | 6 | |
| State | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| Total current | | | 4,865 | | | | 3,159 | | | | 6 | |
| | | | | | | | | | | | | |
| Deferred | | | | | | | | | | | | |
| Federal | | | 114,741 | | | | 63,873 | | | | 58,762 | |
| State | | | 268 | | | | (449 | ) | | | (67 | ) |
| | | | | | | | | | |
| Total deferred, net | | | 115,009 | | | | 63,424 | | | | 58,695 | |
| | | | | | | | | | | | | |
| Amortization of excess deferred taxes | | | (745 | ) | | | (778 | ) | | | (499 | ) |
| | | | | | | | | | | | | |
| Amortization of investment tax credits | | | (1,619 | ) | | | (1,810 | ) | | | (1,630 | ) |
| |
| | | | | | | | | | |
| Total provision for income taxes | | $ | 117,510 | | | $ | 63,995 | | | $ | 56,572 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income statement classification of provision for income taxes | | | | | | | | | | | | |
| Operating income | | $ | 91,781 | | | $ | 46,425 | | | $ | 45,135 | |
| Other income | | | 25,729 | | | | 17,570 | | | | 11,437 | |
| | | | | | | | | | |
| Total | | $ | 117,510 | | | $ | 63,995 | | | $ | 56,572 | |
| | | | | | | | | | |
150
The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Income from continuing operations | | $ | 224,540 | | | $ | 132,734 | | | $ | 104,312 | |
| Total income tax expense | | | 117,510 | | | | 63,995 | | | | 56,572 | |
| | | | | | | | | | |
| Pretax income | | | 342,050 | | | | 196,729 | | | | 160,884 | |
| Statutory tax rate | | | 35 | % | | | 35 | % | | | 35 | % |
| | | | | | | | | | |
| Federal income tax expense at statutory rate | | | 119,718 | | | | 68,855 | | | | 56,309 | |
| Depreciation related to difference in cost basis for tax purposes | | | 2,192 | | | | 1,880 | | | | 2,144 | |
| Allowance for funds used during construction — equity | | | (4,114 | ) | | | (6,539 | ) | | | (1,481 | ) |
| ITC amortization | | | (1,619 | ) | | | (1,810 | ) | | | (1,630 | ) |
| Goodwill | | | 1,646 | | | | 1,386 | | | | 1,732 | |
| Research and development credit | | | (1,666 | ) | | | — | | | | — | |
| Other — net | | | 1,353 | | | | 223 | | | | (502 | ) |
| | | | | | | | | | |
| Provision for income taxes before effect of income tax settlements | | $ | 117,510 | | | $ | 63,995 | | | $ | 56,572 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Effective tax rate | | | 34.4 | % | | | 32.5 | % | | | 35.2 | % |
| | | | | | | | | | |
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. The IRS is currently conducting audits of NPC for the years 1997-2004. NPC believes that has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.
151
The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| Deferred income tax assets | | | | | | | | |
| Net operating loss and credit carryovers | | $ | 137,344 | | | $ | 129,420 | |
| Employee benefit plans | | | 29,997 | | | | (530 | ) |
| Customer advances | | | 21,014 | | | | 34,320 | |
| Gross-ups received on contributions in aid of construction and customer advances | | | 21,844 | | | | 18,424 | |
| Deferred revenues | | | 1,586 | | | | 11,303 | |
| Provision for contract termination | | | (4 | ) | | | 43,737 | |
| Other — net | | | 14,207 | | | | 12,797 | |
| | | | | | | |
| Subtotal | | | 225,988 | | | | 249,471 | |
| | | | | | | |
| Deferred income tax assets associated with regulatory matters | | | �� | | | | | |
| Excess deferred income taxes | | | 5,259 | | | | 6,005 | |
| Unamortized investment tax credit | | | 8,192 | | | | 9,063 | |
| | | | | | | |
| Subtotal | | | 13,451 | | | | 15,068 | |
| | | | | | | |
| Total deferred income tax assets before valuation allowance | | | 239,439 | | | | 264,539 | |
| | | | | | | |
| Valuation allowance | | | (732 | ) | | | (984 | ) |
| | | | | | | |
| Total deferred income tax assets after valuation allowance | | $ | 238,707 | | | $ | 263,555 | |
| | | | | | | |
| | | | | | | | | |
| Deferred income tax liabilities | | | | | | | | |
| Excess of tax depreciation over book depreciation | | $ | 345,135 | | | $ | 349,056 | |
| Deferred energy | | | 171,113 | | | | 140,330 | |
| Regulatory assets | | | 59,092 | | | | 11,061 | |
| Other — net | | | 43,299 | | | | 28,169 | |
| | | | | | | |
| Subtotal | | | 618,639 | | | | 528,616 | |
| | | | | | | |
| Deferred income tax liabilities associated with regulatory matters | | | | | | | | |
| Tax benefits flowed through to customers | | | 153,471 | | | | 155,304 | |
| | | | | | | |
| Subtotal | | | 153,471 | | | | 155,304 | |
| | | | | | | |
| Total deferred income tax liability | | $ | 772,110 | | | $ | 683,920 | |
| | | | | | | |
| | | | | | | | | |
| Net deferred income tax liability | | $ | 393,383 | | | $ | 280,129 | |
| Net deferred income tax liability associated with regulatory matters | | | 140,020 | | | | 140,236 | |
| | | | | | | |
| Total net deferred income tax liability | | $ | 533,403 | | | $ | 420,365 | |
| | | | | | | |
The total 2006 net deferred income tax liability of $533,403 includes $5,950 of deferred tax liability associated with accumulated depreciation on the Mohave generating station, which, on the financial statements, is included in regulatory assets. Reference Note 13, Commitments and Contingencies, for further discussion of the Mohave Generating Station.
NPC’s balance sheet contains a net regulatory asset of $140.0 million at December 31, 2006 and $140.2 million at December 31, 2005. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and 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.
As reflected in NPC’s balance sheet (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| Tax benefits flowed through to customers | | | | | | | | |
| Related to property | | $ | 55,177 | | | $ | 54,371 | |
| Related to goodwill | | | 98,294 | | | | 100,933 | |
| | | | | | | |
| Regulatory tax asset | | | 153,471 | | | | 155,304 | |
| | | | | | | | | |
| Liberalized depreciation at rates in excess of current rates | | | 5,259 | | | | 6,005 | |
| Unamortized investment tax credits | | | 8,192 | | | | 9,063 | |
| | | | | | | |
| Regulatory tax liability | | | 13,451 | | | | 15,068 | |
| | | | | | | |
| Net regulatory tax asset | | $ | 140,020 | | | $ | 140,236 | |
| | | | | | | |
152
SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR owes NPC $20.6 million in inter-company tax payments.
The following table summarizes the tax NOL and credit carryforwards and associated carryforward periods, and a valuation allowance for amounts which NPC has determined that realization is uncertain (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Expiration | |
| Type of Carryforward | | Deferred Tax Asset | | | Valuation Allowance | | | Net Deferred Tax Asset | | | Period | |
| Federal NOL | | $ | 125,681 | | | $ | — | | | $ | 125,681 | | | | 2020-2023 | |
| State NOL | | | 9 | | | | — | | | | 9 | | | | 2008 | |
| Research and development credit | | | 1,666 | | | | — | | | | 1,666 | | | | 2021-2025 | |
| Alternative minimum tax credit | | | 8,696 | | | | — | | | | 8,696 | | | indefinite |
| Arizona coal credits | | | 1,292 | | | | 732 | | | | 560 | | | | 2007-2011 | |
| | | | | | | | | | | | | | |
| Total | | $ | 137,344 | | | $ | 732 | | | $ | 136,612 | | | | | |
| | | | | | | | | | | | | | |
At December 31, 2006, NPC has gross federal and state net operating loss carryforwards of $359.1 million and $124 thousand, respectively.
Considering all positive and negative evidence regarding the utilization of NPC’s deferred tax assets, it has been determined that NPC is more-likely-than-not to realize all recorded deferred tax assets, except some of the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2006.
Sierra Pacific Power Company
The following reflects the composition of taxes on income (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Provision (benefit) for income taxes | | | | | | | | | | | | |
| Current | | | | | | | | | | | | |
| Federal | | $ | 28,497 | | | $ | 67,291 | | | $ | 690 | |
| State | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| Total current | | | 28,497 | | | | 67,291 | | | | 690 | |
| | | | | | | | | | | | | |
| Deferred | | | | | | | | | | | | |
| Federal | | | 2,464 | | | | (38,074 | ) | | | 3,676 | |
| State | | | 226 | | | | 2,136 | | | | (708 | ) |
| | | | | | | | | | |
| Total deferred | | | 2,690 | | | | (35,938 | ) | | | 2,968 | |
| | | | | | | | | | | | | |
| Amortization of excess deferred taxes | | | (1,570 | ) | | | (1,345 | ) | | | (1,697 | ) |
| | | | | | | | | | | | | |
| Amortization of investment tax credits | | | (1,788 | ) | | | (1,629 | ) | | | (1,636 | ) |
| |
| | | | | | | | | | |
| Total provision for income taxes | | $ | 27,829 | | | $ | 28,379 | | | $ | 325 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Income statement classification of provision (benefit) for income taxes | | | | | | | | | | | | |
| Operating income | | $ | 23,570 | | | $ | 26,038 | | | $ | 14,978 | |
| Other income | | | 4,259 | | | | 2,341 | | | | (14,653 | ) |
| | | | | | | | | | |
| Total | | $ | 27,829 | | | $ | 28,379 | | | $ | 325 | |
| | | | | | | | | | |
153
The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| Income from continuing operations | | $ | 57,709 | | | $ | 52,075 | | | $ | 18,577 | |
| Total income tax expense | | | 27,829 | | | | 28,379 | | | | 325 | |
| | | | | | | | | | |
| Pretax income | | | 85,538 | | | | 80,454 | | | | 18,902 | |
| Statutory tax rate | | | 35 | % | | | 35 | % | | | 35 | % |
| | | | | | | | | | |
| Federal income tax expense (benefit) at statutory rate | | | 29,938 | | | | 28,159 | | | | 6,616 | |
| Depreciation related to difference in cost basis for tax purposes | | | 2,517 | | | | 2,678 | | | | 2,691 | |
| Allowance for funds used during construction — equity | | | (2,265 | ) | | | (574 | ) | | | (601 | ) |
| ITC amortization | | | (1,788 | ) | | | (1,629 | ) | | | (1,636 | ) |
| Goodwill | | | 954 | | | | 844 | | | | 506 | |
| Pension benefit plan | | | 338 | | | | (945 | ) | | | (3,684 | ) |
| Research and development credit | | | (2,097 | ) | | | — | | | | — | |
| Other — net | | | 232 | | | | (154 | ) | | | (217 | ) |
| | | | | | | | | | |
| Provision for income taxes before effect of income tax settlements | | $ | 27,829 | | | $ | 28,379 | | | $ | 3,675 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Effective tax rate before effects of income tax settlements | | | 32.5 | % | | | 35.3 | % | | | 19.4 | % |
| | | | | | | | | | |
| Effects of income tax settlements | | | — | | | | — | | | | (3,350 | ) |
| | | | | | | | | | |
| Provision for income taxes | | $ | 27,829 | | | $ | 28,379 | | | $ | 325 | |
| | | | | | | | | | |
| Effective tax rate | | | 32.5 | % | | | 35.3 | % | | | 1.7 | % |
| | | | | | | | | | |
As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. The IRS is currently conducting audits of SPPC for the years 1997-2004. During the first quarter of 2004, SPR reached tentative agreements with the IRS for certain matters. As a result of the tentative agreements, SPPC recognized tax benefits which increased net income by approximately $3.4 million in 2004. SPPC believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.
154
The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| | | | | | | | | |
| Deferred income tax assets | | | | | | | | |
| Net operating loss and credit carryforwards | | $ | 6,233 | | | $ | 6,127 | |
| Employee benefit plans | | | 39,191 | | | | 9,997 | |
| Customer advances | | | 11,149 | | | | 25,202 | |
| Gross-ups received on contributions in aid of construction and customer advances | | | 9,269 | | | | 7,438 | |
| Provision for contract termination | | | 200 | | | | 19,378 | |
| Other | | | 7,761 | | | | 6,658 | |
| | | | | | | |
| Subtotal | | | 73,803 | | | | 74,800 | |
| | | | | | | |
| Deferred income tax assets associated with regulatory matters | | | | | | | | |
| Excess deferred income taxes | | | 9,852 | | | | 11,421 | |
| Unamortized investment tax credit | | | 10,772 | | | | 11,735 | |
| | | | | | | |
| Subtotal | | | 20,624 | | | | 23,156 | |
| | | | | | | |
| Total deferred income tax assets | | $ | 94,427 | | | $ | 97,956 | |
| | | | | | | |
| | | | | | | | | |
| Deferred income tax liabilities | | | | | | | | |
| Excess of tax depreciation over book depreciation | | $ | 195,203 | | | $ | 211,645 | |
| Deferred energy | | | 21,540 | | | | 40,158 | |
| Regulatory assets | | | 41,346 | | | | 9,079 | |
| Other | | | 14,035 | | | | 9,193 | |
| | | | | | | |
| Subtotal deferred tax liabilities | | | 272,124 | | | | 270,075 | |
| | | | | | | |
| Deferred income tax liabilities associated with regulatory matters | | | | | | | | |
| Tax benefits flowed through to customers | | | 109,699 | | | | 93,957 | |
| | | | | | | |
| Total deferred income tax liability | | $ | 381,823 | | | $ | 364,032 | |
| | | | | | | |
| | | | | | | | | |
| Net deferred income tax liability | | $ | 198,321 | | | $ | 195,275 | |
| Net deferred income tax liability associated with regulatory matters | | | 89,075 | | | | 70,801 | |
| | | | | | | |
| Total net deferred income tax liability | | $ | 287,396 | | | $ | 266,076 | |
| | | | | | | |
SPPC’s balance sheet contains a net regulatory asset of $89.0 million at December 31, 2006 and $70.8 million at December 31, 2005. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and 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.
155
As reflected in SPPC’s balance sheet (dollars in thousands):
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| | | | | | | | | |
| Tax benefits flowed through to customers | | | | | | | | |
| Related to property | | $ | 50,998 | | | $ | 43,959 | |
| Related to goodwill | | | 58,701 | | | | 49,998 | |
| | | | | | | |
| Regulatory tax asset | | | 109,699 | | | | 93,957 | |
| | | | | | | | | |
| Liberalized depreciation at rates in excess of current rates | | | 9,852 | | | | 11,421 | |
| Unamortized investment tax credits | | | 10,772 | | | | 11,735 | |
| | | | | | | |
| Regulatory tax liability | | | 20,624 | | | | 23,156 | |
| | | | | | | |
| Net regulatory tax asset | | $ | 89,075 | | | $ | 70,801 | |
| | | | | | | |
SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiaries’ respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. Per the Company’s tax sharing agreement, SPPC owes SPR $9.1 million in current taxes payable.
The following table summarizes the tax NOL and credit carryforwards and associated carryforward periods for SPPC (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Expiration | |
| Type of Carryforward | | Deferred Tax Asset | | | Valuation Allowance | | | Net Deferred Tax Asset | | | Period | |
| Federal NOL | | $ | 5,184 | | | $ | — | | | $ | 5,184 | | | | 2020-2023 | |
| State NOL | | | 1,049 | | | | — | | | | 1,049 | | | | 2010-2013 | |
| | | | | | | | | | | | | | |
| Total | | $ | 6,233 | | | $ | — | | | $ | 6,233 | | | | | |
| | | | | | | | | | | | | | |
At December 31, 2006, SPPC has gross federal and state net operating loss carryforwards of $14.8 million and $11.9 million, respectively.
Considering all positive and negative evidence regarding the utilization of SPPC’s deferred tax assets, it has been determined that the company is more-likely-than-not to realize all recorded deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2006.
NOTE 11. 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 tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. This reconciliation is based on a September 30 measurement date (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Other Postretirement | |
| | | Pension Benefits | | | Benefits | |
| | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| | | | | |
Change in benefit obligations | | | | | | | | | | | | | | | | |
| Benefit obligation, beginning of year | | $ | 625,451 | | | $ | 519,785 | | | $ | 179,184 | | | $ | 162,013 | |
| Service cost | | | 23,033 | | | | 18,481 | | | | 3,533 | | | | 3,281 | |
| Interest cost | | | 36,627 | | | | 32,248 | | | | 10,283 | | | | 9,858 | |
| Plan Participants’ contributions | | | — | | | | — | | | | 1,445 | | | | 1,180 | |
| Actuarial loss (gain) | | | (18,713 | ) | | | 71,536 | | | | (10,770 | ) | | | 10,258 | |
| Gross Benefits paid | | | (20,960 | ) | | | (20,257 | ) | | | (11,998 | ) | | | (8,112 | ) |
| less: federal subsidy on benefits paid | | | N/A | | | | N/A | | | | (515 | ) | | | — | |
| Plan amendments | | | (65 | ) | | | 2,935 | | | | — | | | | 695 | |
| Acquisitions/divestitures | | | — | | | | — | | | | — | | | | — | |
| Special Termination Benefits | | | — | | | | 723 | | | | — | | | | 11 | |
| Curtailments | | | — | | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Benefit obligation, end of year | | $ | 645,373 | | | $ | 625,451 | | | $ | 171,162 | | | $ | 179,184 | |
| | | | | | | | | | | | | |
156
The accumulated benefit obligation for Pension Benefits at the end of 2006 and 2005 was $526 million and $504 million respectively.
The weighted-average actuarial assumptions used to determine end of year benefit obligations were as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | Pension Benefits | | Other Postretirement Benefits |
| | | 2006 | | 2005 | | 2006 | | 2005 |
| Discount rate | | | 6.00 | % | | | 5.75 | % | | | 6.00 | % | | | 5.75 | % |
| Rate of compensation increase | | | 4.50 | % | | | 4.50 | % | | | N/A | | | | N/A | |
In 2006, for measurement purposes, the assumed annual rate of increase in the per capita cost of covered health care benefits was 8%, grading down to 5% in 2013.
In selecting an assumed discount rate for fiscal year 2006 pension cost, SPR considered the yield on high quality bonds as measured by Moody’s Investors Service, Inc. (Moody’s) Aa composite bond index. However, to select an assumed discount rate for fiscal year-end 2006 disclosures and for fiscal year 2006 pension cost, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
| | | | | | | | | |
| Effect on the postretirement benefit obligation | | 2006 | | 2005 |
| | | | | |
| Effect of a 1-percentage point increase | | $ | 18,823 | | | $ | 21,237 | |
| Effect of a 1-percentage point decrease | | $ | (15,657 | ) | | $ | (17,410 | ) |
The following table shows the change in plan assets for 2006 and 2005. SPR contributions for the other post-retirement benefits reflect benefit payments made by SPR (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Other Postretirement | |
| | | Pension Benefits | | | Benefits | |
| | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| | | | | |
Change in plan assets | | | | | | | | | | | | | | | | |
| Fair value of plan assets, beginning of year | | $ | 488,766 | | | $ | 436,291 | | | $ | 53,223 | | | $ | 50,484 | |
| Adjustment to beginning of year value | | | — | | | | — | | | | — | | | | (1,766 | ) |
| Actual return on plan assets | | | 34,424 | | | | 55,706 | | | | 8,015 | | | | 386 | |
| Employer contributions | | | 32,329 | | | | 17,026 | | | | 12,550 | | | | 10,928 | |
| Plan participants’ contributions | | | — | | | | — | | | | 1,445 | | | | 1,303 | |
| Gross benefits paid | | | (20,960 | ) | | | (20,257 | ) | | | (11,998 | ) | | | (8,112 | ) |
| Acquisitions | | | — | | | | — | | | | — | | | | — | |
| Special termination benefits | | | — | | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | — | | | | — | | | | — | |
| Expenses paid | | | (299 | ) | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Fair value of plan assets, end of year | | $ | 534,260 | | | $ | 488,766 | | | $ | 63,235 | | | $ | 53,223 | |
| | | | | | | | | | | | | |
The asset allocation for SPR’s pension plans at the end of 2006 and 2005, and the target allocation for 2007, by asset category, follows. The fair value of plan assets for these plans is $534.2 million and $488.8 million, at the end of 2006 and 2005, respectively. The asset values are determined using quoted market prices. The expected long-term rate of return on these plan assets was 8.25% in 2006 and 2005.
| | | | | | | | | | | | | |
| | | Target Allocation Percentage of Plan Assets at Year End |
| Asset Category | | 2007 | | 2006 | | 2005 |
| Equity securities | | | 60 | % | | | 60 | % | | | 60 | % |
| Debt securities | | | 39 | | | | 39 | | | | 39 | |
| Other | | | 1 | | | | 1 | | | | 1 | |
| | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | |
157
The asset allocation for the other postretirement benefit plans at the end of 2006 and 2005, and target allocation for 2007, by asset category, follows. The fair value of plan assets for these plans is $63.2 million and $53.2 million at the end of 2006 and 2005, respectively. The asset values are determined using recorded closing sales on a national securities exchange. The expected long-term rate of return on these plan assets was 8.25% in 2006 and 2005.
| | | | | | | | | | | | | |
| | | Target Allocation Percentage of Plan Assets at Year End |
| Asset Category | | 2007 | | 2006 | | 2005 |
| Equity securities | | | 60 | % | | | 60 | % | | | 60 | % |
| Debt securities | | | 39 | | | | 39 | | | | 39 | |
| Other | | | 1 | | | | 1 | | | | 1 | |
| | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | |
SPR’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan. SPR strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, SPR considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan. SPR’s investment guidelines prohibit investing the plan assets in real estate and SPR’s own stock. Currently, the plan assets are invested in international and domestic equity securities, and fixed securities which include bonds.
The following table shows the funded status of each of the plans for 2006 and 2005 (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Other Postretirement | |
| | | Pension Benefits | | | Benefits | | |
| Funded Status, end of year: | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| | | | | |
| Fair value of plan assets | | $ | 534,260 | | | $ | 488,767 | | | $ | 63,236 | | | $ | 53,223 | |
| Benefit obligations | | $ | (645,373 | ) | | $ | (625,451 | ) | | $ | (172,192 | ) | | $ | (179,184 | ) |
| | | | | | | | | | | | | |
| Funded status | | $ | (111,113 | ) | | $ | (136,684 | ) | | $ | (108,956 | ) | | $ | (125,961 | ) |
| Unrecognized net actuarial (gain)/loss | | | N/A | | | | 166,157 | | | | N/A | | | | 77,919 | |
| Unrecognized prior service (credit)/cost | | | N/A | | | | 14,543 | | | | N/A | | | | 1,228 | |
| Unrecognized net transition (asset)/obligation | | | N/A | | | | — | | | | N/A | | | | 6,405 | |
| Contribution between measurement date and fiscal year end | | | 368 | | | | 15,332 | | | | — | | | | 4,101 | |
| | | | | | | | | | | | | |
| Amount recognized, end of year | | $ | (110,745 | ) | | $ | 59,348 | | | $ | (108,956 | ) | | $ | (36,308 | ) |
| | | | | | | | | | | | | |
Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Other Postretirement | |
| | | Pension Benefits | | | Benefits | |
| Amounts recognized in the statement | | | | | | | | | | | | |
| of financial position consist of: | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| | | | | |
| Noncurrent asset | | $ | — | | | | N/A | | | $ | — | | | | N/A | |
| Current liability | | | (1,482 | ) | | | N/A | | | | — | | | | N/A | |
| Noncurrent liability | | | (109,263 | ) | | | N/A | | | | (108,956 | ) | | | N/A | |
| Prepaid benefit cost | | | N/A | | | $ | 75,769 | | | | N/A | | | | N/A | |
| Accrued benefit cost | | | N/A | | | | (16,421 | ) | | | N/A | | | $ | (36,308 | ) |
| Additional minimum liability | | | N/A | | | | (7,950 | ) | | | N/A | | | | N/A | |
| Intangible asset | | | N/A | | | | 15 | | | | N/A | | | | N/A | |
| Accumulated other comprehensive income | | | N/A | | | | 7,935 | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | |
| Net amount recognized | | $ | (110,745 | ) | | $ | 59,348 | | | $ | (108,956 | ) | | $ | (36,308 | ) |
| | | | | | | | | | | | | |
158
The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of SFAS 158, which the Company adopted in 2006. Since the Company is able to recover SFAS 87 and SFAS 106 expenses through rates, the amounts will be recorded as Other Regulatory Assets under the provisions of SFAS 71.
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Other Postretirement | |
| | | Pension Benefits | | | Benefits | |
| Amounts recognized as other | | | | | | | | | | | | |
| regulatory assets: | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| Net actuarial (gain)/loss | | $ | 101,674 | | | | N/A | | | $ | 102,413 | | | | N/A | |
| Prior service (credit)/cost | | | 12,587 | | | | N/A | | | | 1,107 | | | | N/A | |
| Transition (asset)/obligation | | | — | | | | N/A | | | | 5,436 | | | | N/A | |
| | | | | | | | | | | | | |
| | | $ | 114,261 | | | | N/A | | | $ | 108,956 | | | | N/A | |
| | | | | | | | | | | | | |
The estimated amounts that will be amortized from other regulatory assets into net periodic cost in 2007 are as follows:
| | | | | | | | | |
| | | | | | | Other | |
| | | Pension Benefits | | | Postretirement | |
| | | | | | Benefits | |
| | | | | | |
| Actuarial (gain)/loss | | $ | 7,184 | | | $ | 3,259 | |
| Prior service (credit)/cost | | | 1,629 | | | | 122 | |
| Transition (asset)/obligation | | | — | | | | 969 | |
At the end of 2006 and 2005, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):
| | | | | | | | | | | | | | | | | |
| | | Projected Benefit Obligation Exceeds | | | Accumulated Benefit Obligation Exceeds | |
| | | the Fair Value of Plan’s Assets | | | the Fair Value of Plan’s Assets | |
| | | 2006 | | 2005 | | | | 2006 | | 2005 | |
| Projected benefit obligation, end of year | | $ | 645,373 | | $ | 625,451 | | | | $ | 25,890 | | $ | 27,225 | | |
| Accumulated benefit obligation, end of year | | | — | | | — | | | | | 23,768 | | | 24,703 | | |
| Fair value of plan assets, end of year | | | 534,260 | | | 488,766 | | | | | — | | | — | | |
The accumulated postretirement benefit obligation exceeds plan assets for all of the company’s other postretirement benefit plans.
The expected cash flows for the plans are as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | Pension Benefits | | | Other Postretirement Benefits |
| | | | | | |
Company contributions | | | | | | | | | | | | |
| 2007 (expected) | | $ | 1,482 | | | | $12,465 |
| |
|
| | | Pension Benefits | | | Other Postretirement Benefits |
| | | | | | | | | | | Expected Federal |
| | | | | | | | Gross | Subsidy |
Expected benefit payments | | | | | | | | | | | | |
| 2007 | | | 23,595 | | | | 9,209 | | | | 597 | |
| 2008 | | | 24,903 | | | | 9,812 | | | | 670 | |
| 2009 | | | 26,668 | | | | 10,372 | | | | 770 | |
| 2010 | | | 28,684 | | | | 11,028 | | | | 853 | |
| 2011 | | | 30,887 | | | | 11,611 | | | | 843 | |
| 2012-2016 | | | 196,777 | | | | 66,337 | | | | 4,993 | |
The above benefit payments are obligations of the indicated plan, and reflect payments which do not include employee contributions. The expected benefit payment information that reflects the employee obligation is almost exclusively paid from plan assets. A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.
159
The components of net periodic pension and other postretirement benefit costs for the consolidated companies, SPPC and NPC are presented below (dollars in thousands):
Sierra Pacific Resources, consolidated
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | | | |
| Service cost | | $ | 23,033 | | | $ | 18,481 | | | $ | 17,988 | | | $ | 3,533 | | | $ | 3,281 | | | $ | 3,058 | |
| Interest cost | | | 36,627 | | | | 32,248 | | | | 30,273 | | | | 10,283 | | | | 9,858 | | | | 9,258 | |
| Expected return on plan assets | | | (40,729 | ) | | | (36,167 | ) | | | (30,632 | ) | | | (4,919 | ) | | | (3,862 | ) | | | (4,100 | ) |
| Amortization of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Actuarial (gain)/loss | | | 9,778 | | | | 6,454 | | | | 8,971 | | | | 4,614 | | | | 3,782 | | | | 4,129 | |
| Prior service (credit)/cost | | | 1,892 | | | | 1,714 | | | | 1,714 | | | | 122 | | | | 63 | | | | 63 | |
| Transition (asset)/obligation | | | — | | | | — | | | | — | | | | 969 | | | | 969 | | | | 969 | |
| Curtailment (gain)/loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Settlement (gain)/loss / Special termination charges | | | — | | | | 723 | | | | — | | | | — | | | | 11 | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Total net benefit cost | | $ | 30,601 | | | $ | 23,453 | | | $ | 28,314 | | | $ | 14,602 | | | $ | 14,102 | | | $ | 13,377 | |
| | | | | | | | | | | | | | | | | | | |
The average percentage of SPR net periodic costs capitalized during 2006, 2005 and 2004 was 35.5%, 34.1%, and 32.1%, respectively.
Nevada Power Company
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | | | |
| Service cost | | $ | 12,900 | | | $ | 10,328 | | | $ | 9,770 | | | $ | 1,052 | | | $ | 887 | | | $ | 798 | |
| Interest cost | | | 17,466 | | | | 15,064 | | | | 13,824 | | | | 2,105 | | | | 1,977 | | | | 1,892 | |
| Expected return on plan assets | | | (18,265 | ) | | | (16,025 | ) | | | (12,564 | ) | | | (1,079 | ) | | | (832 | ) | | | (885 | ) |
| Amortization of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Actuarial (gain)/loss | | | — | | | | — | | | | — | | | | 940 | | | | 758 | | | | 844 | |
| Prior service (credit)/cost | | | 1,677 | | | | 1,499 | | | | 1,499 | | | | 122 | | | | 63 | | | | 63 | |
| Transition (asset)/obligation | | | 4,636 | | | | 2,995 | | | | 4,069 | | | | 969 | | | | 969 | | | | 969 | |
| Curtailment (gain)/loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Settlement (gain)/loss / Special termination charges | | | — | | | | 723 | | | | — | | | | — | | | | 11 | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Total net benefit cost | | $ | 18,414 | | | $ | 14,584 | | | $ | 16,598 | | | $ | 4,109 | | | $ | 3,833 | | | $ | 3,681 | |
| | | | | | | | | | | | | | | | | | | |
The average percentage of NPC net periodic costs capitalized during 2006, 2005 and 2004 was 39.0%, 37.3%, and 33.7%, respectively.
Sierra Pacific Power Company
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | | | |
| Service cost | | $ | 8,989 | | | $ | 7,470 | | | $ | 7,540 | | | $ | 2,417 | | | $ | 2,264 | | | $ | 2,135 | |
| Interest cost | | | 18,224 | | | | 16,526 | | | | 15,820 | | | | 8,114 | | | | 7,793 | | | | 7,284 | |
| Expected return on plan assets | | | (21,617 | ) | | | (19,418 | ) | | | (17,558 | ) | | | (3,715 | ) | | | (2,929 | ) | | | (3,114 | ) |
| Amortization of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Actuarial (gain)/loss | | | — | | | | — | | | | — | | | | 3,646 | | | | 2,994 | | | | 3,252 | |
| Prior service (credit)/cost | | | 212 | | | | 212 | | | | 213 | | | | — | | | | — | | | | — | |
| Transition (asset)/obligation | | | 4,880 | | | | 3,320 | | | | 4,715 | | | | — | | | | — | | | | — | |
| Curtailment (gain)/loss | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Settlement (gain)/loss / Special termination charges | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Total net benefit cost | | $ | 10,688 | | | $ | 8,110 | | | $ | 10,730 | | | $ | 10,462 | | | $ | 10,122 | | | $ | 9,557 | |
| | | | | | | | | | | | | | | | | | | |
160
The average percentage of SPPC net periodic costs capitalized during 2006, 2005 and 2004 was 33.3%, 32.1%, and 31.6%, respectively.
The weighted-average assumptions used to determine net periodic cost are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Postretirement Benefits |
| | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 |
| | | | | |
| Discount rate | | | 5.75 | % | | | 6.10 | % | | | 6.00 | % | | | 5.75 | % | | | 6.10 | % | | | 6.00 | % |
| Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.50 | % | | | 8.25 | % | | | 8.25 | % | | | 8.50 | % |
| Rate of compensation increase | | | 4.50 | % | | | 4.50 | % | | | 4.50 | % | | | N/A | | | | N/A | | | | N/A | |
For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006. The rate was assumed to remain at 6% in all future years.
The expected rate of return on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected rates of return on reinvested assets.
The expected long-term rate of return on plan assets is 8.25% in 2007.
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 effect:
| | | | | | | | | | | | | |
| One percentage point change: | | 2006 | | 2005 | | 2004 |
| | | |
| Effect on total of service and interest cost components | | | | | | | | | | | | |
| Effect of a 1-percentage point increase in health care trend | | | 1,669 | | | | 1,872 | | | | 1,845 | |
| Effects of a 1-percentage point decrease in health care trend | | | (1,360 | ) | | | (1,503 | ) | | | (1,486 | ) |
There were no significant transactions between the plan and the employer or related parties during 2006, 2005, or 2004.
NOTE 12. STOCK COMPENSATION PLANS
At December 31, 2006, SPR 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 in May 2004, provides for the issuance of up to 7,750,000 of SPR’s common shares to key employees through December 31, 2013. 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 2006, SPR issued nonqualified stock options, restricted shares and performance shares under the long-term incentive plan.
Non-Qualified Stock Options
Elected officers and key employees specifically designated by a committee of the Board of Directors are eligible to be awarded nonqualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods, as stated in the grant. These options have to be exercised within ten years of award, and no earlier than one year from the date of grant. At the time of grant, rights to dividend equivalents may also be awarded.
The total number of nonqualifying stock options granted to all employees in 2006 was 176,416, which were issued at an option price not less than market value at the date of grant. Of this amount, 144,304 will vest over three years from the grant date at one-third per year, 30,000 will vest one year from the date of grant, and the remaining 2,112 will vest only upon the restoration of the quarterly common stock dividend within five years of the date of grant; otherwise, these shares will expire unvested. The 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. The Committee also allows cashless exercises, subject to applicable securities law restrictions or other means consistent with the purpose of the plan and the applicable law.
A summary of the status of SPR’s nonqualified stock option plan as of December 31, 2006, 2005, and 2004, and changes during the year is presented below:
161
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | Weighted- | | | | | | | Weighted- | | | | | | | Weighted- | |
| | | | | | | Average | | | | | | | Average | | | | | | | Average | |
| | | | | | | Exercise | | | | | | | Exercise | | | | | | | Exercise | |
| Nonqualified Stock Options | | Shares | | | Price | | | Shares | | | Price | | | Shares | | | Price | |
| Outstanding at beginning of year | | | 1,077,772 | | | $ | 14.38 | | | | 1,227,950 | | | $ | 15.91 | | | | 1,371,869 | | | $ | 16.33 | |
| Granted | | | 176,416 | | | $ | 13.29 | | | | 169,036 | | | $ | 10.10 | | | | 45,000 | | | $ | 7.29 | |
| Exercised | | | 55,000 | | | $ | 5.69 | | | | 28,000 | | | $ | 6.83 | | | | 18,000 | | | $ | 5.39 | |
| Forfeited | | | — | | | $ | — | | | | 291,214 | | | $ | 18.73 | | | | 170,919 | | | $ | 17.41 | |
| Outstanding at end of year | | | 1,199,188 | | | $ | 14.66 | | | | 1,077,772 | | | $ | 14.38 | | | | 1,227,950 | | | $ | 15.91 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Intrinsic value of options exercised | | $ | 571,190 | | | $ | — | | | $ | 147,240 | | | $ | — | | | $ | 33,920 | | | | | |
| Fair value of options vested | | $ | 246,798 | | | $ | — | | | $ | 36,750 | | | $ | — | | | $ | 111,011 | | | | | |
| Options exercisable at year-end | | | 943,085 | | | $ | 15.25 | | | | 928,368 | | | $ | 15.07 | | | | 1,215,450 | | | $ | 15.99 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average grant date fair value of options granted1: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average of all grants for: | | | | | | | | | | | | | | | | | | | | | | | | |
| 2006 | | $ | 4.82 | | | | | | | | | | | | | | | | | | | | | |
| 2005 | | | | | | | | | | $ | 5.52 | | | | | | | | | | | | | |
| 2004 | | | | | | | | | | | | | | | | | | $ | 4.96 | | | | | |
| (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 2006, 2005 and 2004: |
| | | | | | | | | | | | | | | | | |
| | | Average | | Average | | Average | | |
| | | Dividend | | Expected | | Risk- | | Average Expected |
| Year of Option Grant | | Yield | | Volatility | | Free Rate of Return | | Life |
| 2006 | | | 0.00 | % | | | 27.06 | % | | | 4.51 | % | | 6 years |
| 2005 | | | 0.00 | % | | | 39.56 | % | | | 2.32 | % | | 10 years |
| 2004 | | | 0.00 | % | | | 52.60 | % | | | 4.79 | % | | 10 years |
The following table summarizes information about nonqualified stock options outstanding at December 31, 2006:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Options Outstanding | | Options Exercisable |
| | | Weighted | | Number | | | | | | | | | | Number Vested and |
| | | Average | | Outstanding at | | Remaining | | Weighted Average | | Exercisable at |
| Year of Grant | | Exercise Price | | 12/31/06 | | Contractual Life | | Exercise Price | | 12/31/06 |
| 1997 | | $ | 19.97 | | | | 3,188 | | | < 1 year | | $ | 19.97 | | | | 3,188 | |
| 1998 | | $ | 24.93 | | | | 15,840 | | | 1 years | | $ | 24.93 | | | | 15,840 | |
| 1999 | | $ | 25.35 | | | | 36,440 | | | 2 years | | $ | 25.35 | | | | 36,440 | |
| 2000 | | $ | 16.00 | | | | 400,000 | | | 2.6 - 3 years | | $ | 16.00 | | | | 400,000 | |
| 2001 | | $ | 15.08 | | | | 151,540 | | | 4 - 4.9 years | | $ | 15.08 | | | | 151,540 | |
| 2002 | | $ | 14.05 | | | | 241,360 | | | 5 - 5.9 years | | $ | 14.05 | | | | 241,360 | |
| 2004 | | $ | 7.29 | | | | 25,000 | | | 7.5 years | | $ | 7.29 | | | | 25,000 | |
| 2005 | | $ | 10.10 | | | | 149,404 | | | 8.2 - 8.4 years | | $ | 10.10 | | | | 69,717 | |
| 2006 | | $ | 13.29 | | | | 176,416 | | | 9.1 years | | $ | 13.29 | | | | — | |
| Weighted Average Remaining Contractual Life | | | | | | | | | | 5.03 years | | | | | | 4.12 years |
| Intrinsic Value | | $ | 3,136,677 | | | | | | | | | $ | 1,975,871 | | | |
Dividend Equivalents were not granted for any of these awards.
162
Performance Shares
In 2006, 2005 and 2004, SPR granted performance shares in the following numbers and initial values:
| | | | | | | | | | | | | |
| | | 2/7/2006 | | | 2/7/2005 | | | 1/16/2004 | |
| | | |
| Shares Granted | | | 675,056 | | | | 214,596 | | | | 280,082 | |
| Value per Share | | $ | 10.03 | | | $ | 9.58 | | | $ | 7.99 | |
In 2006 and 2005, 172,446 and 171,676 shares of stock, respectively, were granted to plan participants; the actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three-year performance periods. 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. Sierra Pacific Resources, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof.
Also awarded in 2006 were 2,610 special grant shares to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant.
In August, 2006, upon the signing of an employment agreement for the Chief Executive Officer, a grant of 500,000 performance shares was issued according to the agreement. The grant requires the achievement of specific performance goals which were established in the agreement. The final determination and approval of the number of shares awarded is at the discretion of the Board of Directors and the Compensation Committee. In 2006, 65,000 shares were deemed to have been earned and were issued.
Also granted in 2005, were 42,920 special grant shares to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant.
In 2004, SPR granted 280,082 shares of performance shares, which were subsequently reclassified as restricted stock. These grants are included in the discussion below of Restricted Stock.
SPR adopted SFAS 123R “Share Based Payment” in 2006, and according to the requirements set forth in that standard, recognized expense in 2006 related to performance shares. For purposes of determining 2006 expense, the compensation cost has been estimated using a lattice binomial pricing model with the following assumptions used for 2006:
| | | | | | | | | | | | | | | | | |
| | | | | | | Average | | Average Risk- | | Weighted |
| | | Average | | Expected | | Free Rate of | | Average Fair |
| Year | | Dividend Yield | | Volatility | | Return | | Value |
| 2006 | | | 0.00 | % | | | 39.03 | % | | | 4.57 | % | | $ | 13.93 | |
The total value of share based liabilities paid in 2006, 2005 and 2004 were $1,447,300, $819,117 and $876,772, respectively. The total value of shares vested in 2006, 2005 and 2004 were $2,046,124, $807,942 and $0.00, respectively.
Restricted Stock Shares
In 2006, 5,643 shares of restricted stock were awarded at a grant price of $13.29 per share; this grant was fully vested on December 31, 2006 and the shares were issued in early 2007.
There were no restricted shares granted in 2005.
In 2004, SPR granted 280,082 performance shares, which were subsequently reclassified as restricted stock. Due to the achievement of certain performance goals established for this grant, the number of shares available under this grant was increased to 297,587. This grant vested on December 31, 2006, and 222,327 shares were issued in early 2007. The remaining 2004 grant of 3,700
163
restricted shares was issued at a grant price of $6.83 per share, and will vest over three years at one-third per year. In 2005, the remaining 2,467 shares available under this grant were forfeited.
In 2003, SPR granted 448,576 shares of restricted stock at an average grant price of $5.93 per share. Of the shares granted, 438,576 shares will vest over 4 years with one-third becoming available in each of the years ended December 31, 2004, 2005 and 2006. The remaining 10,000 shares will vest over three years at one-third per year. In 2006, according to the vesting schedule for each grant, 131,297 shares were issued under these grants.
A grant of 1,500 restricted shares was made in 2002, at a grant price of $7.35, vesting equally over 4 years. In 2006, 375 shares were issued according to the terms of this grant.
The total value of share based liabilities paid in 2006, 2005, and 2004 were $1,500,321, $1,405,724 and $301,111, respectively. The total value of shares vested in 2006, 2005 and 2004 were $5,750,643, $1,596,657 and $1,406,496, respectively.
Employee Stock Purchase Plan
Upon the inception of SPR’s employee stock purchase plan, SPR was authorized to issue up to an aggregate of 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 the lesser of 90% of the market value on the offering commencement date, or 100% of the market value on the offering exercise date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan SPR sold 55,954, 53,162 and 77,511 shares to employees in 2006, 2005 and 2004, respectively.
SPR adopted SFAS 123R “Share Based Payment” in 2006, and according to the requirements set forth in that standard, recognized expense in 2006 related to the employee stock purchase plan. For purposes of determining the 2006 expense and the 2005 & 2004 pro forma disclosures, 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 2006, 2005 and 2004, with an option life of six months:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Average | | |
| | | Average | | Average | | Risk-Free | | Weighted |
| | | Dividend | | Expected | | Rate of | | Average |
| Year | | Yield | | Volatility | | Return | | Fair Value |
| 2006 | | | 0.00 | % | | | 19.73 | % | | | 4.95 | % | | $ | 2.62 | |
| 2005 | | | 0.00 | % | | | 35.87 | % | | | 2.23 | % | | $ | 2.65 | |
| 2004 | | | 0.00 | % | | | 52.60 | % | | | 1.79 | % | | $ | 2.24 | |
NOTE 13. COMMITMENTS AND CONTINGENCIES (SPR, NPC and SPPC)
Purchased Power
The utilities have several contracts for long-term purchase of electric energy. Expiration of these contracts ranges from 2008 to 2027. Estimated future commitments under non-cancelable agreements as of December 31, 2006 were as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | | | | | Purchased Power | | | | |
| | | NPC | | | SPPC | | | SPR(1) | |
| 2007 | | $ | 310,988 | | | $ | 163,165 | | | $ | 462,402 | |
| 2008 | | | 257,739 | | | | 125,161 | | | | 368,810 | |
| 2009 | | | 239,361 | | | | 98,028 | | | | 323,215 | |
| 2010 | | | 244,305 | | | | 93,836 | | | | 323,882 | |
| 2011 | | | 242,671 | | | | 95,231 | | | | 323,541 | |
| Thereafter | | | 2,868,242 | | | | 1,308,566 | | | | 3,925,708 | |
(1) Amounts differ for SPR due to the elimination of certain inter-company contracts.
164
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 2007 to 2023. Estimated future commitments under non-cancelable agreements as of December 31, 2006 were as follows (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Coal and Gas | | Transportation |
| | | NPC | | SPPC | | Total | | NPC | | SPPC | | Total |
| 2007 | | $ | 202,156 | | | $ | 127,037 | | | $ | 329,193 | | | $ | 48,045 | | | $ | 74,031 | | | $ | 122,076 | |
| 2008 | | | 26,019 | | | | 26,919 | | | | 52,938 | | | | 36,814 | | | | 58,099 | | | | 94,913 | |
| 2009 | | | 13,261 | | | | 24,964 | | | | 15,138 | | | | 36,814 | | | | 48,428 | | | | 85,242 | |
| 2010 | | | 10,293 | | | | — | | | | 10,293 | | | | 36,814 | | | | 48,418 | | | | 85,232 | |
| 2011 | | | — | | | | — | | | | — | | | | 34,438 | | | | 48,418 | | | | 82,856 | |
| Thereafter | | | — | | | | — | | | | — | | | | 183,550 | | | | 361,358 | | | | 544,908 | |
Long-Term Service Agreements
NPC entered into a long-term service agreement in December 2005 to perform maintenance on generation units located at the Chuck Lenzie Generation Station. An additional long-term service agreement was entered into in January 2006 for maintenance of the generation units at the Silverhawk Generation Station. Future commitments under these agreements are as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | Long Term Service Agreements (1) |
| | | Lenzie | | Silverhawk | | Total |
| 2007 | | $ | 11,258 | | | $ | 4,721 | | | $ | 15,979 | |
| 2008 | | | 11,258 | | | | 2,609 | | | | 13,867 | |
| 2009 | | | 11,258 | | | | 13,009 | | | | 24,267 | |
| 2010 | | | 11,258 | | | | 10,779 | | | | 22,037 | |
| 2011 | | | 9,062 | | | | 3,086 | | | | 12,148 | |
| Thereafter | | | 90,340 | | | | 33,443 | | | | 123,783 | |
(1) Does not include equipment and services contracts related to the new peaking units at Clark Generating Station.
Leases
SPPC has an operating lease for its general offices. 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, NPC’s and SPPC’s estimated future minimum cash payments, including SPPC’s headquarters building, under non-cancelable operating leases as of December 31, 2006, were as follows (dollars in thousands):
| | | | | | | | | | | | | |
| | | Operating Leases | |
| | | NPC | | | SPPC | | | Total | |
| 2007 | | $ | 6,525 | | | $ | 10,635 | | | $ | 17,160 | |
| 2008 | | | 7,146 | | | | 10,297 | | | | 17,443 | |
| 2009 | | | 6,253 | | | | 8,931 | | | | 15,184 | |
| 2010 | | | 5,161 | | | | 7,587 | | | | 12,748 | |
| 2011 | | | 3,441 | | | | 778 | | | | 4,219 | |
| Thereafter | | | 64,459 | | | | 36,587 | | | | 101,046 | |
165
Environmental
Nevada Power Company
Reid Gardner Station
In August 1999, the Nevada Department of Environmental Protection (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 following 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Any future ponds will be double-lined with inter-liner leak detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005.
Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.
In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and December 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. In July 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. In July, 2005 NPC received a letter from the Environmental Protection Agency (EPA) requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request. In June, 2006, the EPA issued a Finding and Notice of Violation (NOV).
NPC has progressed to the final draft stage of dialogue and settlement discussions with NDEP, EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that may be required to achieve a settlement of the alleged violations. Management has booked an estimated minimum liability with respect to these matters. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in NPC’s 2006 Integrated Resource Plan (IRP) filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen.
Clark Station
In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the DAQEM 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. In October 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act. NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations. Monetary penalties are not expected to be material and certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006 IRP filing.
NEICO
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 has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.
166
Sierra Pacific Power Company
PCB Treatment, Inc.
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 completed site investigations and along with the EPA determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The cleanup has now been completed on both buildings and are pending inspection and sign off by EPA. The cleanup for the two buildings came in under budget, as such, SPPC does not expect any further obligations.
Litigation
Nevada Power Company and Sierra Pacific Power Company
Enron Litigation
Settlement Agreement
On February 1, 2006, the Utilities completed the settlement of long-term, ongoing litigation involving Enron’s market manipulation during the Western United States energy crisis and Enron’s claims with respect to terminated purchase power contracts between Enron Power Marketing Inc. (“Enron”) and the Utilities in accordance with the terms of the Settlement Agreement, entered into as of November 15, 2005 among the Utilities, Enron, and other related Enron affiliates (the “Settlement Agreement”). The Settlement Agreement provided for the settlement and release of the on-going litigation, regulatory proceedings, appellate proceedings, proofs of claim and other claims between Enron and the Utilities related to these matters. The Settlement Agreement received approval from the Enron Bankruptcy Court on December 15, 2005. The FERC’s approval of the Settlement Agreement was received on January 25, 2006, which triggered the mutual releases and discharges of all past, existing and future claims between the parties.
On January 26, 2006, upon final approval of the settlement with Enron, the Utilities paid Enron approximately $129 million from available cash resources. On January 27, 2006, the approximate $60 million cash held in escrow, plus interest, and NPC’s General and Refunding Series H Bond of approximately $185.7 million and SPPC’s General and Refunding Series E Bond of approximately $92.3 million were returned to the Utilities. As part of the settlement, NPC and SPPC were granted general unsecured claims (the “Unsecured Claims”) in Class Six of Enron’s Plan of Reorganization in the amount of $80.7 million and $45.8 million, respectively. On October 24, 2005, the Utilities purchased a put option from a major international banking institution that, if exercised, obligated that institution to purchase the Unsecured Claims (contingent upon allowance of the Unsecured Claims by the Bankruptcy Court), which ensured that the Utilities’ net cash outlay to settle Enron’s claim would be no higher than $89.9 million. On February 16, 2006, the Unsecured Claims were sold to a separate third party, resulting in a final net cash outlay which did not materially differ from the anticipated cash outlay.
NPC and SPPC filed applications with the PUCN in January 2007 and December 2006, respectively, to recover the amounts paid in connection with the Settlement Agreement, net of the proceeds from the sale of the Unsecured Claims. The Utilities cannot predict, whether, to what extent or upon what conditions the PUCN will approve recovery of these amounts. To the extent the Utilities are not permitted to recover these costs through rate filings, the amounts not permitted would be charged as a current operating expense. See Contract Termination Liabilities.
Enron Bankruptcy Court Judgment
On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy proceeding before Enron Bankruptcy Court seeking liquidated damages of approximately $216 million from NPC and $93 million from SPPC asserting the Utilities had not provided adequate assurance of performance upon Enron’s demand, which triggered Enron to terminate all power contracts with the Utilities under a Western Systems Power Pool Agreement (WSPPA). The Utilities denied liability on numerous grounds, including wrongful termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.
On September 26, 2003, the Bankruptcy Court entered summary judgment in favor of Enron (the “Judgment”) for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment required NPC and SPPC to pay approximately $235 million and $103 million, respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by Enron under the power supply contracts terminated by Enron and approximately $17.7 million and $6.7 million, respectively, for power previously delivered to the Utilities. Based on the pre-judgment rate of 12%, NPC and SPPC recognized
167
additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination liabilities in the third quarter 2003. Also, NPC and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6 million and $2.1 million, respectively, in the third quarter of 2003. The Bankruptcy Court’s order provided that until paid, the amounts owed by the Utilities would accrue interest post-Judgment at a rate of 1.21% per annum.
On November 6, 2003, the Enron Bankruptcy Court ruled to stay execution of the Judgment conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus approximately $282 thousand by NPC for pre-judgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing NPC’s $235 million General and Refunding Mortgage Bond, Series H and SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which would lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. On April 16, 2004, NPC agreed to post an additional cash sum of $25 million in escrow, which lowered the principal amount of NPC’s General and Refunding Mortgage Bond, Series H, by a like amount, as part of an agreement with Enron in which Enron agreed not to request any additional collateral from NPC or SPPC during the pendency of the Utilities’ appeal of the Judgment to the District Court.
On October 10, 2004, in response to our appeal of the Bankruptcy Court Judgment, the U.S. District Court for the Southern District of New York held that the pre-judgment interest should have been calculated at the present value rate, rather than at the rate of 1% per month used by the Bankruptcy Court. Based on this decision, the Utilities reversed the accrued interest included in contract termination liabilities by approximately $40 million for the year ended 2004.
Nevada Power Company
Morgan Stanley Proceedings
On November 29, 2005, SPR and NPC entered into a settlement agreement with Morgan Stanley Capital Group, Inc. (MSCG) resolving the litigation in the United States District Court, District of Nevada concerning various power supply contracts between NPC and MSCG that had been terminated by MSCG in April 2002 and the FERC 206 Complaint against MSCG and the related appeal described above. Under the terms of the settlement agreement, NPC paid $17.5 million to MSCG and the parties dismissed the litigation concerning terminated power contracts between them, and the FERC 206 proceedings as they relate to MSCG.
El Paso Merchant Energy
On January 19, 2006, NPC and EPME entered into a Settlement Agreement in resolution of their termination claims and counterclaims under the WSPPA in the Federal District Court, District of Nevada. Parties further agreed to withdraw, as to EPME, the appeal currently pending in the Ninth Circuit (FERC 206 Appeal) and to dismiss, as to EPME, any complaints made at FERC related to such appeal. NPC agreed to pay EPME $19 million. NPC and EPME executed a final written settlement agreement implementing the terms of this settlement on February 13, 2006.
Nevada Power Company 2001 Deferred Energy Case
On November 30, 2001, NPC made a deferred energy filing with the PUCN seeking repayment 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 rate to repay 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 Order on the 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. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.
On July 20, 2006, the Nevada Supreme Court ruled that NPC is allowed to recover approximately $180 million of deferred energy and directed the District Court to remand the issue back to the PUCN to determine the rate schedule that will be used to recover this amount. In all other respects, the Nevada Supreme Court affirmed the District Court’s decision on the PUCN disallowance. In the third quarter of 2006, as a result of the Nevada Supreme Court decision, NPC recorded approximately $180 million,before tax,of the previously disallowed deferred energy costs in its Consolidated Income Statements as “Reinstatement of Deferred Energy.”
168
In November 2006, the PUCN established a new docket (PUCN Docket No. 06-11029) for the purpose of determining the appropriate rate schedule for recovering approximately $180 million of deferred energy.
In February 2007, NPC entered into a stipulation where NPC shall be authorized to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to the Western Energy Crisis, discussed in Note 3, Regulatory Actions. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
Peabody Western Coal Company
NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) which includes three coal-fired electrical generating units and is located in Northern Arizona. Other participants in Navajo, are the Salt River Project (Salt River), Arizona Public Service Company, Los Angeles Department of Water and Power, and Tucson Electric Power Company (together, the Joint Owners).
On October 15, 2004, coal supplier Peabody Western Coal Co. (Peabody) filed a complaint against the Joint Owners in Missouri State Court in St. Louis, seeking reimbursement of royalties and other costs and damages for alleged breach of the coal supply agreement for the Navajo plant. In January 2005, the Joint Owners were served and operating agent, Salt River, has engaged counsel and is defending the suit on behalf of the Joint Owners. NPC believes Peabody’s claims are without merit and intends to contest these.
On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to remand the case back to state court in St. Louis, Missouri. Joint Owners have filed a motion to dismiss the complaint for lack of jurisdiction. On May 30, 2006, the Federal District Court granted Peabody’s motion and remanded the case back to state court. On June 29, 2006, Joint Owners filed a new motion to dismiss with the Missouri state court and requested a stay of the discovery proceedings pending the ruling on the new motion. On September 21, 2006, the Missouri state court heard oral arguments on the motion to dismiss. Parties are in the process of completing briefing on the motions. A decision is not expected until early 2007. Several discovery motions remain pending. NPC is unable to predict the outcome of the decisions.
Sierra Pacific Power Company
Farad Dam
SPPC owns 4 hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million.
SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (Insurers) for the flume and dam. In December, 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, Insurers filed another (partial) summary judgment motion with respect to coverage, which the court also denied. On June 16, 2006, Insurers filed new summary judgment motions, which SPPC opposed. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts or from other sources.
Management has not recorded a loss contingency for this matter, as the loss, if any, can not be estimated at this time.
Piñon Pine
In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC’s participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable. In its order in May 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s
169
2003 General Rate Case and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). On March 27, 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. On June 12, 2006, the District Court granted PUCN’s motion to stay the Order. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the District Court, which, consistent with its January 25, 2006 order, will remand the matter back to the PUCN for further review. A procedural schedule for this review has not yet been established.
Other Legal Matters
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, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations, or cash flows.
Contract Termination Liabilities
At December 31, 2006 pursuant to the deferred energy accounting provisions of AB 369, included in NPC and SPPC deferred energy balances were approximately $80.1 million and $16.3 million of charges, respectively, for recovery in rates in future periods associated with the terminated power supply contracts. In January 2007, NPC filed an application to recover $83.6 million in deferred legal and settlement costs incurred to resolve claims arising for the western energy crisis. In February 2007, NPC entered into a stipulation, with the parties to the case, to recover the $83.6 million plus carrying charges over a 3-year period beginning June 1, 2007. This stipulation is expressly conditioned upon the PUCN’s acceptance of the concurrently filed stipulation related to NPC’s 2001 Deferred Energy Case, discussed in Note 3, Regulatory Actions. If the PUCN does not accept both stipulations, this stipulation shall be deemed withdrawn, and all parties will retain all rights to litigate. The PUCN has yet to issue an order on the stipulation.
In December 2006, SPPC filed an application to recover $22.6 million in deferred legal and settlement costs incurred to resolve claims arising for the western energy crisis. To the extent that the Utilities are not permitted to recover any portion of these costs, the disallowed amounts would be charged to current operating expense. In February 2007, SPPC entered into a stipulation where SPPC replaces its request to implement rates on July 1, 2007 with a request to establish a regulatory asset to recover the costs. SPPC further requests authority to recover carrying charges on the regulatory asset. SPPC may request authority to begin recovering the regulatory asset established by the PUCN in a future application to change rates. The parties to the stipulation have requested that the PUCN issue an order by September 30, 2007. A significant disallowance of these costs by the PUCN could have a material effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.
Regulatory Contingencies
Nevada Power Company
Mohave Generation Station (Mohave)
In 2005, NPC’s ownership interest in Mohave comprised approximately 10% of NPC’s peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave and NPC owns approximately 14% of the facility.
When operating, Mohave obtained 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 was 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.
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. In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999. The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the decree, Mohave Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met. Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the Consent Decree.
In December 2005, the Owners of the Mohave plant suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder SCE announced it would no longer participate in the efforts to return the plant to service. As a result, NPC decided it is not economically feasible to continue its participation in the project. In September 2006, Salt River’s co-tenancy agreement and the operating agreement between the Owners expired in July 2006. The Owners are negotiating an extension of both agreements including a process that addresses how Owners may sell or assign their right, title, interest and obligations in Mohave.
170
In NPC’s 2003 General Rate Case, the PUCN ordered the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in rates, as such, associated savings are currently recorded as a reduction in electric operating revenues-other. NPC continues to accumulate all costs and savings associated with the shut down of Mohave, including unrecovered plant costs, in Other Regulatory Assets which has a balance of $17.8 million as of December 31, 2006. In its general rate case, NPC requested further clarification on the regulatory treatment of Mohave. In the event any portion of Mohave is disallowed, NPC will have to evaluate the asset for impairment.
NOTE 14. COMMON STOCK AND OTHER PAID-IN CAPITAL
Rights Agreement
In December 2005, the Board of Directors of SPR (the Board) voted to amend the Rights Agreement, dated as of February 2001 (as amended and restated, the “Rights Agreement”), between the SPR and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights (“Rights”) issued there under to December 2005, and to terminate the Rights Agreement upon the expiration of the Rights. The Board also adopted a policy governing future entry into a shareholder rights agreement or similar agreement (a “shareholder rights plan”). SPR’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the board, in the exercise of its fiduciary duties and with the concurrence of a majority of its independent members, determines that, under the circumstances existing at the time, it is in the best interest of SPR’s shareholders to adopt a shareholder rights plan without first obtaining shareholder approval. If a shareholder rights plan is adopted without prior shareholder approval, the plan must provide that is shall expire, unless ratified by shareholders, within one year of adoption.
Employee Stock Ownership Plans
As of December 31, 2006, 8,279,478 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 (LTIP).
The 2005 LTIP for officers and key employees allows for the issuance of SPR’s common shares through December 2013, which can be earned and issued prior to December 2013. 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, bonus stock and cash.
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 No. 25. In addition, in 1996 SPR 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.
Non-Employee Director Stock
The annual retainer for non-employee directors is $57,000, and the minimum amount to be paid in SPR stock is $35,000 per director. During 2006, 2005, and 2004, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 30,733, 31,631, and 18,740 shares, and $154,000, $176,000, and $140,000.
Convertible Notes Issuance
In February 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. In August 2003, SPR obtained shareholder approval to issue additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. In August 2005, SPR announced an offer to pay a cash premium to induce holders to convert their 7.25% Notes to shares of SPR common stock. The conversion offer was accepted by 100% of the holders. In September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued to the holders in exchange for the 7.25% Notes. For additional information regarding these Convertible Notes see Note 6, Long-Term Debt.
In September 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares and an aggregate of $54 million in cash consideration were paid to the holders in exchange for the Convertible Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005.
171
Stock Exchange Transactions
In November 2005 SPR issued 17,344,183 shares of common stock, along with cash in lieu of fractional shares in connection with its PIES. Each PIES consisted of a forward stock purchase contract and a senior unsecured note issued by SPR.
In February 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes that were a component of the PIES, in exchange for 13,662,393 shares of its common stock.
In May 2005, SPR exchanged approximately 41% of the PIES for newly issued PIES (“New PIES”) and issued, as a component of the New PIES $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the PIES. SPR successfully remarketed these notes in June 2005 at an interest rate of 7.803%.
In August 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior Notes associated with the PIES were remarketed. In August 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (see Note 6, Long-Term Debt) to purchase all of the 7.93% Senior Notes.
In November 2005, the purchase contract settlement date for the PIES and New PIES, 3.6101 shares per forward purchase contract were exchanged for a total of 17,344,183 shares of common stock issued to holder of the PIES and New PIES.
Increased Authorized Shares
In May 2006, SPR’s shareholders approved an amendment to SPR’s Restated Articles of Incorporation to increase the number of authorized shares of SPR common stock by 100,000,000 shares for a total amount of 350,000,000 authorized shares.
Common Stock Offering
In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC of approximately $200 million. NPC used the proceeds to repay indebtedness under its revolving credit facility.
In December 2006, SPR contributed capital to SPPC of approximately $75 million. SPPC used the proceeds to repay indebtedness under its revolving credit facility and general corporate purposes. SPR has invested the remaining proceeds in highly liquid short-term investments pending their use for general corporate purposes. As of December 31, 2006 SPR has 350 million shares of common stock authorized and 221.0 million shares of common stock issued and outstanding.
NOTE 15. PREFERRED STOCK
Sierra Pacific Power Company
Preferred Stock
In June 2006, SPPC redeemed $50 million of its Class A, Series 1 Preferred Stock. Two million shares of stock were redeemed at a redemption price per share of $25.683, plus accrued dividends at the redemption date of $0.4875 per share.
SPPC’s Restated Articles of Incorporation, as amended in August 1992, authorize an aggregate amount of 11,780,500 shares of preferred stock at any given time.
On November 1, 2006, Sierra Pacific Power Company filed its restated articles of incorporation with the Nevada Secretary of State. SPPC also filed a withdrawal of the certificate of designation for its’ previously issued but no longer outstanding series of preferred stock.
The restated articles authorize the issuance of (i) Twenty million (20,000,000) shares of common stock with a par value of $3.75 per share; and (ii) Ten million (10,000,000) shares of preferred stock with no par value per share. Currently, all of SPPC’s one thousand (1,000) shares of common stock outstanding are held by SPR.
Under the restated articles, preferred stock may be issued from time to time in one or more series in such amounts and with such terms and conditions as may be determined by the board of directors.
The restated articles limit the liability of directors and officers to the fullest extent permitted by applicable law. The restated articles may be amended or altered by a vote of the holders of a majority of SPPC’s common stock then issued, outstanding and entitled to vote. SPPC may sell its assets upon the affirmative vote of a majority of the board of directors.
172
The restated articles eliminate the restrictive covenants that were previously contained in SPPC’s articles of incorporation, including a limitation on the amount of dividends that may be paid on SPPC’s common stock and a limitation on the amount of secured debt that may be issued by SPPC.
The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year (dollars in thousands).
| | | | | | | | | | | | | | | | | |
| | | Amount | | | Shares Outstanding | |
| Preferred Stock | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| Not subject to mandatory redemption SPPC Class A Series 1 | | $ | — | | | $ | 50,000 | | | | — | | | | 2,000,000 | |
| | | | | | | | | | | | | |
| Total Preferred Stock | | $ | — | | | $ | 50,000 | | | | — | | | | 2,000,000 | |
| | | | | | | | | | | | | |
NOTE 16. EARNINGS PER SHARE (EPS) (SPR)
The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan.
For the year ended December 2004, SPR had outstanding $300 million in 7.25% convertible notes due 2010 that were entitled to receive (non-cumulative) dividend payments on a 1:1 basis for dividends paid to common shareholders without exercising the conversion option. These convertible notes met the criteria of a participating security in the calculation basic EPS, and were convertible at the option of the holders into 65,749,110 common shares.
Emerging Issues Task Force, Participating Securities and the Two-Class Method under FASB Statement No. 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive. In September 2005 SPR issued approximately 65.7 million shares of common stock in connection with the early conversion of the 7.25% Convertible Notes. The weighted average shares outstanding up to the date of conversion are shown separately for the year ending December 2005.
In November 2005 the conversion of SPR’s PIES resulted in the issuance of 17.3 million shares. For the year ended December 2005 these shares are included in the denominator on a weighted average basis.
173
The following table outlines the calculation for earnings per share (EPS):
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
Basic EPS | | | | | | | | | | | | |
Numerator ($000) | | | | | | | | | | | | |
| Income from continuing operations | | $ | 279,792 | | | $ | 86,137 | | | $ | 30,842 | |
| Gain on sale of discontinued operations | | $ | — | | | $ | — | | | $ | 1,629 | |
| |
| Net income applicable to common stock | | $ | 277,451 | | | $ | 62,198 | | | $ | 18,310 | |
| Net income applicable to convertible notes | | $ | — | | | $ | 20,039 | | | $ | 10,261 | |
| | | | | | | | | | |
| Net income used for basic calculation | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Denominator | | | | | | | | | | | | |
| |
| Weighted average number of common shares outstanding | | | 208,531,134 | | | | 140,334,552 | | | | 117,331,365 | |
| Shares from conversion of notes | | | — | | | | 45,213,762 | | | | 65,749,110 | |
| | | | | | | | | | |
| | | | 208,531,134 | | | | 185,548,314 | | | | 183,080,475 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Per Share Amounts | | | | | | | | | | | | |
| Income from continuing operations | | $ | 1.34 | | | $ | 0.46 | | | $ | 0.17 | |
| Gain on sale of discontinued operations | | $ | — | | | $ | — | | | $ | 0.01 | |
| | | | | | | | | | | | | |
| Net income applicable to common stock | | $ | 1.33 | | | $ | 0.44 | | | $ | 0.16 | |
| Net income applicable to convertible notes | | $ | — | | | $ | 0.44 | | | $ | 0.16 | |
Diluted EPS | | | | | | | | | | | | |
Numerator ($000) | | | | | | | | | | | | |
| Income from continuing operations | | $ | 279,792 | | | $ | 86,137 | | | $ | 30,842 | |
| Gain on sale of discontinued operations | | $ | — | | | $ | — | | | $ | 1,629 | |
| | | | | | | | | | | | | |
| Net income applicable to common stock | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| | | | | | | | | | | | | |
Denominator (1) | | | | | | | | | | | | |
| Weighted average number of shares outstanding before dilution | | | 208,531,134 | | | | 140,334,552 | | | | 117,331,365 | |
| Stock options | | | 91,119 | | | | 47,255 | | | | 24,949 | |
| Executive long term incentive plan – restricted | | | 113,456 | | | | 187,810 | | | | 242,679 | |
| Non-Employee Director stock plan | | | 30,754 | | | | 21,193 | | | | 15,028 | |
| Employee stock purchase plan | | | 3,345 | | | | 3,925 | | | | 15,028 | |
| Performance Shares | | | 251,088 | | | | 124,007 | | | | 22,144 | |
| Convertible Stock | | | — | | | | 45,213,762 | | | | 65,749,110 | |
| | | |
| | | | 209,020,896 | | | | 185,932,504 | | | | 183,400,303 | |
| | | |
| | | | | | | | | | | | | |
Per Share Amounts | | | | | | | | | | | | |
| Income from continuing operations | | $ | 1.34 | | | $ | 0.46 | | | $ | 0.17 | |
| Gain on sale of discontinued operations | | $ | — | | | $ | — | | | $ | 0.01 | |
| | | | | | | | | | | | | |
| Net income applicable to common stock | | $ | 1.33 | | | $ | 0.44 | | | $ | 0.16 | |
| | |
| (1) | | The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the years ended December 31, 2006, 2005, and 2004, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the years ended December 31, 2006, 2005, and 2004, 932,946, 917,623 and 1,146,728 shares, respectively, would be included. The denominator also does not include stock equivalents resulting from the conversion of the Corporate PIES, for the year ended December 31, 2004. The amounts that would be included in the calculation, if the conversion price were met would be 17.3 million shares. |
174
NOTE 17. DISCONTINUED OPERATIONS AND DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS
Effective January 2002, SPR, NPC and SPPC adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met. Further, SFAS No. 144 requires that assets to be held and used be tested for recoverability whenever events or circumstances indicate that its carrying amount may not be recoverable.
Sierra Pacific Communications
SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC’s business activities have included the development of a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (Long Haul Assets) and the development of Metro Area Networks (MAN) in Las Vegas and Reno, Nevada.
In 2004, SPC disposed of their MAN assets and recognized a gain on sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets. SPC retained possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. In 2004, in accordance with Statement of Financial Accounting Standards 144 (SFAS 144), Accounting for the Disposition or Impairment of Long-Lived Assets, SPR reported the remaining Long Haul System as discontinued operations. However, due to certain legal issues, SPR was delayed in consummating the sale of the Long Haul System to Qwest. In January 2007 SPC agreed to dismiss pending arbitration against Qwest. As part of the Settlement Agreement, Qwest agreed to execute a quit claim deed disclaiming any further interest in the Long Haul system. In accordance with SFAS 144 if at any time the criteria for classifying assets as held for sale are no longer met, a long-lived asset classified as held for sale shall be reclassified as held and used. As of December 31, 2006, SPC assets associated with the Long-Haul were reclassified for all periods presented from assets held for sale in Discontinued Operations to assets held and used.
NOTE 18. GOODWILL AND OTHER MERGER COSTS
In March 2004, the PUCN issued a decision on NPC’s general rate case that included the recovery of goodwill and other merger costs allocated to NPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that NPC demonstrated merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger costs through rates charged to NPC customers. The PUCN decision permits NPC to recover approximately $4 million per year for two years beginning April 2004, based on a forty-year amortization of NPC’s total goodwill. The amount recovered over those two years reflected a reduction of 20% from the amounts sought by NPC, or approximately $1 million per year, due to customer satisfaction survey results that the PUCN determined required improvement. As a result of the PUCN decision, goodwill of approximately $198 million was reclassified as a regulatory asset and then transferred from the financial statements of SPR to the financial statements of NPC as of March 31, 2004.
Furthermore, the PUCN decision requires NPC to again demonstrate in its next general rate application that merger savings continue during the test period in that case. The PUCN’s order in that case will determine if any further documentation of merger savings is required in the future. In November 2006 NPC filed its GRC, requesting 100% recovery of the amortization amount. Management expects that it will be able to demonstrate continued savings as a result of the merger as well as satisfactory customer survey results.
In May 2004, the PUCN approved a settlement agreement entered into by SPPC, the Staff of the PUCN and other interveners in connection with SPPC’s 2003 general rate case that permits SPPC recovery of goodwill and other merger costs assigned to SPPC’s electric business. SPPC is permitted to recover approximately $2.4 million per year for two years beginning June 2004, based on a forty-year amortization of goodwill costs. As a result of the PUCN decision, goodwill of approximately $96 million was reclassified to a regulatory asset and transferred from the financial statements of SPR to the financial statements of SPPC as of June 30, 2004.
Similar to the decision reached in NPC’s rate case described above, in order to continue to recover goodwill costs SPPC was required to again demonstrate in its next general rate application filed October 2005, that merger savings continued during the test period in that case. In April 2006, the PUCN concluded that SPPC shall be allowed full recovery of its unamortized merger costs thereby ending the merger-related regulatory filings. See Note 3, Regulatory Actions for more information regarding the NPC and SPPC general rate decisions.
SFAS No. 142 provides that an impairment loss is to 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 developed for NPC’s and SPPC’s electric business and for SPR’s unregulated businesses to determine the fair value of each reporting unit as of March 31, 2004. As part of the impairment testing analysis, management revised certain underlying assumptions utilized in previously performed preliminary analyses, that included, revised cash flow forecasts, an increase in the discount rate applied to future cash flows and other
175
assumptions related to the outcomes of NPC’s and SPPC’s general rate cases. As a result of this impairment testing, SPR recorded a goodwill impairment charge related to NPC’s and SPPC’s electric reporting units of approximately $2 million and $10 million as a charge to other operating expenses in SPR’s, NPC’s and SPPC’s Consolidated Statements of Income for the quarter ended March 31, 2004. Goodwill assigned to SPR’s unregulated businesses was determined not to be impaired.
In April 2006, the PUCN issued a decision on SPPC’s general rate case for the gas distribution business that included the recovery of goodwill and other merger costs allocated to SPPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that SPPC demonstrated merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger costs. As a result of the PUCN decision, goodwill of approximately $18.9 million was reclassified as a regulatory asset and transferred from the financial statements of SPR to the financial statements of SPPC as of June 30, 2006. See Note 3 of the Notes to Consolidated Financial Statements, Regulatory Actions for more information regarding the SPPC general rate decision.
Approximately $4 million of goodwill was assigned to SPR’s unregulated operations, (TGPC and LOS) as of March 2006. In December 2006, TGPC sold its investment in TGTC. As a result of the sale, the $3.5 million of goodwill assigned to TGPC goodwill was allocated against the gain on the sale of the investment. Reference Note 4, Investments in Subsidiaries and Other Property for further discussion regarding the sale of TGTC. As of December 31, 2006, goodwill of approximately $500 thousand is allocated to SPR’s unregulated operation of LOS.
NOTE 19. 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.
| | | | | | | | | | | | | | | | | |
| | | SIERRA PACIFIC RESOURCES | |
| | | 2006 Quarter Ended | |
| | | Revised | | | Revised | | | Revised | | | | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 707,056 | | | $ | 821,919 | | | $ | 1,081,967 | | | $ | 745,008 | |
| | | | | | | | | | | | | |
Operating Income(5) | | $ | 59,577 | | | $ | 90,683 | | | $ | 283,793 | (1) | | $ | 54,744 | |
| | | | | | | | | | | | | |
Income from continuing operation(5) | | $ | 2,217 | | | $ | 29,202 | | | $ | 222,246 | | | $ | 26,127 | |
| | | | | | | | | | | | | |
| Net income applicable to common stock | | $ | 1,242 | | | $ | 27,836 | | | $ | 222,246 | | | $ | 26,127 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Income per share-Basic and diluted: | | | | | | | | | | | | | | | | |
| From continuing operations | | $ | 0.01 | | | $ | 0.15 | | | $ | 1.05 | | | $ | 0.12 | |
| Net income applicable to common stock | | $ | 0.01 | | | $ | 0.14 | | | $ | 1.05 | | | $ | 0.12 | |
| | | | | | | | | | | | | | | | | |
| | | 2005 Quarter Ended | |
| | | Revised | | | Revised | | | Revised | | | | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 648,996 | | | $ | 701,038 | | | $ | 959,126 | | | $ | 721,082 | |
| | | | | | | | | | | | | |
| Operating Income | | $ | 58,953 | | | $ | 80,894 | | | $ | 162,750 | | | $ | 56,081 | |
| | | | | | | | | | | | | |
Income from continuing operations (6) | | $ | (8,511 | ) | | $ | 10,026 | | | $ | 61,993 | (3) | | $ | 22,629 | |
| | | | | | | | | | | | | |
| Net Income (loss) applicable to common stock | | $ | (9,486 | ) | | $ | 9,051 | | | $ | 61,018 | | | $ | 21,654 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Income (loss) per share-Basic and diluted: | | | | | | | | | | | | | | | | |
| From continuing operations | | $ | (0.07 | ) | | $ | 0.05 | | | $ | 0.34 | | | $ | 0.12 | |
| Net Income (loss) applicable to common stock | | $ | (0.08 | ) | | $ | 0.05 | | | $ | 0.33 | | | $ | 0.11 | |
| | |
| (1) | | In the third quarter of 2006, operating income includes the reinstatement of deferred energy of approximately $180 million. |
| |
| (2) | | In the fourth quarter of 2006, income from continuing operations includes a gain of $62.9 million due to the sale of TGPC’s partnership interest in TGTC. |
| |
| (3) | | In the third quarter of 2005, income from continuing operations includes a charge of $54 million for the inducement for debt conversion. |
| |
| (4) | | In the fourth quarter of 2005, income from continuing operations includes the reversal of $20.9 million in interest charges as a result of settlements with terminated suppliers. |
| |
| (5) | | Operating Income and Income from Continuing Operations differs from amounts previously reported in the March 31, June 30, and September 30, 2006 10Q’s by a reduction of ($9), ($48), and ($15), respectively, due to SPCOM being classified as assets held for use rather than as discontinued operation. See Note 18 Discontinued Operations and Disposal and Impairment of Long-Lived Assets. |
176
| | |
| (6) | | Operating Income and Income from Continuing Operations differs from amounts previously reported in the March 31, June 30 and September 2005 10Q’s by $5, $1 and ($134), respectively, due to SPCOM being classified as assets held for use rather than as discontinued operations. See Note 18 Discontinued Operations and Disposal and Impairment of Long-lived Assets. |
| | | | | | | | | | | | | | | | | |
| | | NEVADA POWER | |
| | | 2006 Quarter Ended | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 381,275 | | | $ | 543,869 | | | $ | 776,235 | | | $ | 422,702 | |
| | | | | | | | | | | | | |
| Operating Income | | $ | 25,663 | | | $ | 62,019 | | | $ | 244,920 | (1) | | $ | 18,670 | |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (3,296 | ) | | $ | 28,456 | | | $ | 211,113 | | | $ | (11,733 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 2005 Quarter Ended | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 354,134 | | | $ | 451,384 | | | $ | 675,181 | | | $ | 402,568 | |
| | | | | | | | | | | | | |
| Operating Income | | $ | 23,265 | | | $ | 54,031 | | | $ | 126,173 | | | $ | 25,358 | |
| | | | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (8,033 | ) | | $ | 20,969 | | | $ | 99,472 | | | $ | 20,326 | (2) |
| | | | | | | | | | | | | |
| | |
| (1) | | In the third quarter of 2006, operating income includes the reinstatement of deferred energy costs of approximately $180 million. |
| |
| (2) | | In the fourth quarter of 2005, income from continuing operations includes the reversal of $17.7 million in interest charges as a result of settlements with terminated suppliers. |
| | | | | | | | | | | | | | | | | |
| | | SIERRA PACIFIC POWER | |
| | | 2006 Quarter Ended | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 325,497 | | | $ | 277,319 | | | $ | 305,445 | | | $ | 321,969 | |
| | | | | | | | | | | | | |
| Operating Income | | $ | 29,991 | | | $ | 24,803 | | | $ | 36,543 | | | $ | 28,680 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 13,272 | | | $ | 8,999 | | | $ | 20,028 | | | $ | 15,410 | |
| | | | | | | | | | | | | |
| Earnings (deficit) applicable to common stock | | $ | 12,297 | | | $ | 7,633 | | | $ | 20,028 | | | $ | 15,410 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 2005 Quarter Ended | |
| | | March | | | June | | | September | | | December | |
| Operating Revenues | | $ | 294,548 | | | $ | 249,335 | | | $ | 283,683 | | | $ | 318,131 | |
| | | | | | | | | | | | | |
| Operating Income (loss) | | $ | 29,519 | | | $ | 21,710 | | | $ | 38,139 | | | $ | 26,936 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 12,137 | | | $ | 4,899 | | | $ | 21,858 | | | $ | 13,180 | (1) |
| | | | | | | | | | | | | |
| Earnings (deficit) applicable to common stock | | $ | 11,162 | | | $ | 3,924 | | | $ | 20,883 | | | $ | 12,205 | |
| | | | | | | | | | | | | |
| | |
| (1) | | In the fourth quarter of 2005, income includes the reversal of $3.2 million in interest expense due to the settlement with Enron. |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures– Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of December 31, 2006, the registrants’ disclosure controls and procedures are adequate and effective to ensure that material information relating to the
177
registrants’ and their consolidated subsidiaries is recorded, processed, summarized and reported within the time period specified by the SEC’s rules and forms, particularly during the period for which this annual report has been prepared.
(b) Reports on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting
The management of Sierra Pacific Resources is responsible for establishing and maintaining adequate internal control over financial reporting. Sierra Pacific Resources’ internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.
Although Sierra Pacific Resources is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Sierra Pacific Resources’ management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, Sierra Pacific Resources used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2006, the Company’s internal control over financial reporting is effective based on those criteria.
Sierra Pacific Resources’ independent registered public accountants have issued an audit report on our assessment of the Company’s internal control over financial reporting.
March 1, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Sierra Pacific Resources
Reno, Nevada
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Sierra Pacific Resources and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2006 of the Company and our report dated March 1, 2007 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of Statement of Financial Accounting Standards No. 123(R) and Statement of Financial Accounting Standards No. 158.
DELOITTE & TOUCHE, LLP
Reno, Nevada
March 1, 2007
(c) Changes in Internal Controls
None.
ITEM 9B. OTHER INFORMATION
None.
178
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
(a) Directors
The following is a listing of all the current directors of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), and their ages. There are no family relationships among them. Directors serve staggered 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 2007:
James R. Donnelley, 71
Partner, Stet and Query, Ltd., a family-owned investment company, since June 2000. He retired from R.R. Donnelley & Sons Company in June 2000, where he served as Vice Chairman of the Board from July 1990 to June 2000 and as a Director from 1976 to May 2005. He is also a Director of PMP Limited. 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, 62
Chairman 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 is also a director of AEGIS Insurance Services, Inc., Edison Electric Institute, American Gas Institute, Desert Research Institute Foundation Board, and several not-for-profit organizations. He is a trustee of Sierra Nevada College.
Brian J. Kennedy, 63
Mr. Kennedy is President and Chief Executive Officer of Argonaut, LLC. He is also Chairman of Meridian Gold, Inc., having retired as President and CEO in 2006. Prior to that, he served approximately nine years as President and Chief Operating Officer of FMC Gold Company. He is also a Director of two non-profit corporations: the Nevada Museum of Art and the Community Foundation of Western Nevada. Mr. Kennedy was elected as a Director of SPR, SPPC and NPC in February 2007.
John F. O’Reilly, 61
Chairman and Chief Executive Officer of the law firm of O’Reilly Law Group LLC and John F. O’Reilly, APC., Chairman and an Officer and/or a Board member of various family-owned business entities and related investments and businesses. He serves as a Director of the Community Board of Wells Fargo Bank Nevada, N.A., Director of Herbst Gaming, Inc., UNLV Foundation, Nevada Development Authority, Advisory Board of Boys and Girls Clubs of Las Vegas, a member of the Las Vegas Chamber of Commerce Government Affairs Committee, and is involved in various other capacities in other not-for-profit organizations, including Vision 2020, on which he serves as Chairman/CEO and Board member. Mr. O’Reilly has been a Director of NPC since 1995, and was elected a Director of SPR and SPPC in July 1999.
Michael W. Yackira, 55
President and Chief Operating Officer of SPR, and Director of SPR since February 2007. Mr. Yackira was previously Corporate Executive Vice President and Chief Financial Officer from October 2004 to February 15, 2007. From December 2003 to October 2004 he held the position of Executive Vice President and CFO, at both NPC and SPPC. Mr. Yackira was previously Executive Vice President, Strategy and Policy, from January to December 2003. Previously he was the Vice President and CFO of Mars, Inc. from 2001 to 2002. Prior to that, Mr. Yackira was with Florida based FPL Group, Inc., from 1989 to 2000. Mr. Yackira is a board member of the United Way of Southern Nevada, the American Heart Association of Las Vegas, and several not-for-profit organizations.
Directors whose terms expire in 2008:
Joseph B. Anderson, Jr., 64
Chairman and CEO of TAG Holdings, LLC. Mr. Anderson is on the Board of Rite Aid Corporation, Quaker Chemical Corporation, ArvinMeritor, Inc., MDL Capital Management and Valassis Communications, Inc. He is Director of the Original Equipment Suppliers Association, a member of the Michigan Automotive Partnership, Director of the Society of Automotive Engineers Foundation and Director, Society of Automotive Engineers International, Executive of the Committee of the National Association of Black Automotive Suppliers, and Board of Governors of the Center for Creative Leadership. Mr. Anderson was elected as a Director of SPR, SPPC and NPC in February 2005.
179
Krestine M. Corbin, 69
President and Chief Executive Officer of Sierra Machinery, Incorporated, a machine tool manufacturing company, 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.
Philip G. Satre, 57
Mr. Satre retired January 1, 2005, as Chairman of the Board, Harrah’s Entertainment, Inc., a gaming entertainment company. Previously he was CEO of Harrah’s Entertainment from 1993 to 2003. He is a Director of TABCORP Holdings Limited (Australia), Nordstrom Inc., and Rite Aid Corporation, as well as the National Center for Responsible Gaming and the Nevada Cancer Institute. He is a Trustee of Stanford University, the World War II Museum, Inc. and the UC Davis School of Law Alumni Association Board. Mr. Satre was elected as a Director of SPR, SPPC, and NPC in January 2005.
Clyde T. Turner, 69
Owner and Manager of Turner Investments Ltd., a general-purpose investment company, co-owner of Global Trust Ventures, LLC, a private equity fund and co-owner of Global Trust Ventures Management, LLC. He was elected a Director of SPR, NPC, and SPPC in November 2001.
Directors whose terms expire in 2009:
Mary Lee Coleman, 70
President of Coleman Enterprises, a developer of shopping centers and industrial parks. She is also a director of First Dental Health, Inc. 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, 57
Chairman of Dacole Company, an investment firm. Formerly Senior Partner of Hale, Day, Gallagher Company, a real estate brokerage and investment firm. He is also a Director of the W.M. Keck Foundation, the Boy Scouts of America, Nevada Area Council, the Reno Air Race Association, Linfield College, Western Exploration and Development, Ltd., and the National Cowboy and Western Heritage Museum. 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.
Jerry E. Herbst, 69
Chief Executive Officer of Terrible Herbst, Inc., a gaming, resort and gasoline retail company, since 1968. Mr. Herbst has served as a Director of NPC since 1990, and was elected a Director of SPR and SPPC in July 1999.
Donald D. Snyder, 59
Mr. Snyder retired in March 2005 as President and Board Member of Boyd Gaming Corporation, a gaming entertainment company. He is Director of Western Alliance Bancorporation and Cash Systems, Inc. He is Chairman of the Las Vegas Performing Arts Center Foundation. He is also Director of two non-public companies, Bank of Nevada and Switch Communications Group, LLC. He serves on numerous not-for-profit organizations, including Nathan Adelson Hospice, Nevada Development Authority, University of Nevada-Las Vegas Foundation and Council for a Better Nevada. Mr. Snyder was elected a Director of SPR, NPC and SPPC in November 2005.
Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a Director of Lands of Sierra, Inc., Great Basin Energy Company, Sierra Pacific Energy Company, Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Piñon Pine Co. LLC, SPPC Funding LLC, and Nevada Electric Investment Co. All of the above-listed companies are subsidiaries of Sierra Pacific Resources, with the exception of Piñon Pine Co. LLC, and SPPC Funding LLC which are subsidiaries of Sierra Pacific Power Company and Nevada Electric Investment Co. which is a subsidiary of Nevada Power Company.
(b) Executive Officers
See Executive Officers of the Registrant immediately following Item 4
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, or the Exchange Act, requires that Directors, officers, and any holders of more than 10% of SPR’s common stock file reports with the SEC disclosing ownership of the SPR’s stock and changes in beneficial
180
ownership. Officers, Directors and 10% stockholders are required by SEC regulations to furnish SPR with copies of all Section 16(a) forms they file.
To SPR’s knowledge, based solely on review of its records and written representations by persons required to file these reports, during 2006, all filing requirements under Section 16(a) were complied with in a timely fashion.
Audit Committee
The Audit Committee consists of the following individuals: Philip Satre, Krestine M. Corbin, Donald Snyder and Clyde T. Turner, who are all independent as defined in the listing standards under the New York Stock Exchange (NYSE) rules. The Board of Directors of SPR, NPC and SPPC have determined that Audit Committee member Clyde T. Turner is an “audit committee financial expert” as defined by the SEC.
Code of Ethics
SPR, NPC and SPPC have adopted a code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and to the Controller. The code of ethics is set forth on our website at sierrapacificresources.com.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
Compensation Overview
The Compensation Committee, or the Committee, of SPR, is composed entirely of directors who are independent in accordance with NYSE rules. The purpose of the Committee is to evaluate the compensation of the officers of SPR (and their performance relative to their compensation) and assure that they are compensated effectively in a manner consistent with the stated compensation strategy of SPR, internal fairness considerations, competitive practice and the requirements of the appropriate regulatory bodies. In addition, the Committee is responsible for reviewing and assessing SPR’s policies, plans and levels of health, welfare and benefit plans, together with the administration of such plans.
As the holding company of two growing utilities, SPR faces many business issues. During 2006, these issues included: improving its debt profile, increasing its credit ratings, settling of contractual and regulatory disputes, increasing internal generation capability, managing energy portfolio risk, and maintaining regulatory relationships. The Committee has determined that it is in the best interest of SPR’s shareholders and customers to attract and retain those individuals with the appropriate ability, knowledge and experience to help SPR deal effectively with these issues. Accordingly, the Committee has established a compensation program, which it reviews at least annually, for the principal executive officer, Walter M. Higgins, who served during 2006 as Chairman of the Board, President and Chief Executive Officer (the “CEO”); the principal financial officer during 2006, Michael W. Yackira, who served as Corporate Executive Vice President and Chief Financial Officer; and the other named executive officers, Paul J. Kaleta, Roberto R. Denis, and Jeffrey Ceccarelli (collectively with Messrs. Higgins and Yackira, the NEOs). On February 15, 2007, the Board of Directors elected Mr. Higgins Chairman of the Board and Chief Executive Officer, and elected Mr. Yackira President and Chief Operating Officer. The primary objectives of SPR’s compensations program are to:
| | • | | Assess the performance of individuals against key organizational objectives and reward performance that either meets or exceeds those objectives. |
| |
| | • | | Ensure continuity of superior performance and retention of key executives. |
| |
| | • | | Attract qualified candidates. |
To that end, the Committee has developed a mix of compensation, primarily consisting of cash, equity, retirement plans, other benefits and perquisites, all of which are discussed in more detail below under “Components of the Executive Compensation Program.” For 2006, the components of cash compensation, equity compensation and retirement plans are as follows:
| | o | | Salary |
| |
| | o | | Short Term Incentive Plan (STIP) |
| |
| | o | | Cash allowance |
| | • | | Equity Compensation—Long Term Incentive Plan (LTIP) |
| | o | | Non-Qualified Stock Options |
| |
| | o | | Performance Shares |
| | o | | Pension Plan (Qualified Plan) |
| |
| | o | | Non-Qualified Restoration Plan |
| |
| | o | | Non-Qualified Supplemental Executive Retirement Plan (SERP) |
| |
| | o | | Non Qualified Deferred Compensation Program |
181
The Committee has authority under its charter to retain the services of independent counsel, accountants or other consultants it deems necessary or appropriate to assist it. In accordance with this authority, the Committee engages Towers Perrin, as independent, external compensation consultants. In addition, Towers Perrin provides actuarial services and benefit consulting services to SPR. As requested, representatives of Towers Perrin attended Committee meetings in 2006. Towers Perrin apprises the Committee annually on current compensation practices, including how much compensation other companies deliver in cash versus equity, weighting of short term versus long term awards, market evaluations of base salary, short and long term incentive plans, perquisites and post retirement benefits, legal and disclosure issues related to compensation, valuation models for equity grants and other compensation matters.
The peer group that SPR is compared to consists of other utility and energy services companies that are similar to SPR in terms of the number of full time employees and revenues. SPR considers other energy and utility firms with revenues between $3 billion and three thousand employees as similar for comparison purposes.
Compensation Philosophy
General
The Committee believes that compensation should seek to encourage performance by the NEOs that is aligned with the key objectives of SPR on both a short-term and long-term basis and should help SPR in attracting and retaining qualified executives. The Committee does not have prescriptive policies for how NEOs are to be compensated beyond the minimum guidelines that are spelled out in the CEO’s employment contract and in the employment offer letters for the remaining NEOs. The Committee believes its compensation programs for NEOs are realistic, contemporary and in keeping with best practices within the industry.
The Committee makes compensation decisions for NEOs based upon business conditions, corporate goals and conditions that exist in the unique regulatory climate of an investor-owned utility. The mix and type of short-term and long-term awards for any given year are reviewed annually with the CEO, the Chief Administrative Officer, Stephen R. Wood, and Towers Perrin prior to the February Board meeting. Recommendations to the Committee for the total compensation for the NEOs, other than the CEO, are made by the CEO, with advice from the external consultants. None of the NEOs participates in the determination of their own compensation plans. The CEO is not present and is not involved in the discussions of total compensation recommendations for himself.
The Committee believes that the interests of SPR’s shareholders and customers are best served when SPR can attract and retain executives with compensation packages that are market competitive and yet fair and prudent within the environment of an investor-owned regulated utility. The Committee seeks to pay total direct compensation around the 50th percentile of other companies in its peer group, as discussed above. Total direct compensation is equal to the sum of cash compensation and the expected value of long-term incentives.
Incentive Compensation
The Committee annually provides short-term and long-term incentive compensation under two plans, the STIP and the LTIP, which provide for cash and stock compensation based on conditions set by the Committee. The STIP portion of compensation forms the variable cash component of annual compensation and is based on some combination of company-wide financial performance goals, customer satisfaction and operational performance and individual performance. The LTIP portion of compensation provides for equity grants and is typically tied to more long range goals. LTIP grants can be made in the form of performance shares or units, SAR’s, restricted shares, bonus stock, non-qualified or incentive stock options and/or cash.
The primary purpose of grants under the STIP and the LTIP is to achieve a focused, concerted effort on specific aspects of both company and individual performance. In addition, the Committee believes that grants under the STIP and the LTIP are useful in helping to retain key executives who are achieving superior performance against SPR goals by motivating them to remain in their positions and in encouraging continued performance excellence. The Committee attempts to provide substantially more potential value to the NEOs through the LTIP rather than the STIP. This greater potential value is intended to increase the retention element of the executive compensation program.
In determining the grants to be made under these plans, the Committee considers the following factors:
| | o | | the incentive compensation set and paid in recent years; |
| |
| | o | | the desire to ensure that a substantial portion of total compensation is based upon performance; |
| |
| | o | | the relative importance of the corporate, business unit and individual goals in any given year; and |
| |
| | o | | competitive information, analyses and recommendations provided by Towers Perrin. |
182
To the extent that performance goals are attached to grants under the STIP and LTIP, full achievement of those goals is often difficult. The Committee does not believe, however, that it is prudent to establish reward thresholds that are highly unlikely to be attained under any scenario.
The size and content of awards under the STIP and the LTIP vary from year to year. In the recent past, when SPR was facing challenges as a result of the western energy crisis and legal disputes with Enron, the Committee’s compensation decisions were focused more on the challenges of retaining NEOs. Time-vested restricted stock for the CEO and NEOs, and in the case of the CEO, a retention bonus were used at that time to reflect this goal. As SPR has rebounded from those difficulties and its stock price has improved, the Committee has chosen to put more emphasis on stock performance and the attainment of specific corporate goals in the LTIP award program.
Accordingly, two-thirds of the LTIP awards for each NEO, other than the CEO, in 2006 was based on SPR’s total shareholder return against the performance of other utilities, as described in more detail below. The remaining one-third of the 2006 LTIP grant to each of the NEO’s was in the form of non-qualified stock options. These grants reflect the Committee’s desire to continue to focus on share price growth and the related increase in shareholder value. In the case of the CEO, all of his LTIP grants were in the form of performance shares linked to specific performance milestones.
The Committee has followed a practice of making all STIP and LTIP grants to its executive officers on a single date each year, normally at its regularly scheduled Committee meeting in February. All option awards made to NEOs or any of the other employees are made pursuant to SPR’s LTIP plan. All options under the LTIP are granted with an exercise price equal to the fair market value of SPR’s common stock on the date of the grant. Fair market value is defined under the LTIP to be the closing market price of a share of common stock on the date of the grant. All equity grants to NEOs are made by the Committee. While SPR does not have any program or practice to time option grants to executive officers in coordination with the release of material non-public information, it does not time the release of such information for the purpose of affecting the value of executive compensation. The Committee does not have any program, plan or practice of awarding options and setting the exercise price of option grants by using average prices (or lowest prices) of common stock in a period preceding, surrounding or following the grant date.
Tax Deductibility of Pay
Section 162(m) of the Internal Revenue Code of 1986, as amended, limits the amount of compensation that SPR may deduct in any one year to $1,000,000 with respect to each of its five most highly compensated executive officers. There is an exception to that limitation for certain performance-based compensation. For 2006, management believes that substantially all of the compensation paid to its executive officers satisfies the requirements for deductability under Section 162(m).
Minimum Ownership Guidelines
The Committee has established minimum ownership guidelines for NEOs. The CEO is expected to maintain two times his annual salary in SPR stock, and the remaining NEOs are expected to maintain one and a half times their annual salary in SPR stock. The CEO and the NEOs have five years from the date of their employment to meet this requirement.
Other Benefits
The Committee attempts to provide retirement benefits, perquisites and post termination commitments to NEOs that are consistent with those generally offered by other utilities, based in part on the Committee’s review of annual market assessments performed by Towers Perrin.
Components of the Executive Compensation Program
This section outlines the components of SPR’s compensation program for NEOs and explains why the Committee believes that each is important and how it relates to SPR’s overall strategy on compensation.
Cash Compensation
Cash compensation for NEO’s in 2006, which consisted primarily of base salary and incentives under the STIP, was designed to deliver cash compensation at approximately the 50th percentile of the market rate for similar positions within the selected peer group companies, discussed above. Performance-based STIP incentives are designed to motivate NEOs to pursue specific short term objectives that are consistent with the immediate needs of the business in the year of grant.
Salary
The base salary for each NEO is set by the Committee at its meeting in February each year. The CEO has an employment agreement that provides a minimum base salary. The other NEOs have minimum salaries established by their offer letters. Increases
183
or decreases to base salary for the CEO are made by the Committee. In making this determination, the Committee reviews the performance of the CEO and reviews market information provided by Towers Perrin. For the NEOs, other than the CEO, annual compensation recommendations are made to the Committee by the CEO, based upon his review of their respective performances and market information provided by Towers Perrin. The Committee has final approval authority for salaries for the NEOs. In establishing salaries, the Committee is mindful of its overall goal to pay cash compensation to its executive officers at approximately the 50th percentile of cash compensation paid by other peer group companies, as discussed above.
The amount of cash compensation that is provided in the form of base salary is generally less than the potential amount that is provided in the form of bonuses under SPR’s combined STIP and LTIP plans, assuming threshold performance levels are met. This weighting reflects the Committee’s objective to ensure that a substantial amount of each NEO’s total compensation is tied to the achievement of short term and long term corporate, business unit and individual performance goals.
Short Term Incentive Plan (STIP)
The STIP provides for cash payments to all employees based upon the achievement of goals set for a single fiscal year. The plan is reviewed and revised annually by the Committee and metrics are developed for overall corporate goals as well as goals for each business unit within SPR. Goals and metrics for STIP are laid out in a “scorecard,” which is measured and monitored by the Finance and Internal Audit groups within SPR. Overall corporate goals and individual departments progress against the scorecard is available to employees in hard copy and electronic form on a quarterly basis.
The STIP plan allows the CEO to consider the overall financial performance and the condition of SPR in finally determining whether or not to make or reduce the STIP payment. However, the CEO has utilized his authority to pay or withhold STIP payments when the performance criteria has or has not been met, only under exceptional circumstances. The CEO’s discretion to make or withhold payments that would otherwise be made or not be made is applied on a company wide basis, not a case-by-case basis.
At the February Committee meeting, the Committee sets target STIP goals for each of the NEOs based upon input and discussions with management and the external compensation consultants. Target STIP bonuses in 2006 were set at 75% of base salary for the CEO and set at 50% of base salary for the other NEOs. For 2006, the Committee selected categories upon which to gauge SPR’s and NEOs’ annual performance. Each category was assigned a percentage weighting as follows:
| | | | | |
| Financial Performance | | | 30 | % |
| Customer Perception | | | 30 | % |
| Business Unit Performance | | | 20 | % |
| Individual Performance Assessment | | | 20 | % |
Financial Performance is measured by the amount of expenditures relating to operations, maintenance and capital spending versus approved financial budgets, as well as the management of employee headcounts. Since the control of expenditures for operations and maintenance is critical, these expenditures were assigned a 50% weighting in the STIP calculation. The calculation measures actual expenditures compared to budgeted expenditures, and tracks this data from the Monthly Executive Financial Summary report with data from the General Ledger. Control of Capital spending was assigned a 40% weighting in the STIP calculation, and it also measures actual expenditures compared to budgeted expenditures. This data was also tracked in the Monthly Executive Financial Summary report with data from the General Ledger. Control of employee headcount was considered to be important in managing Company costs. This measure was assigned a 10% weighting in the STIP calculation. Data from this measure is derived from the Human Resource database.
As SPR continues to expand and grow, SPR believes that it is important to maintain and improve customer perception of service levels. Customer perception is measured by the firm of Market Strategies, Inc. They select a statistically significant sample of residential, commercial and major account customers who are asked to rate what they feel about SPR on a scale of zero to ten, with zero being very unfavorable and ten being very favorable. A weighting of 100% is assigned to this measure of customer satisfaction for STIP purposes.
Specific Business Unit Performance measures are developed for each of SPR’s six organizational units, as well as SPR’s two local unions. Each organizational unit and union typically has at least five measures that are important to the success of the overall company.
Individual performance is also a component of compensation for the CEO and NEOs under the STIP program and it is assigned a weighting of 20%. Annually, the performance of the CEO is evaluated by the Committee, and the Chair of the Committee has the authority to determine a payment to the CEO under the individual performance component of the STIP program. The Chair of the Committee and the CEO make the determination on payments to the NEOs regarding the individual performance component of the STIP program.
As mentioned, the CEO has the discretion to determine whether SPR’s performance merits a recommendation to the Committee as to whether or not to make STIP payments. Actual payments under STIP can range for each NEO from nothing to 150% of the NEO’s target percentage. For fiscal 2006, SPR exceeded all minimum thresholds for STIP goals, which generated award payments under the STIP for the CEO of 80% of his base salary, and for each NEO, of approximately 50% of his base salary.
184
Cash Allowance
The CEO and each NEO is given a cash allowance, which can be used at their discretion. Typically, this group has used their cash allowance to offset expenses associated with acquiring financial planning and tax services, or to purchase / lease a vehicle to be used for business purposes. The Board of Directors elected to use cash allowances to simplify the administrative process of handling such requirements. For 2006, the CEO’s cash allowance was $30,000 and the remaining NEOs received between $11,000 and $15,000 each.
Equity Compensation
Long Term Incentive Plan (LTIP)
In 2006, the NEOs, other than the CEO, received two-thirds of the value of their LTIP awards in the form of Performance Shares and the other third in non-qualified stock options, or NQSO’s; all of the CEO’s LTIP awards were in the form of performance shares. The Committee believes that the 2006 equity awards serve to align the interests of the NEOs, with SPR’s shareholders and customers as they were weighted more heavily for performance against the Dow Jones Utility average than simple share price appreciation. While share price is a key indicator of the success of any public enterprise, the Committee believes that outperforming the peer group of companies in the DJUI is more critical to the success of SPR during the period over which the 2006 LTIP grants will vest.
The amount of equity compensation that is provided to each NEO in a given year is generally determined in reference to the NEO’s base salary for that year. The Committee generally approves an award for each NEO each year with a present cash value that is determined by multiplying the NEO’s base salary by a percentage. The percentage that the Committee selects for a given year depends upon the Committee’s assessment of the appropriate balance between cash and equity compensation. In making that assessment, the Committee considers factors such as the relative merits of cash and equity as a device for retaining and motivating NEOs and practices used by other utility and energy companies. In 2006, the Committee resolved to make equity awards that had a present cash value equal to 86% of base salary compensation to the NEOs, with the exception of the CEO. The present cash value of LTIP NQSO’s was determined by using a modified binomial valuation model calculated by the external compensation consultant, Towers Perrin, and assumptions regarding turnover, dividend trends and the expected life of the options. The CEO has a performance contract which calls for his long-term incentive performance to be measured and rewarded quarterly. On a quarterly basis, the CEO is measured on the following criteria:
| | • | | total shareholder return against the Dow Jones Utility Index; |
| |
| | • | | recovery of deferred energy disallowed in NPC’s 2001 Deferred Energy Case; |
| |
| | • | | restoration of investment grade status for the Utilities’ senior secured debt; |
| |
| | • | | a satisfactory achievement of regulatory and litigation milestones as measured by the Board; |
| |
| | • | | restoration of the common stock dividend; and |
| |
| | • | | attaining Public Utilities Commission of Nevada approval and securing all necessary licenses and permits required to commence construction of the Ely Energy Center. |
While most of SPR’s stock option awards to NEOs have historically been made pursuant to its annual grant program under the LTIP, the Committee retains the discretion to make additional awards to executive officers at other times, in connection with the initial hiring of a new officer, for retention purposes or otherwise. In 2006, the Committee granted such awards to a newly hired executive with a grant price equal to the closing price of SPR’s common stock on the day he signed his employment agreement. SPR does not have any program, plan or test practice to time such additional awards in coordination with the release of material non-public information.
In 2006, the Committee reduced the CEO long-term incentive award during a quarterly measurement period, based upon their assessment of his performance against specific SPR objectives specified in his employment agreement. Under the terms of the CEO’s employment agreement, in connection with regulatory and litigation measures, the Board may use discretion as to the number of shares delivered based on their assessment of the level of achievement. The Committee believed that a partial award was justified in connection with these milestones for settlement of the Enron litigation.
Non-Qualified Stock Options
Non-Qualified Stock Options granted under the LTIP may vest on the basis of the satisfaction of performance conditions established by the Committee or on the basis of a passage of time and continued employment. The NQSO’s granted in 2006 are time vested, one-third per year over the three-year period from the date of the grant. The NQSO’s have a ten year option life, and contain forfeiture provisions in the case of certain terminations of employment.
185
Performance Shares
Performance Shares are shares that typically vest at the end of a three-year period to the extent that specific performance targets determined by the Committee are met. If these objectives are not met, the Performance Shares are forfeited. Performance Shares do not have any voting rights in stockholder votes. Performance shares may be paid in stock or cash equivalents after vesting and do not entitle the recipient to receive dividends or dividend equivalents.
In 2006, Performance Shares granted under the LTIP were based on SPR’s Total Shareholder Return (TSR) compared to the TSR of Dow Jones Utility Index companies. The CEO did not participate in this grant since he was provided with the employment agreement LTIP opportunity discussed above. The Performance Shares for the remaining NEO’s are measured at the end of a three year calendar period against the Dow Jones Utility Index. Shares will be earned according to the table shown below:
| | | | | |
| Performance | | Shares Earned |
| Below 35th Percentile | | 0% of grant |
| 35th Percentile | | 50% of grant |
| 50th Percentile | | 100% of grant |
| 75th Percentile | | 150% of grant |
Retirement Plans
Pension Plan (Qualified Plan)
SPR has a tax-qualified, noncontributory defined-benefit pension plan that covers certain eligible employees, including the NEOs. Benefits under the Pension Plan are based upon the employee’s years of service and his or her highest average earnings for a five consecutive calendar year period with SPR and its subsidiaries. Benefits are payable after retirement in the form of an annuity; lump sum payments are only available to terminated employees who have less than a $50,000 actuarial present value. Earnings, for purposes of the calculation of benefits under the Pension Plan, are generally defined to include base salary and STIP payments and exclude other forms of compensation. The amount of annual earnings that may be considered in calculating benefits under the Pension Plan is limited by law. For 2006, the annual limitation was $220,000.
Benefits under SPR’s Pension Plan are calculated as an annuity according to the following formula:
(1.325% x “Final Average Earnings” x “Benefit Accrual Service”) + (0.475% x “Excess Compensation” [over the Social Security covered compensation] x “Benefit Accrual Service” up to 35 year maximum)
Contributions to the Pension Plan are made exclusively by SPR and are paid into a trust fund from which benefits are paid to participants. The Pension Plan currently limits pensions paid under the plan to an annual maximum of $175,000 payable beginning at age 65 in accordance with IRS requirements.
Non-Qualified Restoration Plan
SPR also has an unfunded pension plan (the Non-Qualified Restoration Plan) that provides for payments out of the general assets of SPR an amount substantially equal to the difference between the amount that would have been payable under the Qualified Plan, in the absence of laws limiting pension benefits and earnings that must be considered in calculating pension benefits, and the amount actually payable under the Qualified Plan. The formula for determining this benefit is the same as for the Qualified Plan. In the Non-Qualified Restoration Plan, total compensation (as defined in the Qualified plan) is used and the Qualified Plan portion of the payment is subtracted, leaving a benefit payment from the Non-Qualified Restoration Plan to be net of Qualified Plan payment.
Non-Qualified Supplemental Executive Retirement Plan or SERP
The SERP was adopted by SPR in 1990 and restated in May of 2002. The plan provides for payments beginning at age 65 of an annual amount determined by the following formula:
Step 1. (3.0% x SERP “Final Average Earnings*” x “Years of Service” up to 15 years) + (1.5% x SERP Final Average Earnings” x “Years of Service” over 15 yrs).
Step 2.Less the benefit payable under the Qualified Retirement Plan.
(1.325% x “Final Average Earnings” x “Benefit Accrual Service”) + (0.475% x “Excess Compensation” x “Benefit Accrual Service” up to 35 year maximum)
186
Step 3.Less the benefit payable under the Non Qualified Restoration Plan (already included in Step 2, if IRS limitation rules are not taken into account).
*SERP “Final Average Earnings” reflect a three consecutive calendar year period, but otherwise are only minimally different than “Final Average Earnings” under the Qualified Pension Plan and include specific income items approved by the Board of Directors.
The CEO and the NEOs participate in the SERP. The SERP is designed to provide a competitive supplemental benefit that is beneficial in the attraction and retention of key executive talent.
Non-Qualified Deferred Compensation Program
Executive officers are also eligible for participation in the Non-Qualified Deferred Compensation program, which is a supplement to the 401(k) program. All employees are eligible for participation in the NQDC plan if they make in excess of $110,000 in base salary and are in the top 5% highly compensated group of employees. The Plan provides eligible participants the opportunity to defer compensation on a pre-tax basis and direct the investment of these amounts in hypothetical investments that mirror the 401(k) investment options. The “match restoration” provision of the Plan provides for an employer match, according to the 401(k) plan design, which is not otherwise provided under SPR’s 401(k) Plan due to IRS defined limits.
This “match restoration” under the Plan when added to the employer match provided under SPR’s 401(k) Plan will result in a 100% match of employee contributions up to 6% of eligible earnings.
Other Benefits
General employee benefits for medical, dental and vision insurance, 401(k) plan, ESPP, and life insurance and disability coverage are made available to all nonunion Management, Professional and Technical (MPAT) employees at SPR. These same benefit offerings form part of the compensation for the NEOs, and are identical to those offered to all other MPAT employees with two exceptions.
SPR provides the CEO with supplemental life insurance coverage per his employment contract of $2,000,000 and life insurance while traveling with a death benefit of an additional $1,000,000. All other NEOs are provided with supplemental life insurance coverage in the amount of $500,000.
Perquisites
SPR may provide NEOs with certain perquisites. These perquisites may include:
| | • | | Housing Allowances (for alternate work locations) |
| |
| | • | | Executive Physical Programs |
| |
| | • | | Tax gross ups on specific expenses |
A complete listing and value associated with these perquisites are shown in the Summary Compensation table as “All Other Compensation.”
SPR provides these perquisites for different reasons that are of benefit to SPR. These perquisites reflect competitive business practices for SPR’s competitive peer group, and the Committee considers them necessary for retention and recruitment purposes. The Committee reviews the perquisites provided to the NEOs on a regular basis in an attempt to ensure that they continue to be appropriate in light of the Committee’s overall goal of designing a compensation program for NEOs that maximizes the interests of the shareholders and customers.
Post -Termination Compensation
SPR has entered into change in control severance agreements with all of the NEOs. These agreements provide for payments and other benefits if the officer’s employment terminates for a qualifying event or circumstances, including, but not limited to, being terminated without “cause” or leaving employment for “good reason” as these terms are defined in the severance agreements. Additional information regarding the Severance Agreements and the Transitional Compensation Agreements including a definition of key terms and a quantification of benefits that would have been received by SPR’s NEOs had termination occurred on or before December 31, 2006 is found under the heading “Potential Payments upon Termination or Change in Control” of the Compensation Discussion and Analysis.
The Committee believes that these severance and transitional compensation arrangements are an important part of overall compensation for the NEO’s. The Committee believes that these agreements will help to secure the continued employment and focus of the NEOs, notwithstanding any concern that they might have regarding their own continued employment, prior to or following a
187
change in control. The Committee also believes that these agreements are an important recruiting and retention tool, as most of the companies with which SPR competes for talent have similar agreements in place for their senior executives.
SUMMARY COMPENSATION TABLE
The following table sets forth information about the compensation of the Chief Executive Officer, the Chief Financial Officer and each of the three most highly compensated officers, for services in all capacities to SPR and its subsidiaries.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Change in | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Non- | | Qualified and | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Equity | | Non-Qualified | | All Other | | | | |
| | | | | | | | | | | | | | | Stock Awards | | Option | | Incentive | | Deferred | | Compensation | | | | |
| Name and Principal | | | | | | | | | | Bonus ($) | | ($) | | Awards ($) | | Plan ($) | | Compensation | | ($) | | | | |
| Position | | Year | | Salary ($) | | (1) | | (2) | | (2) | | (3) | | ($)(6) | | (7) | Total ($) | |
| |
| Walter M. Higgins (5) | | | 2006 | | | $ | 743,654 | | | $ | 333,333 | | | $ | 1,998,892 | | | $ | — | | | $ | 594,750 | | | $ | 1,719,679 | | | $ | 180,705 | | | $ | 5,571,013 | |
Chairman of the Board,
President, and Chief
Executive Officer | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Michael W. Yackira (5) | | | 2006 | | | $ | 373,846 | | | $ | — | | | $ | 260,466 | | | $ | 376,527 | | | $ | 200,000 | | | $ | 196,991 | | | $ | 57,577 | | | $ | 1,465,408 | |
Corporate Executive Vice
President, Chief Financial Officer | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Paul J. Kaleta (4) | | | 2006 | | | $ | 268,846 | | | $ | 65,000 | | | $ | 174,601 | | | $ | 221,505 | | | $ | 150,000 | | | $ | 41,554 | | | $ | 341,498 | | | $ | 1,263,004 | |
Corporate Sr. Vice
President, General Counsel | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Roberto R. Denis | | | 2006 | | | $ | 297,693 | | | $ | — | | | $ | 218,097 | | | $ | 324,913 | | | $ | 165,000 | | | $ | 189,990 | | | $ | 58,108 | | | $ | 1,253,800 | |
Corporate Sr. Vice
President, Energy Supply | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli | | | 2006 | | | $ | 332,115 | | | $ | — | | | $ | 229,241 | | | $ | 62,908 | | | $ | 165,000 | | | $ | 394,995 | | | $ | 88,640 | | | $ | 1,272,899 | |
Corporate Sr. Vice
President, Service Delivery and Operations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | In 2006, Mr. Higgins received a retention incentive payment in the amount of $333,333, and Mr. Kaleta was paid a signing bonus in the amount of $65,000. |
| |
| (2) | | “Stock Awards” consists of the values for performance shares and restricted stock; “Option Awards” consists of the values for non-qualified stock options. Assumptions used to value these awards are consistent with contemporary practices for their accounting treatment and recognized in accordance with SFAS No. 123R “Share Based Payments” in 2006. Reference Note 12, Stock Compensation Plans, of the Footnotes to the Consolidated Financial Statements. |
| (3) | | The amounts presented for Non-Equity Incentive Plan awards consist of payments under the Short-Term Incentive Plan earned in 2006, and are calculated using base salary which could differ from the amount reported in the “Salary” column. |
| |
| (4) | | Mr. Kaleta was appointed to the position of Corporate Senior Vice President and General Counsel in February 2006. |
| |
| (5) | | Effective February 15, 2007, Mr. Higgins’ is Chairman and Chief Executive Officer of SPR, and Mr. Yackira is President and Chief Operating Officer of SPR. |
| |
| (6) | | Deferred Compensation reflects the following factors that result in an increase in value: |
| | i. | | Increase in final average pay resulting primarily from increases in incentive compensation payments made in 2006 |
| |
| | ii. | | Increase in service (by 1 year) used to calculate the benefit |
| |
| | iii. | | Decrease in period to time before commencement (by 1 year) |
| | |
| |
| | The increase in incentive compensation payments reflects the achievement of targeted goals and the overall improved financial health of the company. Final average pay for purposes of the calculation of the amounts shown in this table includes 2006 compensation in the averaging period, replacing the 2001 compensation for Restoration Plan purposes and 2003 compensation for SERP purposes that would be used in the prior year calculations. |
| |
| (7) | | Amounts for All Other Compensation include the following for 2006: |
188
ALL OTHER COMPENSATION TABLE
| | | | | | | | | | | | | | | | | | | | | |
| | | Walter M. | | | Michael | | | Paul J. | | | Roberto R. | | | Jeffrey L. | |
| Description | | Higgins | | | W. Yackira | | | Kaleta | | | Denis | | | Ceccarelli | |
| |
| SPR contributions to the 401k deferred compensation plan | | $ | 13,200 | | | $ | 13,200 | | | $ | 9,154 | | | $ | 13,200 | | | $ | 13,200 | |
| | | | | | | | | | | | | | | | | | | | | |
| Imputed income on group term life insurance and premiums paid for executive term life policies | | $ | 14,666 | | | $ | 4,281 | | | $ | 1,840 | | | $ | 3,600 | | | $ | 2,464 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash in lieu of forgone vacation | | $ | 47,308 | | | $ | 25,096 | | | $ | 14,331 | | | $ | 29,308 | | | $ | 15,977 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cash allowance to be used at the discretion of the executive | | $ | 30,000 | | | $ | 15,000 | | | $ | 11,077 | | | $ | 12,000 | | | $ | 15,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Housing Allowance (for alternate work location) | | $ | 75,531 | | | $ | — | | | $ | — | | | $ | — | | | $ | 42,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Relocation Expense | | $ | — | | | $ | — | | | $ | 261,084 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Tax gross up on relocation expenses | | $ | — | | | $ | — | | | $ | 44,012 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| |
| Total | | $ | 180,705 | | | $ | 57,577 | | | $ | 341,498 | | | $ | 58,108 | | | $ | 88,641 | |
GRANTS OF PLAN-BASED AWARDS
All grants of plan-based awards to the named executive officers of SPR in 2006 are presented in the table below. The incentive plans under which these grants were made are fully described in the Compensation Discussion and Analysis section.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exercise | | Grant Date |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | All | | All | | or Base | | Fair Value |
| | | | | | | Estimated Future Payouts Under | | Estimated Future Payouts Under | | Other | | Other | | Price of | | of Stock or |
| | | | | | | Non-Equity Incentive Plan Awards | | Equity Incentive Plan Awards | | Stock | | Option | | Option | | Option |
| | | | | | | Threshold | | Target | | Maximum | | Threshold | | Target | | Maximum | | Awards | | Awards | | Awards | | Awards |
| Name | | Grant Date | | | | ($) | | ($) | | ($) | | (#) | | (#) | | (#) | | (#) | | (#) | | ($/sh) | | ($) |
| |
| Walter M. Higgins Performance Shares | | 08/04/2006 | | | | | | | | | | | | | | | | | 42,500 | | | | 450,000 | | | | 500,000 | | | | | | | | | | | | | | | $ | 7,225,000 | |
| Short-Term Incentive Plan | | 01/01/2006 | | | | | | | | $ | 594,750 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Michael W. Yackira Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 17,527 | | | $ | 13.29 | | | $ | 84,558 | |
| Performance Shares | | 02/07/2006 | | | | | | | | | | | | | | | | | 10,432 | | | | 20,864 | | | | 31,296 | | | | | | | | | | | | | | | $ | 96,879 | |
| Short-Term Incentive Plan | | 01/01/2006 | | | | | | | | $ | 200,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Paul J. Kaleta Options | | 02/01/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 30,000 | | | $ | 13.10 | | | $ | 144,600 | |
| Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8,224 | | | $ | 13.29 | | | $ | 39,675 | |
| Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,112 | | | $ | 13.29 | | | $ | 10,189 | |
| Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 14,405 | | | $ | 13.29 | | | $ | 69,496 | |
| Performance Shares | | 02/07/2006 | | | | | | | | | | | | | | | | | 8,575 | | | | 17,149 | | | | 25,724 | | | | | | | | | | | | | | | $ | 79,629 | |
| Restricted Shares | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,643 | | | | | | | | | | | $ | 74,995 | |
| Short-Term Incentive Plan | | 01/01/2006 | | | | | | | | $ | 150,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Roberto R. Denis Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 13,445 | | | $ | 13.29 | | | $ | 64,864 | |
| Performance Shares | | 02/07/2006 | | | | | | | | | | | | | | | | | 8,003 | | | | 16,005 | | | | 24,008 | | | | | | | | | | | | | | | $ | 74,317 | |
| Short-Term Incentive Plan | | 01/01/2006 | | | | | | | | $ | 165,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli Options | | 02/07/2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 14,886 | | | $ | 13.29 | | | $ | 71,816 | |
| Performance Shares | | 02/07/2006 | | | | | | | | | | | | | | | | | 8,860 | | | | 17,720 | | | | 26,580 | | | | | | | | | | | | | | | $ | 82,280 | |
| Short-Term Incentive Plan | | 01/01/2006 | | | | | | | | $ | 165,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
189
| 1. | | Mr. Higgins’ performance share grant of 500,000 shares, dated August 4, 2006, was awarded per an employment agreement executed on that date. Of this amount, 65,000 shares were earned and issued in October 2006. The value of these vested shares is reflected in the “Summary Compensation Table,” and the remaining unvested portion is included in the “Outstanding Equity Awards at Fiscal Year-End Table.” A total of 353,282 outstanding performance shares from his previous employment agreement, signed in 2003, were cancelled upon the execution of this new agreement. According to the terms of his new employment agreement, Mr. Higgins is entitled to receive the following performance shares with the achievement of certain criteria, if they are met by June 1, 2008: |
| | i. | | Shareholder return as measured by the Dow Jones Utility Index: |
| | 1. | | if SPR is positioned in the 40th percentile, 42,500 shares will be awarded. |
| |
| | 2. | | if SPR is positioned at or above the 50th percentile, 85,000 shares will be awarded. |
| |
| | 3. | | if SPR is positioned at or above the 70th percentile, 135,000 shares will be awarded. |
| | ii. | | Recover all of the deferred energy charges previously denied in the 2002 PUCN deferred energy case, 50,000 shares, with final assessment of achievement to be at the discretion of the Board of Directors. |
| |
| | iii. | | Restore investment grade status for the senior secured debt of the Utilities, 100,000 shares, no award if goal is not attained. |
| |
| | iv. | | Satisfactory achievement of remaining regulatory and litigation milestones, as measured by the Board of Directors, 65,000 shares, final award to be at the discretion of the Board of Directors. |
| |
| | v. | | Restore quarterly common stock dividend, 100,000 shares, no award if goal is not attained. |
| |
| | vi. | | Attain PUCN approval and secure all necessary licenses and permits required to commence construction of the proposed Ely plant, 50,000 shares, number of shares awarded to be at the discretion of the Board of Directors. |
| 2. | | The performance share grants dated February 7, 2006 have a three year performance and vesting period ending on December 31, 2008. |
| | i. | | The threshold represents the minimum acceptable performance which, if attained, results in payment of 50% of the target award. |
| |
| | Performance below the minimum acceptable level results in no award earned. |
| |
| | ii. | | The target indicates a level of outstanding performance and which, if attained, results in payment of 100% of the target award. |
| |
| | iii. | | The maximum represents a level indicative of exceptional performance which, if attained, results in a payment of 150% of the target award. |
| 3. | | For the executives listed above all option grants dated February 7, 2006 will vest over three years at one-third per year, except for the option to purchase 30,000 shares and 2,112 shares, as described in footnote(4) below, granted to Mr. Kaleta. |
| |
| 4. | | In addition to the above grants, upon his hire Mr. Kaleta was also granted: |
| | i. | | an option award of 30,000 shares, with a one year vesting period beginning on the grant date of February 1, 2006. |
| |
| | ii. | | a restricted shares award of 5,643 shares, with a grant date of February 7, 2006, which was fully vested on December 31, 2006. |
| |
| | iii. | | an option award of 2,112 shares which will vest only upon the restoration of the quarterly common stock dividend before February 7, 2010. |
190
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table provides information about all awards held by the named executive officers at December 31, 2006:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | OPTION AWARDS | | | STOCK AWARDS |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity | | | Equity |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Incentive | | | Incentive |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plan | | | Plan |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Awards: | | | Awards: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Number | | | Market or |
| | | | | | | | | | | Equity | | | | | | | | | | | Number | | | Market | | | of | | | Payout |
| | | | | | | | | | | Incentive | | | | | | | | | | | of | | | Value of | | | Unearned | | | Value of |
| | | | | | | | | | | Plan | | | | | | | | | | | Shares | | | Shares or | | | Shares, | | | Unearned |
| | | | | | | | | | | Awards: | | | | | | | | | | | or Units | | | Units of | | | Units or | | | Shares, |
| | | Number of | | | Number of | | | Number of | | | | | | | | | | | of Stock | | | Stock | | | Other | | | Units or |
| | | Securities | | | Securities | | | Securities | | | | | | | | | | | that | | | that Have | | | Rights | | | Other |
| | | Underlying | | | Underlying | | | Underlying | | | | | | | | | | | Have | | | Not | | | that Have | | | Rights that |
| | | Unexercised | | | Unexercised | | | Unexercised | | | Option | | | Option | | | Not | | | Vested | | | Not | | | Have Not |
| | | Options (#) | | | Options (#) | | | Unearned | | | Exercise | | | Expiration | | | Vested | | | ($) | | | Vested | | | Vested ($) |
| Name | | Exercisable | | | Unexercisable | | | Options (#) | | | Price ($) | | | Date | | | (#) | | | (1) | | | (#) | | | (1) |
| Walter M. Higgins | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options - 08/04/2000 | (2) | | 400,000 | | | | | | | | | | | $ | 16.00 | | | | 02/19/2009 | | | | | | | | | | | | | | | | | |
| Options - 01/01/2001 | (3) | | 110,130 | | | | | | | | | | | $ | 14.80 | | | | 01/02/2011 | | | | | | | | | | | | | | | | | |
| Options - 01/01/2002 | (3) | | 123,900 | | | | | | | | | | | $ | 15.58 | | | | 01/02/2012 | | | | | | | | | | | | | | | | | |
| Performance Shares -08/04/2006 | (4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 435,000 | | | $ | 7,321,050 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Michael W. Yackira | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (3) | | 6,212 | | | | 12,426 | | | | | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (5) | | | | | | | | | | 4,660 | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (3) | | | | | | 17,527 | | | | | | | $ | 13.29 | | | | 02/08/2016 | | | | | | | | | | | | | | | | | |
| Performance Shares -02/07/2005 | (6) | | | | | | | | | | | | | | | | | | | | | | 15,775 | | | $ | 265,501 | | | | 7,887 | | | $ | 132,731 | |
| Performance Shares -02/07/2005 | (7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,915 | | | $ | 99,550 | |
| Performance Shares -02/07/2006 | (6) | | | | | | | | | | | | | | | | | | | | | | 6,954 | | | $ | 117,035 | | | | 13,910 | | | $ | 234,106 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Paul J. Kaleta | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options - 02/01/2006 | (8) | | | | | | 30,000 | | | | | | | $ | 13.10 | | | | 02/02/2016 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (3) | | | | | | 8,224 | | | | | | | $ | 13.29 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (5) | | | | | | | | | | 2,112 | | | $ | 13.29 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (3) | | | | | | 14,405 | | | | | | | $ | 13.29 | | | | 02/08/2016 | | | | | | | | | | | | | | | | | |
| Performance Shares -02/07/2006 | (6) | | | | | | | | | | | | | | | | | | | | | | 6,959 | | | $ | 117,120 | | | | 3,479 | | | $ | 58,551 | |
| Performance Shares -02/07/2006 | (7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,610 | | | $ | 43,927 | |
| Performance Shares -02/07/2006 | (6) | | | | | | | | | | | | | | | | | | | | | | 5,716 | | | $ | 96,196 | | | | 11,433 | | | $ | 192,421 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Roberto R. Denis | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (3) | | 3,700 | | | | 7,401 | | | | | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (5) | | | | | | | | | | 2,775 | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (3) | | | | | | 13,445 | | | | | | | $ | 13.29 | | | | 02/08/2016 | | | | | | | | | | | | | | | | | |
| Performance Shares -02/07/2005 | (6) | | | | | | | | | | | | | | | | | | | | | | 9,396 | | | $ | 158,131 | | | | 4,697 | | | $ | 79,054 | |
| Performance Shares -02/07/2005 | (7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,523 | | | $ | 59,292 | |
| Performance Shares -02/07/2006 | (6) | | | | | | | | | | | | | | | | | | | | | | 5,334 | | | $ | 89,779 | | | | 10,671 | | | $ | 179,585 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Options - 01/01/1998 | (3) | | 7,920 | | | | | | | | | | | $ | 24.93 | | | | 01/02/2008 | | | | | | | | | | | | | | | | | |
| Options - 01/01/1999 | (3) | | 7,920 | | | | | | | | | | | $ | 24.22 | | | | 01/02/2009 | | | | | | | | | | | | | | | | | |
| Options - 08/01/1999 | (9) | | 10,300 | | | | | | | | | | | $ | 26.00 | | | | 08/02/2009 | | | | | | | | | | | | | | | | | |
| Options - 01/01/2001 | (3) | | 22,510 | | | | | | | | | | | $ | 14.80 | | | | 01/02/2011 | | | | | | | | | | | | | | | | | |
| Options - 01/01/2002 | (3) | | 34,500 | | | | | | | | | | | $ | 15.58 | | | | 01/02/2012 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (3) | | 4,842 | | | | 9,685 | | | | | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2005 | (5) | | | | | | | | | | 3,632 | | | $ | 10.05 | | | | 02/08/2015 | | | | | | | | | | | | | | | | | |
| Options - 02/07/2006 | (3) | | | | | | 14,886 | | | | | | | $ | 13.29 | | | | 02/08/2016 | | | | | | | | | | | | | | | | | |
| Performance Shares -02/07/2005 | (6) | | | | | | | | | | | | | | | | | | | | | | 12,295 | | | $ | 206,930 | | | | 6,147 | | | $ | 103,449 | |
| Performance Shares -02/07/2005 | (7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4,611 | | | $ | 77,603 | |
| Performance Shares -02/07/2006 | (6) | | | | | | | | | | | | | | | | | | | | | | 5,906 | | | $ | 99,399 | | | | 11,814 | | | $ | 198,828 | |
| | |
| |
| | (1) | | Market Value is based on the December 31, 2006, closing trading price of SPR stock of $16.83; all incentive plan performance share awards are shown as achieving the target level of performance, which results in a 100% payout of the award. |
| |
| | (2) | | This grant vests over a four year period, one quarter each year beginning one year after grant date. |
| |
| | (3) | | These option awards vest over a three year period, one third each year beginning one year after grant date. |
| |
| | (4) | | Mr. Higgins was awarded 500,000 shares upon signing a new employment agreement in August 2006. These shares are to be earned upon the achievement of certain objectives prior to the expiration of the employment agreement in June 2008. Details of the performance criteria to be met are included in Footnote 1 to the “Grants of Plan-Based Awards” table. |
| |
| | (5) | | This grant will be earned upon the restoration of SPR’s common stock dividend within five years of grant date. |
| |
| | (6) | | These performance share awards are paid at the end of a three year performance period (measured from the date of grant) if the specified performance measures are achieved. |
| |
| | (7) | | This grant will be earned upon the return of NPC and SPPC to investment grade within three years of the award. |
| |
| | (8) | | This award was granted to Mr. Kaleta upon his hire in 2006 and will vest at the end of one year from date of grant. |
| |
| | (9) | | This award was granted to Mr. Ceccarelli upon the consummation of the merger between SPR and NPC, and vested one third each year over a three year period commencing January 2000. |
191
OPTION EXERCISES AND STOCK VESTED
The following table provides information on the exercises of options and the vesting of stock awards during 2006:
| | | | | | | | | | | | | | | | | |
| | | OPTION AWARDS | | STOCK AWARDS |
| | | Number of Shares | | Value Realized on | | Number of Shares | | Value Realized on |
| | | Acquired on | | Exercise ($) | | Acquired on | | Vesting ($) |
| Name | | Exercise (#) | | (1) | | Vesting (#) | | (2) |
| |
| Walter M. Higgins | | | | | | | | | | | | | | | | |
| Performance Shares | | | | | | | | | | | 65,000 | | | $ | 982,150 | |
| Restricted Shares | | | | | | | | | | | 42,300 | | | $ | 711,909 | |
| | | | | | | | | | | | | | | | | |
| Michael W. Yackira | | | | | | | | | | | | | | | | |
| Options | | | 30,000 | | | $ | 300,450 | | | | | | | | | |
| Restricted Shares | | | | | | | | | | | 12,544 | | | $ | 211,116 | |
| Restricted Shares | | | | | | | | | | | 39,894 | | | $ | 671,416 | |
| | | | | | | | | | | | | | | | | |
| Paul J. Kaleta | | | | | | | | | | | | | | | | |
| Restricted Shares | | | | | | | | | | | 5,643 | | | $ | 94,972 | |
| | | | | | | | | | | | | | | | | |
| Roberto R. Denis | | | | | | | | | | | | | | | | |
| Options | | | 25,000 | | | $ | 270,740 | | | | | | | | | |
| Restricted Shares | | | | | | | | | | | 3,334 | | | $ | 44,676 | |
| Restricted Shares | | | | | | | | | | | 7,600 | | | $ | 127,908 | |
| Restricted Shares | | | | | | | | | | | 25,931 | | | $ | 436,419 | |
| | | | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli | | | | | | | | | | | | | | | | |
| Restricted Shares | | | | | | | | | | | 11,270 | | | $ | 189,674 | |
| Restricted Shares | | | | | | | | | | | 33,245 | | | $ | 559,513 | |
| | |
| (1) | | The value realized on exercise is calculated as the fair market value on the date of exercise, less the exercise price of the option. |
| |
| (2) | | The value realized on vesting is calculated as the market value on the vesting date. |
192
PENSION BENEFITS
The following table provides the present value of accumulated retirement benefits payable to each of the named executive officers, according to the terms and conditions of each plan. The retirement plans under which these benefits are available are generally described in the Compensation Discussion and Analysis section of this note.
| | | | | | | | | | | | | | | |
| | | | | Number of | | | | |
| | | | | Years | | Present Value of | | Payments |
| | | | | Credited | | Accumulated | | During Last |
| Name | | Plan Name | | Service | | Benefit | | Fiscal Year |
| |
| Walter M. Higgins (1) | | SPR Retirement Plan | | | 10.250 | | | $ | 401,006 | | | $ | — | |
| | | SPR Restoration Plan | | | 10.250 | | | $ | 1,902,151 | | | $ | — | |
| | | SPR SERP Plan | | | 15.167 | | | $ | 5,119,017 | | | $ | — | |
| | | | | | | | | | | | | | | |
| Michael W. Yackira (2) | | SPR Retirement Plan | | | 3.667 | | | $ | 107,353 | | | $ | — | |
| | | SPR Restoration Plan | | | 3.667 | | | $ | 163,656 | | | $ | — | |
| | | SPR SERP Plan | | | 3.667 | | | $ | 240,339 | | | $ | — | |
| | | | | | | | | | | | | | | |
| Paul J. Kaleta (3) | | SPR Retirement Plan | | | 0.667 | | | $ | 17,571 | | | $ | — | |
| | | SPR Restoration Plan | | | 0.667 | | | $ | 5,490 | | | $ | — | |
| | | SPR SERP Plan | | | 0.667 | | | $ | 18,494 | | | $ | — | |
| | | | | | | | | | | | | | | |
| Roberto R. Denis (4) | | SPR Retirement Plan | | | 3.083 | | | $ | 96,097 | | | $ | — | |
| | | SPR Restoration Plan | | | 3.083 | | | $ | 101,882 | | | $ | — | |
| | | SPR SERP Plan | | | 6.083 | | | $ | 505,277 | | | $ | — | |
| | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli (5) | | SPR Retirement Plan | | | 31.000 | | | $ | 779,706 | | | $ | — | |
| | | SPR Restoration Plan | | | 31.000 | | | $ | 657,860 | | | $ | — | |
| | | SPR SERP Plan | | | 32.083 | | | $ | 570,835 | | | $ | — | |
| | |
| (1) | | Mr. Higgins’ benefit under the SERP plan includes 4 years, 11 months of imputed service. |
| |
| (2) | | Mr. Yackira will become vested in all plans in 1 year, 4 months. |
| |
| (3) | | Mr. Kaleta will become vested in all plans in 4 years, 4 months. |
| |
| (4) | | Mr. Denis’ benefit under the SERP plan includes 3 years of imputed service for attaining age 62; he will be vested in all plans in 1 year, 11 months. |
| |
| (5) | | Mr. Ceccarelli’s benefit under the SERP plan includes 1 year, 1 month of imputed service. |
The following assumptions were used in calculating the present value of the accumulated benefit:
| | i. | | Pension economic assumptions utilized for SPR’s FAS 158 financial reporting for fiscal year 2006, were used for the calculations. |
| |
| | ii. | | SPR reports using an early measurement date of September 30 and that date has been used in all calculations for the above table, and these assumptions are outlined below: |
| | a. | | The discount rate was 6.0% for 2006 |
| |
| | b. | | Postretirement mortality is based on the RP 2000 mortality table, projected to 2015 |
| |
| | c. | | There was assumed to be no pre-retirement mortality, turnover, or disability |
| |
| | d. | | Retirement age was assumed to be the greater of age 62 and current age |
| | iii. | | The demographic assumptions used are also consistent with pension financial reporting, with the exception as required by SEC guidance, that pre-retirement decrements are not used. |
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE-IN-CONTROL
The following tables show the estimated payments each of the named executives could receive upon their termination or a change-in-control, according to the terms and conditions of any contracts or agreements in effect for that executive. The amounts shown assume that the termination was effective as of December 31, 2006, and includes amounts earned through that time. The actual amounts to be paid out can only be determined at the time an executive separates from SPR.
193
The footnotes are presented after the final table.
Walter M. Higgins
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Reason for Termination | |
| | | Voluntary | | | For Cause | | | Death | | | Disability | | | Retirement | | | Without | | | Change-in- | |
| Type of Benefit | | (1) (8) | | | (2) (9) | | | (9) | | | (3) (9) | | | (4) | | | Cause (5) (10) | | | Control (6) (11) | |
| |
| Cash Severance (7) | | $ | 1,687,500 | | | $ | — | | | $ | 562,500 | | | $ | 562,500 | | | $ | 1,687,500 | | | $ | 1,312,500 | | | $ | 2,625,000 | |
| Life Insurance Proceeds (18) | | | | | | | | | | $ | 2,750,000 | | | | | | | | | | | | | | | | | |
| Cash LTIP Award | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Lump Sum Pension Equivalent (16) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity Benefits(12) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Shares | | $ | 1,144,659 | | | | | | | $ | 1,144,659 | | | $ | 1,144,659 | | | $ | 1,144,659 | | | $ | 1,144,659 | | | $ | 7,321,050 | |
| Restricted Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 401k Shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unexercisable Options | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Retirement Benefits (13) (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SPR Retirement Plan | | $ | 36,216 | | | | | | | $ | 18,108 | | | $ | 36,216 | | | $ | 36,216 | | | $ | 36,216 | | | $ | 36,216 | |
| SPR Restoration Plan | | $ | 169,284 | | | | | | | $ | 84,636 | | | $ | 169,284 | | | $ | 169,284 | | | $ | 169,284 | | | $ | 169,284 | |
| SPR SERP Plan | | $ | 447,984 | | | | | | | $ | 223,992 | | | $ | 447,984 | | | $ | 447,984 | | | $ | 447,984 | | | $ | 447,984 | |
| Retiree Medical | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested Deferred Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Health & Welfare (14) | | $ | 52,720 | | | | | | | | | | | | | | | | | | | $ | 114,429 | | | $ | 72,599 | |
| Outplacement | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Perquisites | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax Gross-Ups (15) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 3,813,167 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total of All Benefits (19) | | $ | 3,538,363 | | | $ | — | | | $ | 4,783,895 | | | $ | 2,360,643 | | | $ | 3,485,643 | | | $ | 3,225,072 | | | $ | 14,485,300 | |
| | | | | | | | | | | | | | | | | | | | | | |
Michael W. Yackira
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Reason for Termination | |
| | | | | | | | | | | | | | | | | | | | | | | Without | | | Change-in- | |
| | | Voluntary | | | For Cause | | | Death | | | Disability | | | Retirement | | | Cause (5) | | | Control (6) | |
| Type of Benefit | | (1) (8) | | | (2) (9) | | | (9) | | | (3) (9) | | | (4) | | | (10) | | | (11) | |
| |
| Cash Severance (7) | | $ | 375,000 | | | | — | | | | — | | | $ | 375,000 | | | $ | 375,000 | | | $ | 375,000 | | | $ | 1,687,500 | |
| Life Insurance Proceeds (18) | | | | | | | | | | $ | 1,063,000 | | | | | | | | | | | | | | | | | |
| Cash LTIP Award | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Lump Sum Pension Equivalent (16) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,192,714 | |
| Equity Benefits(12) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Shares | | $ | 1,132,161 | | | | | | | $ | 1,132,161 | | | $ | 1,132,161 | | | $ | 1,132,161 | | | $ | 1,132,161 | | | $ | 1,520,338 | |
| Restricted Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 401k Shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unexercisable Options | | $ | 177,891 | | | | | | | $ | 177,891 | | | $ | 177,891 | | | $ | 177,891 | | | $ | 177,891 | | | $ | 177,891 | |
| Retirement Benefits (13) (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SPR Retirement Plan | | | | | | | | | | | | | | | | | | | | | | $ | 8,016 | | | $ | 8,016 | |
| SPR Restoration Plan | | | | | | | | | | | | | | | | | | | | | | $ | 11,472 | | | $ | 11,472 | |
| SPR SERP Plan | | | | | | | | | | | | | | | | | | | | | | $ | 18,312 | | | $ | 18,312 | |
| Retiree Medical | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested Deferred Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Health & Welfare (14) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 65,362 | |
| Outplacement | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Perquisites | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax Gross-Ups (15) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total of All Benefits (19) | | $ | 1,685,052 | | | $ | — | | | $ | 2,373,052 | | | $ | 1,685,052 | | | $ | 1,685,052 | | | $ | 1,722,852 | | | $ | 4,681,605 | |
| | | | | | | | | | | | | | | | | | | | | | |
194
Paul J. Kaleta
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Reason for Termination | |
| | | | | | | | | | | | | | | | | | | | | | | Without | | | Change-in- | |
| | | Voluntary | | | For Cause | | | Death | | | Disability | | | Retirement | | | Cause (5) | | | Control (6) | |
| Type of Benefit | | (1) (8) | | | (2) (9) | | | (9) | | | (3) (9) | | | (4) | | | (10) | | | (11) | |
| |
| Cash Severance (7) | | $ | 300,000 | | | | — | | | | — | | | $ | 300,000 | | | $ | 300,000 | | | $ | 300,000 | | | $ | 1,305,000 | |
| Life Insurance Proceeds (18) | | | | | | | | | | $ | 850,000 | | | | | | | | | | | | | | | | | |
| Cash LTIP Award | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Lump Sum Pension Equivalent (16) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 523,994 | |
| Equity Benefits(12) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Shares | | $ | 329,182 | | | | | | | $ | 329,182 | | | $ | 329,182 | | | $ | 329,182 | | | $ | 329,182 | | | $ | 603,187 | |
| Restricted Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 401k Shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unexercisable Options | | $ | 199,483 | | | | | | | $ | 199,483 | | | $ | 199,483 | | | $ | 199,483 | | | $ | 199,483 | | | $ | 199,483 | |
| Retirement Benefits (13) (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SPR Retirement Plan | | | | | | | | | | | | | | | | | | | | | | $ | 1,920 | | | $ | 1,920 | |
| SPR Restoration Plan | | | | | | | | | | | | | | | | | | | | | | $ | 696 | | | $ | 696 | |
| SPR SERP Plan | | | | | | | | | | | | | | | | | | | | | | $ | 2,052 | | | $ | 2,052 | |
| Retiree Medical | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested Deferred Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Health & Welfare (14) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 58,406 | |
| Outplacement | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Perquisites | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax Gross-Ups (15) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total of All Benefits (19) | | $ | 828,665 | | | $ | — | | | $ | 1,378,665 | | | $ | 828,665 | | | $ | 828,665 | | | $ | 833,333 | | | $ | 2,694,738 | |
| | | | | | | | | | | | | | | | | | | | | | |
Roberto R. Denis
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Reason for Termination | |
| | | | | | | | | | | | | | | | | | | | | | | Without | | | Change-in- | |
| | | Voluntary | | | For Cause | | | Death | | | Disability | | | Retirement | | | Cause (5) | | | Control (6) | |
| Type of Benefit | | (1) (8) | | | (2) (9) | | | (9) | | | (3) (9) | | | (4) | | | (10) | | | (11) | |
| |
| Cash Severance (7) | | $ | 300,000 | | | | — | | | | — | | | $ | 300,000 | | | $ | 300,000 | | | $ | 300,000 | | | $ | 1,350,000 | |
| Life Insurance Proceeds (18) | | | | | | | | | | $ | 850,000 | | | | | | | | | | | | | | | | | |
| Cash LTIP Award | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Lump Sum Pension Equivalent (16) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,202,928 | |
| Equity Benefits(12) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Shares | | $ | 1,069,769 | | | | | | | $ | 1,069,769 | | | $ | 1,069,769 | | | $ | 1,069,769 | | | $ | 1,069,769 | | | $ | 1,404,043 | |
| Restricted Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 401k Shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unexercisable Options | | $ | 191,220 | | | | | | | $ | 191,220 | | | $ | 191,220 | | | $ | 191,220 | | | $ | 191,220 | | | $ | 191,220 | |
| Retirement Benefits (13) (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SPR Retirement Plan | | | | | | | | | | | | | | | | | | | | | | $ | 8,232 | | | $ | 8,232 | |
| SPR Restoration Plan | | | | | | | | | | | | | | | | | | | | | | $ | 7,632 | | | $ | 7,632 | |
| SPR SERP Plan | | | | | | | | | | | | | | | | | | | | | | $ | 13,500 | | | $ | 13,500 | |
| Retiree Medical | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested Deferred Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Health & Welfare (14) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 58,406 | |
| Outplacement | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Perquisites | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax Gross-Ups (15) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total of All Benefits (19) | | $ | 1,560,989 | | | $ | — | | | $ | 2,110,989 | | | $ | 1,560,989 | | | $ | 1,560,989 | | | $ | 1,590,353 | | | $ | 4,235,961 | |
| | | | | | | | | | | | | | | | | | | | | | |
195
Jeffrey L. Ceccarelli
VALUE OF SEVERANCE AND CHANGE-IN-CONTROL AGREEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Reason for Termination | |
| | | | | | | | | | | | | | | | | | | | | | | Without | | | Change-in- | |
| | | Voluntary | | | For Cause | | | Death | | | Disability | | | Retirement | | | Cause (5) | | | Control (6) | |
| Type of Benefit | | (1) (8) | | | (2) (9) | | | (9) | | | (3) (9) | | | (4) | | | (10) | | | (11) | |
| |
| Cash Severance (7) | | $ | 335,000 | | | | — | | | | — | | | $ | 335,000 | | | $ | 335,000 | | | $ | 335,000 | | | $ | 1,507,500 | |
| Life Insurance Proceeds (18) | | | | | | | | | | $ | 1,003,000 | | | | | | | | | | | | | | | | | |
| Cash LTIP Award | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Lump Sum Pension Equivalent (16) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 343,276 | |
| Equity Benefits(12) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Shares | | $ | 925,689 | | | | | | | $ | 925,689 | | | $ | 925,689 | | | $ | 925,689 | | | $ | 925,689 | | | $ | 1,245,723 | |
| Restricted Stock | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 401k Shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unexercisable Options | | $ | 142,990 | | | | | | | $ | 142,990 | | | $ | 142,990 | | | $ | 142,990 | | | $ | 142,990 | | | $ | 142,990 | |
| Retirement Benefits (13) (17) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| SPR Retirement Plan | | $ | 60,876 | | | | | | | $ | 52,476 | | | $ | 60,876 | | | $ | 60,876 | | | $ | 60,876 | | | $ | 60,876 | |
| SPR Restoration Plan | | $ | 51,372 | | | | | | | $ | 44,292 | | | $ | 51,372 | | | $ | 51,372 | | | $ | 51,372 | | | $ | 51,372 | |
| SPR SERP Plan | | $ | 42,972 | | | | | | | $ | 37,044 | | | $ | 42,972 | | | $ | 42,972 | | | $ | 42,972 | | | $ | 42,972 | |
| Retiree Medical | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested Deferred Compensation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Benefits | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Health & Welfare (14) | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 61,761 | |
| Outplacement | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Perquisites | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax Gross-Ups (15) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total of All Benefits (19) | | $ | 1,558,899 | | | $ | — | | | $ | 2,205,491 | | | $ | 1,558,899 | | | $ | 1,558,899 | | | $ | 1,558,899 | | | $ | 3,456,470 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Voluntary Terminationis defined for Mr. Higgins consistent with his employment agreement dated August 4, 2006. The document provides for a benefit equal to continued salary through June 1, 2008, provided he voluntarily resigns with the Board’s consent prior to June 1, 2008. In addition, he would be eligible to receive a pro-rata payment for all Short Term Incentive Awards, which equals 75% of base pay for 2006, and which otherwise would have been earned but unpaid by that date. For each of the other named executives, Voluntary Termination is defined as the executive resigning for good cause consistent with the terms of his employment agreement. |
| |
| (2) | | Termination For Causerequires SPR to terminate the employment relationship based on one of the provisions of the most recent employment agreement, such as fraud or gross misconduct. |
| |
| (3) | | Termination on the basis ofDisabilityassumes the disability prevents the executive from successfully fulfilling the duties of his position. This calculation assumes the qualifying event occurred on or before June 1, 2006, that SPR gave 30 days notice of termination, and the termination was effective December 31, 2006. Also for purposes of this calculation, it has been assumed that the CEO does not exercise the appeal provision of the disability determination process. |
| |
| (4) | | Termination on the basis ofRetirementassumes that the executive voluntarily resigned and is eligible to retire effective December 31, 2006. |
| |
| (5) | | Termination Without Causerequires SPR to decide to terminate the employment relationship without notice or providing a reason. |
| |
| (6) | | TheChange-in-Controlcalculation assumes that the executive was terminated at some point following a corporate change-in-control with an effective date of December 31, 2006. |
| |
| (7) | | Cash Severance is defined as all those payments owed or owing to the executive which are payable in cash under the different termination scenarios. While different payments may be paid in a lump sum or over a period of time, for the purpose of these calculations, the payments are assumed to be made in a lump sum within five days of the termination date. In addition, it is assumed that all accrued and unused vacation time for 2006 has been either used or paid, and all salary has been paid through the last day of the year. |
| |
| (8) | | The value of Mr. Higgins’ Cash Severance following a Voluntary Termination has been set at 1.5 times his annual base salary and target annual bonus award. As per footnote 1, by agreement, Mr. Higgins is eligible for continued salary payments through June 1, 2008, if he were to voluntarily resign with the Board’s Consent effective December 31, 2006. For all other executives, the value is calculated based on the formula of one times annual base salary. |
| |
| (9) | | In relation to the Cash Severance for Death, Disability or For Cause, the amount represents the executive’s pro-rata portion of his annual incentive award, which for 2006 had a performance period end date of December 31, 2006. Therefore, the payment of the annual incentive award would be earned but unpaid on December 31, 2006, provided any annual incentive performance measures were fulfilled. For purposes of this calculation, it is assumed the executive fulfilled the performance measures at “target” in relation to any annual incentive award. |
| |
| (10) | | The value of the Cash Severance for Termination without Cause represents one-time base annual earnings plus target incentive award. |
| |
| (11) | | The value of the Cash Severance for termination following a Change-in-Control, represents two times base earnings plus target annual bonus award, as per Mr. Higgins’ most recent employment agreement. For all other named executive officers the values represent three times the annual base earnings plus the target annual bonus award. |
| |
| (12) | | Equity awards are valued based on the trading price of SPR’s common stock at close of business on December 31, 2006 of $16.83. In addition, the calculations reflect any provisions in the employment or change-in-control agreements, in regard to accelerated vesting of outstanding performance or other share awards, as well as the immediate right to exercise any outstanding and unvested stock options. The values are based on the assumption that any unvested portion of performance shares would have been vested had the performance cycle not been truncated. Also, any pro-rata calculations are based on the initial grant date from the start of the performance cycle through December 31, 2006. |
| |
| (13) | | The value of any retirement benefits is calculated as the amount of any projected single life annuity for one year at the executive’s normal retirement, or the first date he would be eligible to receive an unreduced benefit. The value shown reflects the amount of any benefit accrued as of December 31, 2006, and assumes the executive voluntarily terminates employment on that date to retire. The following assumptions were listed for this calculation: |
| | | | |
| | i. | | Annuity conversion interest rate was 4.73% for 2006. |
| | ii. | | The mortality table used for lump sum conversions was GAR 94 Unisex. |
| | iii. | | Retirement age was assumed to be the greater of age 55 and current age. |
| | |
| |
| (14) | | The value of the health and welfare benefits to be provided to an executive and his family, if appropriate, is based on the value of his current elections prior to termination. The calculation assumes no change in benefit elections over the span of any continuation period. For each of the named |
196
| | |
| | | executives, except Mr. Higgins, the opportunity to continue in the health program, at the full cost and expense of SPR, beyond employment, is available for up to 36 months following a change-in-control. Mr. Higgins is only eligible for an additional 24 months following a change-in-control, as per his most recent employment agreement. However, Mr. Higgins is eligible for continued participation through June 1, 2008, provided he voluntarily resigns with the Board’s consent, and in the event of termination without cause, Mr. Higgins is eligible for continued coverage for up to 36 months. |
| |
| (15) | | Mr. Higgins is the only named executive who is eligible for a gross-up of any severance payments following a change-in-control, based on calculations for parachute payments. All of the other executives’ severance payments are subject to reduction in the event the payment exceeds the threshold for parachute payments, set by IRC Section 280(g), which is defined as 2.99 times his 5 year average W-2 earnings for the 5 years immediately prior to termination. For purposes of these calculations, these values represent the maximum amount payable to each executive which would then be subject to reduction at the time of termination. |
| |
| (16) | | The Lump Sum Pension Service Equivalent is based on the provisions of each named executive’s employment or change-in-control agreement, which provides for a lump sum cash payment equal to the actuarial equivalent of three additional years of service, calculated from the date of termination, under all pension plans. In the case of Mr. Higgins, the value of this benefit is equal to zero since any grant for additional years of service under the plan, would not enhance his already accrued and vested benefit based on his current age and eligibility to retire. |
| |
| (17) | | In addition, each of the named executives would be eligible to receive: |
| | a. | | All fully vested amounts, which might be distributable consistent with the law, under SPR’s Non-qualified deferred compensation program, as presented in the “Non-Qualified Deferred Compensation” table |
| |
| | b. | | All fully vested amounts under SPR’s 401(k) defined contribution plan, which all employees participate in; the 2006 contribution for each named executive is included in the “Summary Compensation Table”. |
| | |
| |
| (18) | | Each named executive officer is covered by SPR’s Basic Life Insurance Program through CIGNA (1.5 times salary), and an Executive Life Insurance Program through Paragon with benefits payable to a designated beneficiary in the event of death ranging from $400,000 to $500,000. In addition to the basic amounts, SPR provides for accidental death and dismemberment coverage (1.5 times salary) and business travel accident insurance of $1,000,000 for each of the named executive officers with the exception of Mr. Higgins. In regard to Mr. Higgins, SPR contracts directly with CIGNA and Paragon to provide coverage and pays the premium on a policy with Pacific Life Insurance Company as well as a policy administered by M. Benefits Solutions. For the purpose of these calculations the qualifying event for each named executive is assumed to be for natural causes at December 31, 2006, and not as part of any business travel or accident. |
| |
| (19) | | This total includes values for annuities that were calculated for retirement benefits that are payable monthly over a period of time, that may or may not be realized at the values disclosed. |
197
NON-QUALIFIED DEFERRED COMPENSATION
The following table shows the 2006 activity and ending balances for each of the named executive officers in the SPR non-qualified deferred compensation plan. This plan is generally described in the Compensation Discussion and Analysis section of this note.
NON-QUALIFIED DEFERRED COMPENSATION
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Aggregate | | | | |
| | | Executive | | | Registrant | | | | | | | Withdrawals/ | | | | |
| | | Contributions in | | | Contribution in | | | Aggregate | | | Distributions in | | | Aggregate Balance | |
| | | Last Fiscal Year | | | Last Fiscal Year | | | Earnings in Last | | | Last Fiscal Year | | | at Last Fiscal Year- | |
| Name | | ($) | | | ($) | | | Fiscal Year ($) | | | ($) | | | End ($) | |
| Walter M. Higgins | | | 42,175 | | | | — | | | | 3,576 | | | | — | | | | 45,751 | |
| | | | | | | | | | | | | | | | | | | | | |
| Michael W. Yackira | | | 18,000 | | | | — | | | | 4,724 | | | | — | | | | 38,442 | |
| | | | | | | | | | | | | | | | | | | | | |
| Paul J. Kaleta | | | 5,004 | | | | — | | | | 72 | | | | — | | | | 5,075 | |
| | | | | | | | | | | | | | | | | | | | | |
| Roberto R. Denis | | | 8,190 | | | | — | | | | 584 | | | | — | | | | 8,774 | |
| | | | | | | | | | | | | | | | | | | | | |
| Jeffrey L. Ceccarelli | | | 12,900 | | | | — | | | | 1,033 | | | | — | | | | 13,933 | |
The 2006 Registrant Contribution will be made in early 2007.
2006 COMPENSATION OF NON-EMPLOYEE DIRECTORS
The total 2006 compensation of our Non-Employee Directors is shown in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Change in | | | | |
| | | Fees | | | | | | | | | | | | | | Pension Value | | | | |
| | | Earned or | | | | | | | | | | Non-Equity | | and Nonqualified | | | | |
| | | Paid in | | Stock | | Option | | Incentive Plan | | Deferred | | All Other | | |
| | | Cash | | Awards | | Awards | | Compensation | | Compensation | | Compensation | | Total |
| Name | | ($) | | ($) | | ($) | | ($) | | Earnings | | ($) | | ($) |
| |
| Mr. Anderson | | $ | 50,809 | | | $ | 35,000 | | | | — | | | | — | | | | — | | | | — | | | $ | 85,809 | |
| Ms. Coleman | | | 43,609 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 78,609 | |
| Ms. Corbin | | | 46,609 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 81,609 | |
| Mr. Day* (1) | | | 39,200 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 74,200 | |
| Mr. Donnelley* | | | 35,513 | | | | 57,000 | | | | — | | | | — | | | | — | | | | — | | | | 92,513 | |
| Mr. Herbst * | | | 45,809 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 80,809 | |
| Mr. O’Reilly * (1) | | | 24,800 | | | | 57,000 | | | | — | | | | — | | | | — | | | | — | | | | 81,800 | |
| Mr. Satre * (1) | | | 39,800 | | | | 57,000 | | | | — | | | | — | | | | — | | | | — | | | | 96,800 | |
| Mr. Snyder (1) | | | 56,200 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 91,200 | |
| Mr. Turner* (1) | | | 57,200 | | | | 35,000 | | | | — | | | | — | | | | — | | | | — | | | | 92,200 | |
| | |
| * | | Chair of Committee |
| |
| (1) | | The Director elected to defer payment of the stock award until such time as he is no longer a Director of SPR, although the receipt of the stock award is reflected in the Stock Awards column. |
DIRECTOR COMPENSATION
Each non-employee director is paid an annual retainer of $57,000. In keeping with the Board’s policy to tie management and director compensation to overall company performance and to increase director share ownership, SPR’s Non-Employee Director Stock Plan (“Plan”) requires that a minimum of $35,000 of the annual retainer for each non-employee director be paid in common stock of SPR. In accordance with the terms of the Plan, several non-employee directors regularly elect to receive an even greater percentage in stock. The reason for instituting a minimum amount of annual retainer that non-employee directors must be paid in SPR Stock is to ensure that all non-employee directors will hold a minimum of $100,000 worth of SPR Stock after their first three-year term in office.
In addition to the annual retainer, non-employee directors of SPR and its subsidiaries are paid $1,200 for each Board or Committee meeting attended (other than Audit Committee meetings, addressed below), not to exceed two meeting fees per day regardless of the number of meetings attended. Members of the Audit Committee are paid $1,500 per meeting of the Audit Committee attended. Non-employee directors also receive a full or partial fee (depending on distance) for travel to attend meetings away from the director’s home city. In consideration of their additional responsibility and time commitments, non-employee directors serving as Committee Chairpersons are also paid an additional $1,000 quarterly, except for the Audit Committee Chair, who receives $2,500 quarterly in consideration for the considerable duties now imposed by that office.
198
SPR’s Retirement Plan for Outside Directors, adopted March 6, 1987, was terminated on June 25, 1996. The actuarial value of the vested benefit as of May 20, 1996, for each director was converted into “phantom stock” of SPR at its fair market value on that day. The “phantom stock” is held in an account to be paid at the time of the non-employee director’s departure from the Board, either in stock or cash at the discretion of the Board. All “phantom stock” earns dividends at the same rate as listed company common stock from the date of conversion and is deemed reinvested in additional shares at the price of the stock on the dividend payment date.
BOARD AND COMMITTEE MEETINGS
The Board of Directors maintains the following committees: Audit; Compensation; Corporate and Civic Responsibility; Nominating and Governance; and Planning and Finance. The Board also establishes ad hoc committees for specific projects when required.
The Audit Committee was established in July 1992 to review and confer with SPR’s independent auditors and to review its internal auditing program and procedures and its financial statements to ensure that SPR’s operations and financial reporting are in compliance with all applicable laws, regulations, and SPR policies. The directors presently serving on the Audit Committee, all of whom are “independent,” are Mr. Turner (Chair), Ms. Corbin, and Messrs. Satre and Snyder. The Audit Committee met 8 times in 2006. The membership and structure of the Audit Committee and its governing documents satisfy all requirements of the SEC and the NYSE.
The Compensation Committee, formerly called the Human Resources Committee, was formed in July 1999 and assumed the duties of a pre-existing Compensation and Organization Committee, which was originally formed in 1991. This Committee reviews director and executive performance, and reviews and recommends to the Board any changes in fees for directors and compensation for all officers of SPR. The Committee also oversees SPR’s pension and 401(k) benefit plans and monitors and oversees the appointment and discharge of plan money managers. It also reviews and discharges the fiduciary duties delegated by the Board to the Committee under SPR’s benefit plans. The Committee’s charter is posted on SPR’s website atwww.sierrapacificresources.com. The directors presently serving on the Compensation Committee are Mr. Donnelley (Chair), Ms. Coleman, and Messrs. Anderson and Day. The Compensation Committee met five times in 2006. All members of the Compensation Committee are independent as defined in Sections 303A of the New York Stock Exchange Listed Company Manual. No member of the Committee has any relationship with SPR that might interfere with the exercise of independent judgment or overall independence from management of SPR.
The Corporate and Civic Responsibility Committee was formed in July 1999 and, among other things, assumed the duties of the previous Environmental Committee, which was established in 1992. Among its other duties, this Committee oversees the SPR’s environmental policy and performance and provides guidance to executive management on environmental issues as well as overseeing all other aspects of corporate compliance with applicable law, business standards of conduct, corporate giving, and legislative and governmental affairs. The directors presently serving on the Corporate and Civic Responsibility Committee are Mr. Day (Chair) and Messrs. Anderson, Higgins, Satre, Snyder and Turner. The Corporate and Civic Responsibility Committee met three times in 2006.
The Nominating and Governance Committee, which was formed in August 2003, assumed certain duties formerly discharged by the Human Resources Committee. All members of the Nominating and Governance Committee are independent as defined in Section 303A of the New York Stock Exchange Listed Company Manual. No member of the Committee has any relationship with SPR that might interfere with the exercise of independent judgment or overall independence from management of SPR. This Committee considers nominations to the Board of Directors as recommended by or from a variety of sources, including Board members, senior management, community and business leaders, and search agencies to whom it has paid fees in the past and may continue to pay a fee. Although the Board has not established any absolute prerequisites for membership, in seeking new directors the Board values diversity, general business acumen, knowledge, and experience, specialized knowledge or experience in our industry, and general familiarity with finance and accounting. The Committee also considers candidates recommended by Stockholders. To be considered, nominations must be submitted in writing to the Committee in care of the Secretary of SPR within the time frame fixed by SPR’s Bylaws as reported in this proxy. Any stockholder submitting a recommendation should include as much information as he or she deems appropriate for consideration by the Committee. The Secretary will then submit the recommendation to the Committee for consideration at or before the time the Committee makes its recommendations to the Board for nominees for the next Annual Meeting of Stockholders. The Committee also recommends appointments of Directors to Board Committees and reviews plans for management succession. Pursuant to New York Stock Exchange rules, the Committee’s Charter and SPR’s Code of Business Conduct, and Corporate Governance Guidelines are posted on SPR’s website atwww.sierrapacificresources.com. The directors presently serving on the Nominating and Governance Committee are Mr. Herbst (Chair), Ms. Corbin and Messrs. Anderson, Satre, and Snyder. The Nominating and Governance Committee met five times in 2006. For the 2007 Annual Meeting, no institutional stockholder or group of stockholders put forward any nominees for director.
The Planning and Finance Committee was formed in July 1999. This Committee reviews and recommends the long-range goals of the parent and subsidiary companies to the Board, and the type and amount of financing necessary to meet those goals. The directors presently serving on the Planning and Finance Committee are Mr. O’Reilly (Chair), Ms. Coleman, and Messrs. Donnelly, Herbst and Higgins. The Planning and Finance Committee met four times in 2006.
There were four regularly scheduled and three special meetings of the Board of Directors during 2006. Each member of the Board attended at least 75% of all meetings of the Board of Directors and of all Committees which he or she served, except for Mr. Day. Non-management directors meet at regularly scheduled and unscheduled Executive Sessions during Board meetings without
199
management present. James Donnelley, an independent director, was selected by the Board to preside over these Executive Sessions.
COMPENSATION COMMITTEE
Compensation Committee Interlocks and Insider Participation
During 2006, Ms. Coleman, and Messrs. Anderson, Donnelley and Day served as members of the Compensation Committee. None of them were at any time during 2006, or before then, an officer or employee of SPR or any of its subsidiaries. None of them had any relationships with SPR or any of its subsidiaries during 2006 that was required to be disclosed under Item 404 of Regulation S-K under the Exchange Act.
None of our executive officers or any of our subsidiaries served as a director or member of the Compensation Committee (or other committee serving an equivalent function) of any other entity, whose executive officer served on our Board of Directors or any of our subsidiaries or the Compensation Committee.
Compensation Committee Report
The Compensation Committee of the Board of Directors of SPR oversees SPR’s compensation program on behalf of the Board. In fulfilling its oversight responsibilities, the Compensation Committee reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
In reliance on the review and discussions referred to above, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and SPR’s Proxy Statement to be filed in connection with the SPR’s 2007 Annual Meeting of stockholders, each of which will be filed with the SEC.
| | | | | |
| | COMPENSATION COMMITTEE
James R. Donnelley,Chair
Joseph B. Anderson, Jr.
Mary Lee Coleman
Theodore J. Day
| |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All of the common stock of NPC and SPPC is owned by SPR.
Information regarding security ownership of SPR common stock by certain beneficial owners and management is hereby incorporated by reference from SPR’s definitive proxy statement to be filed in connection with the annual meeting of shareholders to be held on May 7, 2007.
200
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Related Party Transactions
The son of John F. O’Reilly, a member of SPR’s Board of Directors, is associated with the Waller Law Group, which is acting as co-counsel for SPR and the Utilities in two significant litigation matters. Mr. O’Reilly’s son is not working on either matter, and neither Mr. O’Reilly nor his son receives any compensation or other benefits from SPR or the Utilities related to these matters. On the basis of this relationship, however, the Board of Directors has not included Mr. O’Reilly among those directors considered to be independent.
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 Utilities according to each Utility’s usage. For fiscal year 2006, the costs for such services allocated to NPC was $2.2 million and the costs of such services allocated to SPPC was $1.7 million. 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, subject to any applicable regulatory restrictions and restrictions under SPR’s or the Utilities’ financing agreements.
Review, Approval or Ratification of Transactions with Related Parties
In accordance with SPR’s Business Conduct Code “The Power of Integrity—A Guide to Business Conduct” (the “Business Conduct Code”), all transactions and relationships between and among the Utilities and their non–utility affiliates, including SPR, are to be guided by and conducted in accordance with all statutes and rules enforced by the PUCN and the California Public Utilities Commission, FERC, and the related compliance plans of the Utilities. Employees must ensure that inter-company transactions and related activities are permitted, properly documented and meet applicable regulations. Moreover, SPR and the Utilities must comply with FERC Order No. 2004 and all subsequent versions. This requires that employees engaged in transmission system operations act independently of any company employees engaged in wholesale merchant functions so as not to benefit an affiliate in the wholesale purchase and sale of power or natural gas. All directors, officers, employees, consultants and contractors of SPR and the Utilities are expected to abide by these standards of conduct and every supervisor and manager is responsible for helping employees understand and comply with these principles. “The Power of Integrity—A Guide to Business Conduct” is set forth in writing on SPR’s website atwww.sierrapacificresources.com.
The Ethics and Compliance Office oversees company compliance with laws, regulations and policies, self–governance activities, compliance risk assessment, integrity and compliance training, and monitors and reports on compliance efforts. The Ethics and Compliance Office is responsible for managing all integrity and compliance programs, including managing the investigation process and reviewing results of investigations. The Ethics and Compliance Office is also responsible for applying the business conduct rules on a consistent basis and ensuring that employee concerns are addressed in a fair, unbiased and timely manner.
The Code of Ethics for the CEO, CFO and Controller (the “Code of Ethics”) is set forth in writing on SPR’s website atwww.sierrapacificresources.com. This Code of Ethics requires the CEO, CFO and Controller to exhibit and promote the highest standards of honest and ethical conduct at SPR and the Utilities through the establishment and operation of policies and procedures that, among other things, prohibit and eliminate the appearance or occurrence of conflicts between what is in the best interest of SPR and the Utilities and what could result in material personal gain for a member of the financial organization, including the CEO, CFO and Controller.
In accordance with the charter of SPR’s audit committee, the audit committee is responsible for reviewing reports and disclosures of insider and affiliated party transactions and periodically reviewing the Code of Ethics to determine whether it complies with applicable rules and regulations and whether management has established a system to enforce the code. The audit committee is also responsible for advising the Board with respect to SPR’s policies and procedures regarding compliance with applicable laws and regulations in connection with insider and affiliated party transactions as well as compliance with the Business Conduct Code. A copy of the audit committee charter is set forth in writing on SPR’s website atwww.sierrapacificresources.com.
201
BOARD INDEPENDENCE AND CORPORATE GOVERNANCE DISCLOSURE
Director Independence
The Board has determined that each of the following directors of SPR meet the independence requirements under the New York Stock Exchange’s listing standards: Mary Lee Coleman, Theodore J. Day, Jerry E. Herbst, Donald D. Snyder, Clyde T. Turner, Philip G. Satre, Krestine M. Corbin, Joseph B. Anderson, Jr., James R. Donnelley and Brian J. Kennedy.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table summarizes the aggregate fees billed to SPR, NPC and SPPC by our independent registered public accounting firm, Deloitte and Touche LLP.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | NPC | | | SPPC | | | SPR Consolidated (d) | |
| | | 2006 | | | 2005 | | | 2006 | | | 2005 | | | 2006 | | | 2005 | |
| Audit Fees (a) | | $ | 1,403,150 | | | $ | 1,359,499 | | | $ | 1,328,825 | | | $ | 1,295,521 | | | $ | 3,016,025 | | | $ | 3,270,514 | |
| Audit Related Fees (b) | | | 10,000 | | | | — | | | | 10,500 | | | | 36,308 | | | | 20,500 | | | | 94,693 | |
| All Other Fees (c) | | | — | | | | — | | | | — | | | | — | | | | 75,000 | | | | 29,560 | |
| | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,413,150 | | | $ | 1,359,499 | | | $ | 1,339,325 | | | $ | 1,331,829 | | | $ | 3,111,525 | | | $ | 3,394,767 | |
| | | | | | | | | | | | | | | | | | | |
| | |
| (a) | | Fees for audit services billed in 2006 and 2005 consisted of: |
| | § | | Audit of the companies financial statements. |
| |
| | § | | Reviews of the companies quarterly financial statements. |
| |
| | § | | Comfort letters, regulatory audits, consents and other services related to SEC matters. |
| (b) | | Fees for audit related services billed in 2006 and 2005 consisted of: |
| | § | | Sarbanes-Oxley Act, Section 404 advisory services. |
| |
| | § | | Agreed upon procedures. |
| (c) | | Fees for all other services billed in 2006 and 2005 consisted of permitted non-audit services, such as: |
| (d) | | 2005 Audit fees have been adjusted from information previously presented to reflect fees for audit services relating to the audit of the 2005 financial statements, including internal controls over financial reporting for SPR, billed subsequent to the filing of the 2006 proxy statement. |
In considering the nature of the services provided by the independent registered public accounting firm, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with the independent auditor and management to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.
Pre-Approval Policy
The services performed by Deloitte and Touche LLP, in 2006 were pre-approved on February 26, 2006 meeting by the Audit Committee in accordance with the pre-approval policy and procedures adopted by the Audit Committee. This policy describes the permitted audit, audit-related, tax, and other services (collectively, the “Disclosure Categories”) that Deloitte and Touche may perform. The policy requires that prior to the beginning of each fiscal year, a description of the services (the “Service List”) expected to be performed by Deloitte and Touche in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval.
Any requests for audit, audit related, tax, and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings. However, the authority to grant specific pre-approval between meetings, as necessary, has been delegated to the Chairman of the Audit Committee. Under the policy, the Chairman must update the Audit Committee at the next regularly scheduled meeting of any services that were granted specific pre-approval.
In addition, although not required by the rules and regulations of the SEC, the Audit Committee (generally) requests a range of fees associated with each proposed service on the Service List and any services that were not originally included on the Service List. Providing a range of fees for a service incorporates appropriate oversight and control of the independent auditor relationship, while permitting the Company to receive immediate assistance from the independent auditor when time is of the essence.
202
On a quarterly basis, the Audit Committee reviews the status of services and fees incurred year-to-date against the original Service List and the forecast of remaining services and fees for the fiscal year.
The policy contains ade minimisprovision that operates to provide retroactive approval for small immaterial and permissible non-audit services under certain circumstances. The provision allows for the pre-approval requirement to be waived if all of the following criteria are met:
| | 1. | | The service is not an audit, review or other attest service; |
| |
| | 2. | | The aggregate amount of all such services provided under this provision does not exceed the lesser of $50,000 or five percent of total fees paid to the independent auditor in a given fiscal year; |
| |
| | 3. | | Such services were not recognized at the time of the engagement to be non-audit services; |
| |
| | 4. | | Such services are promptly brought to the attention of the Audit Committee and approved by the Audit Committee or its designee; and |
| |
| | 5. | | The service and fee are specifically disclosed in the Proxy Statement as meeting thede minimisrequirements. |
During 2006, fees for audit related services, tax services and all other fees were pre-approved by the Audit Committee or Chairman of the Audit Committee.
203
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements, Financial Statement Schedules and Exhibits
| | | | | | | | | |
| | | | | | | Page | |
| | 1. | | | Financial Statements: | | | | |
| | | | | | | | | |
| | | | | Reports of Independent Registered Public Accounting Firm | | | 95 | |
| | | | | | | | | |
| | | | | Sierra Pacific Resources: | | | | |
| | | | | Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 98 | |
| | | | | Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 99 | |
| | | | | Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004 | | | 100 | |
| | | | | Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 101 | |
| | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 102 | |
| | | | | Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 103 | |
| | | | | | | | | |
| | | | | Nevada Power Company: | | | | |
| | | | | Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 105 | |
| | | | | Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 106 | |
| | | | | Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004 | | | 107 | |
| | | | | Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 108 | |
| | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 109 | |
| | | | | Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 110 | |
| | | | | | | | | |
| | | | | Sierra Pacific Power Company: | | | | |
| | | | | Consolidated Balance Sheets as of December 31, 2006 and 2005 | | | 111 | |
| | | | | Consolidated Income Statements for the Years Ended December 31, 2006, 2005 and 2004 | | | 112 | |
| | | | | Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004 | | | 113 | |
| | | | | Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2006, 2005 and 2004 | | | 114 | |
| | | | | Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 | | | 115 | |
| | | | | Consolidated Statements of Capitalization as of December 31, 2006 and 2005 | | | 116 | |
| | | | | Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company | | | 117 | |
| | | | | | | | | |
| | 2. | | | Financial Statement Schedules: | | | | |
| | | | | Schedule I – Condensed Financial Statements of Sierra Pacific Resources | | | 206 | |
| | | | | Schedule II – Consolidated Valuation and Qualifying Accounts | | | 207 | |
| | | | | | | | | |
| | | | | 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 209 to 218. | | | | |
204
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 | |
| | February 28, 2007 | |
| |
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 28th day of February, 2007.
| | | | | | | | | |
/s/ | | William D. Rogers William D. Rogers | | | | /s/ | | John E. Brown John E. Brown |
| | | Chief Financial Officer (Principal Financial Officer) | | | | | | Controller (Principal Accounting Officer) |
| | | | | | | | | |
/s/ | | Mary Lee Coleman Mary Lee Coleman | | | | /s/ | | Jerry E. Herbst Jerry E. Herbst |
| | | Director | | | | | | Director |
| | | | | | | | | |
/s/ | | Krestine M. Corbin Krestine M. Corbin | | | | /s/ | | John F. O’Reilly John F. O’Reilly |
| | | Director | | | | | | Director |
| | | | | | | | | |
/s/ | | Theodore J. Day Theodore J. Day | | | | /s/ | | Clyde T. Turner Clyde T. Turner |
| | | Director | | | | | | Director |
| | | | | | | | | |
/s/ | | James R. Donnelley James R. Donnelley | | | | /s/ | | Joseph B. Anderson, Jr. Joseph B. Anderson, Jr. |
| | | Director | | | | | | Director |
| | | | | | | | | |
/s/ | | Philip G. Satre Philip G. Satre | | | | /s/ | | Donald D. Snyder. Donald D. Snyder |
| | | Director | | | | | | Director |
| | | | | | | | | |
/s/ | | Michael W. Yackira Michael W. Yackira | | | | /s/ | | Brian J. Kennedy Brian J. Kennedy |
| | | Director | | | | | | Director |
205
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
ASSETS | | | | | | | | |
| Investments and other property, net (Note 4) | | $ | 3,045,872 | | | $ | 2,539,689 | |
| | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | | 25,206 | | | | 35,185 | |
| Accounts receivable less allowance for uncollectible accounts: | | | | | | | | |
| 2006-$0 | | | 1,755 | | | | — | |
| Dividends receivable from subsidiary | | | 20,208 | | | | 321 | |
| Materials, supplies and fuel, at average cost | | | 13 | | | | 2 | |
| Deferred income taxes | | | 138 | | | | — | |
| Other | | | 420 | | | | 946 | |
| | | | | | | |
| | | | 47,740 | | | | 36,454 | |
| | | | | | | |
| | | | | | | | | |
| Deferred Charges and Other Assets: | | | | | | | | |
| Goodwill (Note 18) | | | 469 | | | | 22,877 | |
| Regulatory asset for pension plans | | | 2,906 | | | | — | |
| Unamortized debt issuance costs | | | 10,269 | | | | 13,545 | |
| Deferred income tax benefit | | | 105,010 | | | | 148,451 | |
| Other | | | 1,611 | | | | 68,240 | |
| | | | | | | |
| | | | 120,265 | | | | 253,113 | |
| | | | | | | |
TOTAL ASSETS | | $ | 3,213,877 | | | $ | 2,829,256 | |
| | | | | | | |
CAPITALIZATION AND LIABILITIES | | | | | | | | |
| Capitalization: | | | | | | | | |
| Common shareholders’ equity | | $ | 2,622,297 | | | $ | 2,060,154 | |
| Long-term debt | | | 550,545 | | | | 661,255 | |
| | | | | | | |
| | | | 3,172,842 | | | | 2,721,409 | |
| | | | | | | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Accounts payable | | | 8,581 | | | | 75,723 | |
| Accrued interest | | | 12,216 | | | | 14,561 | |
| Accrued salaries and benefits | | | 2,948 | | | | 2,617 | |
| Deferred income taxes | | | — | | | | 144 | |
| Accrued taxes | | | 212 | | | | 182 | |
| | | | | | | |
| | | | 23,957 | | | | 93,227 | |
| | | | | | | |
| | | | | | | | | |
| Commitments and Contingencies (Note 13) | | | | | | | | |
| | | | | | | | | |
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accrued retirement benefits | | | 11,691 | | | | 11,124 | |
| Other | | | 5,387 | | | | 3,496 | |
| | | | | | | |
| | | | 17,078 | | | | 14,620 | |
| | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 3,213,877 | | | $ | 2,829,256 | |
| | | | | | | |
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED INCOME STATEMENTS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
OPERATING EXPENSES: | | | | | | | | | | | | |
| Operation: | | | | | | | | | | | | |
| Impairment of goodwill | | $ | — | | | $ | — | | | $ | 11,695 | |
| Other | | | 5,952 | | | | 19,006 | | | | 15,114 | |
| Taxes: | | | | | | | | | | | | |
| Income taxes (benefits) | | | (23,595 | ) | | | (33,078 | ) | | | (39,332 | ) |
| Other than income | | | 172 | | | | 152 | | | | 132 | |
| | | | | | | | | | |
| | | | (17,471 | ) | | | (13,920 | ) | | | (12,391 | ) |
| | | | | | | | | | |
OPERATING INCOME | | | 17,471 | | | | 13,920 | | | | 12,391 | |
| | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | |
| Early debt conversion fees | | | — | | | | (54,000 | ) | | | — | |
| Subsidiary earnings | | | 324,152 | | | | 185,777 | | | | 122,626 | |
| Other income | | | 4,236 | | | | 1,573 | | | | 545 | |
| Other expense | | | (6,595 | ) | | | (2,627 | ) | | | (1,379 | ) |
| Income (taxes) / benefits | | | 1,157 | | | | 18,799 | | | | 596 | |
| | | | | | | | | | |
| | | | 322,950 | | | | 149,522 | | | | 122,388 | |
| | | | | | | | | | |
| Total Income Before Interest Charges | | | 340,421 | | | | 163,442 | | | | 134,779 | |
| | | | | | | | | | | | | |
INTEREST CHARGES: | | | | | | | | | | | | |
| Long-term debt | | | 51,431 | | | | 74,323 | | | | 88,323 | |
| Other | | | 11,539 | | | | 6,882 | | | | 17,885 | |
| | | | | | | | | | |
| | | | 62,970 | | | | 81,205 | | | | 106,208 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Income Applicable to Common Stock | | $ | 277,451 | | | $ | 82,237 | | | $ | 28,571 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Amount per share basic and diluted — (Note 7) | | | | | | | | | | | | |
| Net Income Applicable to Common Stock | | $ | 1.33 | | | $ | 0.44 | | | $ | 0.16 | |
| | | | | | | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding — basic | | | 208,531,134 | | | | 185,548,314 | | | | 183,080,475 | |
| | | | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding — diluted | | | 209,020,896 | | | | 185,932,504 | | | | 183,400,303 | |
| | | | | | | | | | |
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
SCHEDULE 1
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
| | | | | | | | | | | | | |
| | | Year ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net Cash used by Operating Activities | | | (59,166 | ) | | | (147,993 | ) | | | (130,541 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Investments in subsidiaries and other property — net | | | (284,490 | ) | | | (231,182 | ) | | | (7,853 | ) |
| Dividends received from subsidiaries | | | 161,793 | | | | 65,819 | | | | 57,152 | |
| | | | | | | | | | |
| Net Cash used by Investing Activities | | | (122,697 | ) | | | (165,363 | ) | | | 49,299 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Change in restricted cash and investments | | | — | | | | 21,677 | | | | 21,652 | |
| Proceeds from issuance of long-term debt | | | — | | | | 220,211 | | | | 335,000 | |
| Retirement of long-term debt | | | (110,710 | ) | | | (132,949 | ) | | | (290,883 | ) |
| Sale of common stock, net of issuance cost | | | 282,594 | | | | 236,208 | | | | 3,488 | |
| | | | | | | | | | |
| Net Cash from Financing Activities | | | 171,884 | | | | 345,147 | | | | 69,257 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (9,979 | ) | | | 31,791 | | | | (11,985 | ) |
| Beginning Balance in Cash and Cash Equivalents | | | 35,185 | | | | 3,394 | | | | 15,379 | |
| | | | | | | | | | |
| Ending Balance in Cash and Cash Equivalents | | $ | 25,206 | | | $ | 35,185 | | | $ | 3,394 | |
| | | | | | | | | | |
206
Sierra Pacific Resources
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
| | | | | |
| | | Provision for Uncollectible Accounts | |
| Balance at January 1, 2004 | | $ | 44,917 | |
| Provision charged to income | | | 10,813 | |
| Amounts written off, less recoveries | | | (19,533 | ) |
| | | | |
| Balance at December 31, 2004 | | $ | 36,197 | |
| | | | |
| | | | | |
| Balance at January 1, 2005 | | $ | 36,197 | |
| Provision charged to income | | | 9,550 | |
| Amounts written off, less recoveries | | | (9,519 | ) |
| | | | |
| Balance at December 31, 2005 | | $ | 36,228 | |
| | | | |
| | | | | |
| Balance at January 1, 2006 | | $ | 36,228 | |
| Provision charged to income | | | 13,476 | |
| Amounts written off, less recoveries | | | (10,138 | ) |
| | | | |
| Balance at December 31, 2006 | | $ | 39,566 | |
| | | | |
Nevada Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
| | | | | |
| | | Provision for Uncollectible Accounts | |
| Balance at January 1, 2004 | | $ | 40,297 | |
| Provision charged to income | | | 7,794 | |
| Amounts written off, less recoveries | | | (17,190 | ) |
| | | | |
| Balance at December 31, 2004 | | $ | 30,901 | |
| | | | |
| | | | | |
| Balance at January 1, 2005 | | $ | 30,901 | |
| Provision charged to income | | | 6,966 | |
| Amounts written off, less recoveries | | | (7,481 | ) |
| | | | |
| Balance at December 31, 2005 | | $ | 30,386 | |
| | | | |
| | | | | |
| Balance at January 1, 2006 | | $ | 30,386 | |
| Provision charged to income | | | 10,795 | |
| Amounts written off, less recoveries | | | (8,347 | ) |
| | | | |
| Balance at December 31, 2006 | | $ | 32,834 | |
| | | | |
207
Sierra Pacific Power Company
Schedule II — Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2006, 2005 and 2004
(Dollars in Thousands)
| | | | | |
| | | Provision for Uncollectible Accounts | |
| Balance at January 1, 2004 | | $ | 4,620 | |
| Provision charged to income | | | 3,019 | |
| Amounts written off, less recoveries | | | (2,343 | ) |
| | | | |
| Balance at December 31, 2004 | | $ | 5,296 | |
| | | | |
| | | | | |
| Balance at January 1, 2005 | | $ | 5,296 | |
| Provision charged to income | | | 2,584 | |
| Amounts written off, less recoveries | | | (2,038 | ) |
| | | | |
| Balance at December 31, 2005 | | $ | 5,842 | |
| | | | |
| | | | | |
| Balance at January 1, 2006 | | $ | 5,842 | |
| Provision charged to income | | | 2,681 | |
| Amounts written off, less recoveries | | | (1,791 | ) |
| | | | |
| Balance at December 31, 2006 | | $ | 6,732 | |
| | | | |
208
2006 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 Pacific Energy 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
| | • | | Restated and Amended Articles of Incorporation of Sierra Pacific Resources, dated May 24, 2006 (filed as Exhibit 3.1 to Form 10-Q for quarter ended June 30, 2006). |
| |
| | • | | By-laws of Sierra Pacific Resources as amended through May 3, 2005 (filed as Exhibit 3.1 to Form 8-K filed May 9, 2005). |
Nevada Power Company
| | • | | 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). |
| |
| | • | | 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
| | • | | Restated Articles of Incorporation of Sierra Pacific Power Company dated October 25, 2006 (filed as Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2006). |
| |
| | • | | 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). |
| |
| | • | | Articles of Incorporation of Piñon Pine Corp., dated December 11, 1995 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995). |
| |
| | • | | Articles of Incorporation of Piñon Pine Investment Co., dated December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995). |
| |
| | • | | Agreement of Limited Liability Company of Piñon Pine Company, L.L.C., dated December 15, 1995, between Piñon Pine Corp., Piñon Pine Investment Co. and GPSF-B INC 1995 (filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995). |
| |
| | • | | 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
| | • | | Indenture between Sierra Pacific Resources and The Bank of New York, dated May 1, 2000, for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000). |
209
| | • | | Officers’ Certificate dated August 12, 2005, establishing the terms of Sierra Pacific Resources’ 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005). |
| |
| | • | | Form of Sierra Pacific Resources’ 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005). |
| |
| | • | | Officers’ Certificate dated June 14, 2005, establishing the terms of Sierra Pacific Resources’ 7.803% Senior Notes due 2007 (filed as Exhibit 99.1 to Form 8-K filed June 16, 2005). |
| |
| | • | | Indenture, dated March 19, 2004, between Sierra Pacific Resources and the Bank of New York, as Trustee, in connection with the issuance of 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004). |
| |
| | • | | Form of Sierra Pacific Resources’ 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004). |
Nevada Power Company
| | • | | General and Refunding Mortgage Indenture, dated 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). |
| |
| | • | | 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). |
| |
| | • | | 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.l(c) to Form 10-Q for the quarter ended June 30, 2001). |
| |
| | • | | 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). |
| |
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2003). |
| |
| | • | | Form of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2003). |
| |
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012 (filed as Exhibit 4.1 to Form 10-Q for quarter ended June 30, 2004). |
| |
| | • | | Form of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I due 2012 (filed as Exhibit 4.2 to Form 10-Q for quarter ended June 30, 2004). |
| |
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form 10-K filed for year ended December 31, 2005). |
| |
| | • | | Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31, 2005). |
210
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2005). |
| |
| | • | | Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(B) to Form 10-K for the year ended December 31, 2005). |
| |
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006. |
| |
| | • | | Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Appendix A to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006). |
| |
| | • | | Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Exhibit 4.7 to Form S-4 filed June 7, 2006). |
| |
| | • | | Form of 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (included in Exhibit 4.7) (filed as Appendix A to Exhibit 4.7 to Form S-4 filed June 7, 2006). |
Sierra Pacific Power Company
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | *(A) Second Supplemental Indenture, dated as of October 30, 2006, to subject additional properties of Sierra Pacific Power Company located in the State of California to the lien of the General and Refunding Mortgage Indenture and to correct defects in the original Indenture. |
| |
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2004). |
| |
| | • | | Form of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.5 to Form 10-Q for the quarter ended March 31, 2004). |
| |
| | • | | Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(E) to Form 10-K for the year ended December 31, 2004). |
211
| | • | | Form of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(F) to Form 10-K for the year ended December 31, 2004). |
| |
| | • | | Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006). |
| |
| | • | | Form of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006). |
| |
| | • | | 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 the year ended December 31, 1999). |
| |
| | • | | 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). |
| |
| | • | | 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). |
(10) Sierra Pacific Resources
| | • | | Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2003). |
| |
| | • | | Amendment to Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2006). |
| |
| | • | | Michael W. Yackira Employment Letter dated March 17, 2003 (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2002). |
| |
| | • | | Paul J. Kaleta Employment Letter dated January 9, 2006 (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2005). |
| |
| | • | | Stephen R. Wood Employment Letter dated June 29, 2004 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004). |
| |
| | • | | Roberto Denis Employment Letter dated July 11, 2003 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2003). |
| |
| | • | | Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Jeffrey L. Ceccarelli, Donald L. Shalmy, Michael W. Yackira, Roberto Denis, Stephen R. Wood and Paul J. Kaleta 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). |
| |
| | • | | Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Mary O. Simmons and John E. Brown 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). |
| |
| | • | | Sierra Pacific Resources’ 2004 Executive Long-Term Incentive Plan (filed as Appendix A to 2004 Proxy Statement). |
212
| | • | | Sierra Pacific Resources’ Non-Employee Director Stock Plan (filed as Exhibit 99.2 to Form S-8 dated December 13, 1999). |
| |
| | • | | Sierra Pacific Resources’ Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999). |
Nevada Power Company
| | • | | *(A) Lease, dated December 11, 2006, between Nevada Power Company as lessee and Beltway Business Park Warehouse No. 2, LLC as lessor, relating to Nevada Power Company’s South Operations Center facility. |
| |
| | • | | Second Amended and Restated Credit Agreement, dated as of November 4, 2005, among Nevada Power Company, Wachovia Bank, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to the Form 10-Q for the quarter ended September 30, 2005). |
| |
| | • | | Amendment and Consent, dated April 19, 2006, to the Second Amended and Restated Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2006). |
| |
| | • | | Financing Agreement between Clark County, Nevada and Nevada Power Company, dated August 1, 2006 (relating to Clark County, Nevada $39,500,000 Pollution Control Refund Revenue Bonds Series 2006) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2006). |
| |
| | • | | Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona $40,000,000 Pollution Control Corporation Refunding Revenue Bonds Series 2006A) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006). |
| |
| | • | | Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds Series 2006B) (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2006). |
| |
| | • | | Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company, dated June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000). |
| |
| | • | | Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company, dated June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year ended December 31, 2000). |
| |
| | • | | 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, for the year ended December 31, 1997). |
| |
| | • | | 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, for the year ended December 31, 1995). |
213
| | • | | 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, for the year ended December 31, 1995). |
| |
| | • | | 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. 1-1698, for the year ended December 31, 1995). |
| |
| | • | | 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, for the year ended December 31, 1995). |
| |
| | • | | 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, for the year ended December 31, 1992). |
| |
| | • | | 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, for the year ended December 31, 1992). |
| |
| | • | | Collective Bargaining Agreement dated as of February 1, 2005, effective through February 1, 2008, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2005). |
| |
| | • | | Engineering, Procurement and Construction Agreement dated October 13, 2004 between Nevada Power Company and Fluor Enterprises, Inc. and Exhibit A thereto (filed as Exhibit 10.3 and Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004). |
| |
| | • | | 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, for the year ended December 31, 1987). |
| |
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | 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 Porto S-7, File No. 2-56356). |
| |
| | • | | 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). |
214
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | Settlement Agreement dated December 19, 2003, between Nevada Power Company, Pinnacle West Energy Corporation and Southern Nevada Water Authority (filed as Exhibit 10(G) to the Form 10-K for the year ended December 31, 2003). |
| |
| | • | | 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, for the year ended December 31, 1983). |
Sierra Pacific Power Company
| | • | | Amended and Restated Credit Agreement, dated as of November 4, 2005 among Sierra Pacific Power Company, Wachovia Bank, National Association, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to the Form 10-Q for the quarter ended September 30, 2005). |
| |
| | • | | Amendment and Consent, dated April 19, 2006, to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2006). |
| |
| | • | | *(B) Financing Agreement dated November 1, 2006 between Humboldt County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Humboldt County, Nevada $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006). |
| |
| | • | | *(C) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $58,750,000 Gas Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A). |
| |
| | • | | *(D) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $75,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B). |
| |
| | • | | *(E) Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $84,800,000 Gas and Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C). |
| |
| | • | | 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 31, 2001). |
215
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | 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) b Form 10-K for the year ended December 31, 1999). |
| |
| | • | | Collective Bargaining Agreement dated January 1, 2003, effective through December 31, 2005 between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local No. 1245 (filed as Exhibit 10(J) to the Form 10-K for the year ended December 31, 2003). |
| |
| | • | | 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). |
| |
| | • | | 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 31, 2001). |
| |
| | • | | Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (confidential portions omitted and flied separately with lie Securities and Exchange Commission) (filed as Exhibit 5-GG to Registration No. 2-62476). |
| |
| | • | | 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). |
| |
| | • | | Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal Stores Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993). |
| |
| | • | | 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). |
| |
| | • | | 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). |
| |
| | • | | 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). |
216
Sierra Pacific Communications
| | • | | 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). |
| |
| | • | | Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Quest 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
| | • | | 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
| | • | | *(A) Statement regarding computation of Ratios of Earnings to Fixed Charges. |
Nevada Power Company
| | • | | *(B) Statement regarding computation of Ratios of Earnings to Fixed Charges. |
Sierra Pacific Power Company
| | • | | *(C) Statement regarding computation of Ratios of Earnings to Fixed Charges. |
(21) Sierra Pacific Resources
| | • | | 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 Water Development Company, a Nevada Corporation. |
| | | | Tuscarora Gas Pipeline Company, a Nevada Corporation. |
| | | | Tuscarora Gas Operating Company, a Nevada Corporation. |
Nevada Power Company
| | • | | Nevada Electric Investment Company, a Nevada Corporation. |
| | | | Commonsite, Inc., a Nevada Corporation. |
Sierra Pacific Power Company
| | • | | Piñon Pine Company, a Nevada Corporation. |
| | | | Piñon Pine Investment Company, a Nevada Corporation. |
| | | | Piñon Pine Investment Co. LLC, a Nevada Limited Liability Company. |
| | | | GPSF-B, a Delaware Corporation. |
| | | | SPPC Funding LLC, a Delaware Limited Liability Company. |
217
(23) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
| | • | | *(A) Consent of Independent Registered Public Accounting Firm in connection with 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 Form S-8, No. 333-72160 (Post-Effective Amendment to Registration) on Form S-3/A and Registration Statement No. 333-135752 (automatic shelf registration statement of securities of well-known seasoned issuers) on Form S-3. |
| | • | | *(B) Consent of Independent Registered Public Accounting Firm in connection with Nevada Power Company’s Registration Statement on Form S-3, No. 333-130189 (shelf registration statement). |
| | • | | *(C) Consent of Independent Registered Public Accounting Firm in connection with Sierra Pacific Power Company’s Registration Statement on Form S-3, No. 333-130191 (shelf registration statement). |
(31) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
| | • | | *(31.1) Annual Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(31.2) Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(31.3) Annual Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(31.4) Annual Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(31.5) Annual Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(31.6) Annual Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(32) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company
| | • | | *(32.1) Certification of Chief Executive Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(32.2) Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(32.3) Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(32.4) Certification of Chief Financial Officer of Sierra Pacific Resources Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(32.5) Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
| | • | | *(32.6) Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
218
