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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, 2002
Commission File Number 1-7850
| SOUTHWEST GAS CORPORATION | |||
| (Exact name of registrant as specified in its charter) | |||
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| California |
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88-0085720 | |
| (State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) | |
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| 5241 Spring Mountain Road |
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89193-8510 | |
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(Zip Code) | |
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| Registrant’s telephone number, including area code: (702) 876-7237 | |||
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| Securities registered pursuant to Section 12(b) of the Act: | |||
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| Title of each class |
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Name of each exchange on which registered | |
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| Common Stock, $1 par value |
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New York Stock Exchange, Inc. | |
| 9.125% Trust Originated Preferred Securities |
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New York Stock Exchange, Inc. | |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
| Yes x |
No o |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is an accelerated filer.
| Yes x |
No o |
Aggregate market value of the
voting stock held by nonaffiliates of the registrant:
$815,977,973 as of June 28, 2002
The number of shares outstanding of common stock:
Common Stock, $1 Par Value,
33,534,271 shares as of March 10, 2003
DOCUMENTS INCORPORATED BY REFERENCE
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Part Into Which Incorporated |
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| Annual Report to Shareholders for the Year Ended |
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Table of Contents
TABLE OF CONTENTS
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MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K |
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Table of Contents
| BUSINESS |
Southwest Gas Corporation (the Company) is incorporated, effective March 1931, under the laws of the State of California. The Company is comprised of two business segments: natural gas operations (Southwest or the natural gas operations segment) and construction services. Southwest is engaged in the business of purchasing, transporting, and distributing natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor and transporter of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.
Northern Pipeline Construction Co. (Northern or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor which provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
Financial information with respect to industry segments is included in Note 11 of the Notes to Consolidated Financial Statements which is included in the 2002 Annual Report to Shareholders and is incorporated herein by reference.
The Company maintains a Web site (www.swgas.com) for the benefit of shareholders, investors, customers, and other interested parties. The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports available, free of charge, through its Web site as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (SEC).
Southwest is subject to regulation by the Arizona Corporation Commission (ACC), the Public Utilities Commission of Nevada (PUCN), and the California Public Utilities Commission (CPUC). These commissions regulate public utility rates, practices, facilities, and service territories in their respective states. The CPUC also regulates the issuance of all securities by the Company, with the exception of short-term borrowings. Certain accounting practices, transmission facilities, and rates are subject to regulation by the Federal Energy Regulatory Commission (FERC).
Southwest purchases, transports, and distributes natural gas to 1,455,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. There were 58,000 customers added to the system during 2002.
The table below lists the percentage of operating margin (operating revenues less net cost of gas) by major customer class for the years indicated:
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Residential and |
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Other Sales |
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Transportation |
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| December 31, 2002 |
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83 |
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7 |
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10 |
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82 |
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8 |
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10 |
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| December 31, 2000 |
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84 |
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3 |
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13 |
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Southwest is not dependent on any one or a few customers to the extent that the loss of any one or several would have a significant adverse impact on earnings.
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Transportation of customer-secured gas to end-users accounted for 52 percent of total system throughput in 2002. Although the volumes were significant, these customers provide a much smaller proportionate share of operating margin. Customers who utilized this service transported 133 million dekatherms in 2002, 127 million dekatherms in 2001, and 148 million dekatherms in 2000. The changes between years primarily reflect shifts by a number of large commercial and industrial customers between transportation service and sales service.
The demand for natural gas is seasonal. Variability in weather from normal temperatures can materially impact results of operations. It is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in operations. Also, earnings for interim periods can be significantly affected by the timing of general rate relief.
Rates that Southwest is authorized to charge its distribution system customers are determined by the ACC, PUCN, and CPUC in general rate cases and are derived using rate base, cost of service, and cost of capital experienced in a historical test year, as adjusted in Arizona and Nevada, and projected for a future test year in California. The FERC regulates the northern Nevada transmission and liquefied natural gas (LNG) storage facilities of Paiute Pipeline Company (Paiute), a wholly owned subsidiary, and the rates it charges for transportation of gas directly to certain end-users and to various local distribution companies (LDCs). The LDCs transporting on the Paiute system are: Sierra Pacific Power Company (serving Reno and Sparks, Nevada), Avista Utilities (serving South Lake Tahoe, California), and Southwest Gas Corporation (serving Truckee and North Lake Tahoe, California and various locations throughout northern Nevada).
Rates charged to customers vary according to customer class and rate jurisdiction and are set at levels allowing for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt, preferred securities distributions, and a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, plus certain other assets such as working capital and inventories, less accumulated depreciation on utility plant in service, net deferred income tax liabilities, and certain other deductions. Rate schedules in all service areas contain purchased gas adjustment (PGA) clauses, which allow Southwest to file for rate adjustments as the cost of purchased gas changes. In Nevada, tariffs provide for annual adjustment dates for changes in purchased gas costs. In addition, Southwest may request to adjust rates more often, if market conditions warrant. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. In California, a monthly gas cost adjustment based on forecasted monthly prices is used to adjust rates. PGA rate changes affect cash flows but have no direct impact on profit margin. Filings to change rates in accordance with PGA clauses are subject to audit by the appropriate state regulatory commission staff. Information with respect to recent general rate cases and PGA filings is included in the Rates and Regulatory Proceedings section of Management’s Discussion and Analysis (MD&A) in the 2002 Annual Report to Shareholders.
The table below lists the docketed general rate filings last initiated and/or completed within each ratemaking area:
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Date Final Rates |
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| Arizona |
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General rate case |
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May 2000 |
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November 2001 |
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Northern and Southern |
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General rate case |
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February 2002 |
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Pending |
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Northern and Southern |
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General rate case |
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July 2001 |
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December 2001 |
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Paiute |
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General rate case |
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July 1996 |
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January 1997 |
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Deliveries of natural gas by Southwest are made under a priority system established by state regulatory commissions. The priority system is intended to ensure that the gas requirements of higher-priority customers, primarily residential customers and other customers who use 500 therms of gas per day or less, are fully satisfied on a daily basis before lower-priority customers, primarily electric utility and large industrial customers able to use alternative fuels, are provided any quantity of gas or capacity.
Demand for natural gas is greatly affected by temperature. On cold days, use of gas by residential and commercial customers may be as much as six times greater than on warm days because of increased use of gas for space heating. To fully satisfy this increased high-priority demand, gas is withdrawn from storage in certain service areas, or peaking supplies are purchased from suppliers. If necessary, service to interruptible lower-priority customers may be curtailed to provide the needed delivery system capacity. No curtailment occurred during the latest peak heating season. Southwest maintains no backlog on its orders for gas service.
Southwest is responsible for acquiring (purchasing) and arranging delivery of (transporting) natural gas to its system for all sales customers. Southwest believes that natural gas supplies and pipeline capacity for transportation will continue to be sufficient to meet market demands in its service territories.
The primary objective of Southwest with respect to gas supply is to ensure that adequate, as well as economical, supplies of natural gas are available from reliable sources. Gas is acquired from a wide variety of sources and a mix of purchase provisions, including spot market purchases and firm supplies with a variety of terms. During 2002, Southwest acquired gas supplies from 55 suppliers. This practice mitigates the risk of nonperformance by any one supplier.
Balancing reliable supply assurances with the associated costs results in a continually changing mix of purchase provisions within the supply portfolios. To address the unique requirements of its various market areas, Southwest assembles and administers separate natural gas supply portfolios for each of its jurisdictional areas. Firm and spot market natural gas purchases are made in a competitive bid environment. Southwest has experienced price volatility over the past several years, as the weighted average delivered cost of natural gas has ranged between 27 cents per therm in 1998 and 55 cents per therm in 2001. During 2002, Southwest paid 38 cents per therm. To mitigate customer exposure to market price volatility, Southwest continues to purchase a significant percentage of its forecasted annual normal weather requirements under firm, fixed-price arrangements that are secured periodically throughout the year.
The firm, fixed price arrangements are structured such that a stated volume of gas is required to be scheduled by Southwest and delivered by the supplier. If the gas is not needed by Southwest or cannot be procured by the supplier, the contract provides for fixed or market-based penalties to be paid by the non-performing party. In the event that demand on Southwest’s system is lower than expected, Southwest may have the opportunity to forego the purchase at a negotiated price in excess of the contracted price during periods of extreme price volatility. Any savings would reduce the overall cost of gas for the purchase period.
In managing its gas supply portfolio, Southwest does not currently utilize stand-alone derivative financial instruments, but may do so in the future to hedge against possible price increases. Any such change would be undertaken only with regulatory commission authorization to recover costs associated with these activities.
Gas supplies for the southern system of Southwest (Arizona, southern Nevada, and southern California properties) are primarily obtained from producing regions in Colorado and New Mexico (San Juan basin), Texas (Permian basin), and Rocky Mountain areas. For its northern system (northern Nevada and northern California properties), Southwest primarily obtains gas from Rocky Mountain producing areas and from Canada.
Southwest arranges for transportation of gas to its Arizona, Nevada, and California service territories through the pipeline systems of El Paso Natural Gas Company (El Paso), Kern River Gas Transmission Company (Kern River), Transwestern Pipeline Company, Northwest Pipeline Corporation, Paiute Pipeline Company, and Southern California Gas Company. Supply and pipeline capacity availability on both short- and long-term bases is continually monitored by
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Southwest to ensure the reliability of service to its customers. Southwest currently receives firm transportation service, both on a short- and long-term basis, for all of its service territories on the pipeline systems noted above, and also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise.
The Company believes that the current level of contracted firm interstate capacity is sufficient to serve each of the service territories. As the need arises to acquire additional capacity on one of the interstate pipeline transmission systems, primarily due to customer growth, Southwest considers available options to obtain the capacity, either through the use of firm contracts with a pipeline company or by purchasing capacity on the open market.
Southwest is dependent upon the El Paso pipeline system for the transportation of gas to virtually all of its Arizona service territories. Southwest receives transportation service from El Paso to its Arizona service territories under a full requirements contract. Under full requirements service, El Paso is obligated to transport all of a customer’s gas requirements each day, and the customer is obligated to have El Paso, and only El Paso, transport its requirements. Virtually all of El Paso’s customers in Arizona, New Mexico, and Texas are full requirements customers, while El Paso transports gas for its customers in California and Nevada subject to a specific maximum daily quantity, or contract demand limitation.
Since November 1999, the FERC has been examining capacity allocation issues on the El Paso system in several proceedings. During that time, the demand for natural gas on the El Paso system has risen primarily due to increased electric power generation fuel needs and market area growth. As a result, shippers have been increasingly experiencing reductions in the quantities of gas that they have been receiving from their daily transportation nominations. Many of the contract demand shippers have argued that the growth in the full requirements shippers’ volumes, coupled with El Paso’s failure to expand its system, have impaired their ability to receive all of the service to which they are entitled.
In May 2002, the FERC issued an order requiring that full requirements service be terminated as of November 2002. The order stated that full requirements transportation service agreements were to be converted to contract demand-type service agreements, and full requirements customers were to have an opportunity to negotiate an allocation of the system capacity determined by El Paso to be in excess of the capacity needed to fully serve the contract demand shippers. If the customers failed to agree upon an allocation, then the FERC would establish an allocation methodology for the customers. Following the order, various parties including Southwest submitted comments to the FERC seeking clarification or petitioning for rehearing.
In September 2002, the FERC issued an order of clarification for the May 2002 order. Among other things, the FERC determined that full requirements customers had not agreed upon an allocation of capacity and, therefore, the FERC established a methodology to allocate capacity among the full requirements customers. In addition, the FERC postponed conversion of full requirements service agreements to contract demand-type service agreements until May 2003. Because the proceeding is ongoing, further modifications to previous orders as well as additional rulings may occur.
Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. However, by delaying the effective date of the order, Southwest maintained sufficient capacity during the winter of 2002-2003 to serve its Arizona customers. Management also expects that sufficient capacity will be available to Southwest in the future, but additional costs may be incurred to acquire such capacity. It is anticipated that any additional costs will be collected from customers, principally through the PGA mechanism.
Electric utilities are the principal competitors of Southwest for the residential and small commercial markets throughout its service areas. Competition for space heating, general household, and small commercial energy needs generally occurs at the initial installation phase when the customer/builder typically makes the decision as to which type of equipment to install and operate. The customer will generally continue to use the chosen energy source for the life of the equipment. As a result of its success in these markets, Southwest has experienced consistent growth among the residential and small commercial customer classes.
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Unlike residential and small commercial customers, certain large commercial, industrial, and electric generation customers have the capability to switch to alternative energy sources. To date, Southwest has been successful in retaining most of these customers by setting rates at levels competitive with alternative energy sources such as electricity, fuel oils, and coal. However, increases in natural gas prices, if sustained for an extended period of time, may impact Southwest’s ability to retain some of these customers. Overall, management does not anticipate any material adverse impact on operating margin from fuel switching.
Southwest continues to compete with interstate transmission pipeline companies, such as El Paso, Kern River, and Tuscarora Gas Transmission Company, to provide service to certain large end-users. End-use customers located in close proximity to these interstate pipelines pose a potential bypass threat and, therefore, require Southwest to closely monitor each customer situation and provide competitive service in order to retain the customer. Southwest has remained competitive through the use of negotiated transportation contract rates, special long-term contracts with electric generation and cogeneration customers, and other tariff programs. These competitive response initiatives have mitigated the loss of margin earned from large customers.
Federal, state, and local laws and regulations governing the discharge of materials into the environment have had little direct impact upon Southwest. Environmental efforts, with respect to matters such as protection of endangered species and archeological finds, have increased the complexity and time required to obtain pipeline rights-of-way and construction permits. However, increased environmental legislation and regulation are also beneficial to the natural gas industry. Because natural gas is one of the most environmentally safe fossil fuels currently available, its use helps energy users comply with stricter environmental standards.
At December 31, 2002, the natural gas operations segment had 2,546 regular full-time equivalent employees, of which 488 full-time equivalent non-exempt employees in central Arizona are represented by the International Brotherhood of Electrical Workers. No other natural gas operations segment employees are represented by a union. Southwest believes it has a good relationship with its employees and that compensation, benefits, and working conditions afforded its employees are comparable to those generally found in the utility industry.
Northern Pipeline Construction Co. (Northern or the construction services segment) is a full-service underground piping contractor, which provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. Northern contracts primarily with LDCs to install, repair, and maintain energy distribution systems from the town border station to the end-user. The primary focus of business operations is main and service replacement as well as new business installations. Construction work varies from relatively small projects to the piping of entire communities. Construction activity is seasonal in most areas. Peak construction periods are the summer and fall months in colder climate areas, such as the midwest. In the warmer climate areas, such as the southwestern United States, construction continues year round.
Northern business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with Northern to provide pipe replacement services and new line installations. Contract terms generally specify unit-price or fixed-price arrangements. Unit-price contracts establish prices for all of the various services to be performed during the contract period. These contracts often have annual pricing reviews. During 2002, approximately 93 percent of revenue was earned under unit-price contracts. As of December 31, 2002 no significant backlog existed with respect to outstanding construction contracts.
Competition within the industry has traditionally been limited to several regional competitors in what has been a largely fragmented industry. Several national competitors also exist within the industry. Northern currently operates in approximately 17 major markets nationwide. Its customers are the primary LDCs in those markets. During 2002, Northern served 45 major customers, with Southwest accounting for approximately 34 percent of their revenues. With the
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exception of one other customer that accounted for approximately 12 percent of revenue, no other customer had a relatively significant contribution to Northern revenues.
Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2002, Northern had 1,939 regular full-time equivalent employees. Employment peaked in October 2002 when there were 2,290 employees. The majority of the employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.
Operations are conducted from 17 field locations with corporate headquarters located in Phoenix, Arizona. All buildings are leased from third parties. The lease terms are typically five years or less. Field location facilities consist of a small building for repairs and land to store equipment.
Described below are some of the identified risk factors of the Company that may have a negative impact on our future financial performance. Unless indicated otherwise, references below to “we”, “us” and “our” should be read to refer to Southwest Gas Corporation and its subsidiaries.
OUR LIQUIDITY, AND IN CERTAIN CIRCUMSTANCES, EARNINGS, COULD BE ADVERSELY AFFECTED BY THE COST OF PURCHASING NATURAL GAS DURING PERIODS IN WHICH NATURAL GAS PRICES ARE RISING SIGNIFICANTLY OR ARE MORE VOLATILE.
Rate schedules in each of our service territories contain purchased gas adjustment clauses which permit us to file for rate adjustments to recover increases in the cost of purchased gas. Increases in the cost of purchased gas have no direct impact on our profit margins, but do affect cash flows and can therefore impact the amount of our capital resources. We have used short-term borrowings in the past to temporarily finance increases in purchased gas costs, and we expect to do so during 2003, if the need again arises.
We may file requests for rate increases to cover the rise in the costs of purchased gas. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial run-up of these costs or our costs are more volatile. Any material disallowance of purchased gas costs could have a material impact on cash flow and earnings.
Increases in the cost of natural gas may arise from a variety of factors, including weather, changes in demand, the level of production and availability of natural gas, transportation constraints, federal and state energy and environmental regulation and legislation, the degree of market liquidity, natural disasters, wars, and other catastrophic events and the success of the Company’s strategies in managing price risk.
GOVERNMENTAL POLICIES AND REGULATORY ACTIONS CAN HAVE A MATERIAL IMPACT ON OUR EARNINGS.
Governmental policies and regulatory actions, including those of the ACC, the CPUC, the FERC, and the PUCN with respect to allowed rates of return, rate structure, purchased gas and investment recovery, operation and construction of facilities, present or prospective wholesale and retail competition, changes in tax laws and policies, and changes in and compliance with environmental and safety laws and policies, can have a material impact on our earnings. Risks and uncertainties relating to delays in obtaining regulatory approvals, adverse conditions imposed in regulatory approvals, or adverse determinations in regulatory investigations can also impact financial performance.
SIGNIFICANT CUSTOMER GROWTH IN ARIZONA AND NEVADA COULD STRAIN OUR CAPITAL RESOURCES.
We continue to experience significant population and customer growth throughout our service territories. During 2002, we added 58,000 customers, a four percent growth rate. Over the last several years, customer growth has averaged five percent. This growth has required large amounts of capital to finance the investment in new transmission and distribution plant. In 2002, our natural gas construction expenditures totaled $264 million. Approximately 66 percent of
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these current-period expenditures represented new construction, and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant.
Cash flows from operating activities (net of dividends) have been inadequate, and are expected to continue to be inadequate, to fund all necessary capital expenditures. We have been funding this shortfall through the issuance of additional debt and equity securities, and will continue to do so. Our ability to issue additional securities is dependent upon, among other things, conditions in the capital markets, regulatory authorizations, and our level of earnings.
SIGNIFICANT CUSTOMER GROWTH IN ARIZONA AND NEVADA COULD ALSO IMPACT EARNINGS.
Our ability to earn the rates of return authorized by the ACC and the PUCN is also adversely affected by significant customer growth, because the rates we charge our distribution customers in Arizona and Nevada are derived using rate base, cost of service, and cost of capital experienced in an historical test year, as adjusted. This results in “regulatory lag” which delays our recovery of some of the costs of capital improvements and operating costs from customers in Arizona and Nevada.
OUR EARNINGS ARE GREATLY AFFECTED BY VARIATIONS IN TEMPERATURE DURING THE WINTER HEATING SEASON.
The demand for natural gas is seasonal and is greatly affected by temperature. Variability in weather from normal temperatures can materially impact results of operations. On cold days, use of gas by residential and commercial customers may be as much as six times greater than on warm days because of the increased use of gas for space heating. Weather has been and will continue to be one of the dominant factors in our financial performance.
UNCERTAIN ECONOMIC CONDITIONS MAY AFFECT OUR ABILITY TO FINANCE CAPITAL EXPENDITURES.
Our ability to finance capital expenditures and other matters will depend upon general economic conditions in the capital markets. The direction of interest rates is uncertain. Declining interest rates are generally believed to be favorable to utilities while rising interest rates are believed to be unfavorable because of the high capital costs of utilities. In addition, our authorized rate of return is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, our authorized rate of return in the future could be reduced. If interest rates are higher than assumed rates, our ability to earn our currently authorized rate of return may be adversely impacted.
| PROPERTIES |
The plant investment of Southwest consists primarily of transmission and distribution mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators which comprise the pipeline systems and facilities located in and around the communities served. Southwest also includes other properties such as land, buildings, furnishings, work equipment, vehicles, and software systems in plant investment. The northern Nevada and northern California properties of Southwest are referred to as the northern system; the Arizona, southern Nevada, and southern California properties are referred to as the southern system. Several properties are leased by Southwest, including an LNG storage plant in northern Nevada, a portion of the corporate headquarters office complex located in Las Vegas, Nevada, and the administrative offices in Phoenix, Arizona. Total gas plant, exclusive of leased property, at December 31, 2002 was $2.8 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.
Substantially all gas main and service lines are constructed across property owned by others under right-of-way grants obtained from the record owners thereof, on the streets and grounds of municipalities under authority conferred by franchises or otherwise, or on public highways or public lands under authority of various federal and state statutes. None of the numerous county and municipal franchises are exclusive, and some are of limited duration. These franchises are renewed regularly as they expire, and Southwest anticipates no serious difficulties in obtaining future renewals.
With respect to the right-of-way grants, Southwest has had continuous and uninterrupted possession and use of all such rights-of-way, and the associated gas mains and service lines, commencing with the initial stages of the construction
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of such facilities. Permits have been obtained from public authorities and other governmental entities in certain instances to cross or to lay facilities along roads and highways. These permits typically are revocable at the election of the grantor and Southwest occasionally must relocate its facilities when requested to do so by the grantor. Permits have also been obtained from railroad companies to cross over or under railroad lands or rights-of-way, which in some instances require annual or other periodic payments and are revocable at the election of the grantors.
Southwest operates two primary pipeline transmission systems: (i) a system owned by Paiute, a wholly owned subsidiary, extending from the Idaho-Nevada border to the Reno, Sparks, and Carson City areas and communities in the Lake Tahoe area in both California and Nevada and other communities in northern and western Nevada; and (ii) a system extending from the Colorado River at the southern tip of Nevada to the Las Vegas distribution area.
The following map shows the locations of major Southwest facilities and transmission lines, and principal communities to which Southwest supplies gas either as a wholesaler or distributor. The map also shows major supplier transmission lines that are interconnected with the Southwest systems.
The information appearing in Part I, Item 1. Business, page 5 with respect to the construction services segment is incorporated herein by reference.
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| LEGAL PROCEEDINGS |
The Company has been named as defendant in various legal proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that none of this litigation will have a material adverse impact on the Company’s financial position or results of operations.
| SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
| MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
The principal markets on which the common stock of the Company is traded are the New York Stock Exchange and the Pacific Stock Exchange. At March 10, 2003, there were 21,974 holders of record of common stock, and the market price of the common stock was $19.60. The quarterly market price of and dividends on Company common stock required by this item are included in the 2002 Annual Report to Shareholders and are incorporated herein by reference.
| SELECTED FINANCIAL DATA |
Information required by this item is included in the 2002 Annual Report to Shareholders and is incorporated herein by reference.
| MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Information required by this item is included in the 2002 Annual Report to Shareholders and is incorporated herein by reference.
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Information required by this item is included in the 2002 Annual Report to Shareholders under the heading “Management’s Discussion and Analysis” and under Notes 6 and 7 of the Notes to Consolidated Financial Statements. This information is incorporated herein by reference. Other risk information is included under the heading “Company Risk Factors” in Item 1. Business of this report.
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The Consolidated Financial Statements of Southwest Gas Corporation and Notes thereto, together with the reports of PricewaterhouseCoopers LLP, Independent Accountants, and Arthur Andersen LLP, Independent Public Accountants, are included in the 2002 Annual Report to Shareholders and are incorporated herein by reference.
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
On May 28, 2002, the Company dismissed Arthur Andersen LLP as its independent auditor. The decision to dismiss Arthur Andersen was recommended by the Company’s Audit Committee and approved by its Board of Directors.
Arthur Andersen’s report on the financial statements of the Company for each of the years ended December 31, 2000 and December 31, 2001 did not contain an adverse opinion or a disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope, or accounting principles.
10
Table of Contents
During the years ended December 31, 2000 and December 31, 2001, and the interim period between December 31, 2001 and May 28, 2002, there were no disagreements between the Company and Arthur Andersen on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Arthur Andersen, would have caused it to make reference to the subject matter of the disagreements in connection with its report. During the years ended December 31, 2000 and December 31, 2001, and the interim period between December 31, 2001 and May 28, 2002, there were no reportable events (as defined in Item 304(a)(1)(v) of Regulation S-K promulgated by the SEC). In May 2002, Arthur Andersen furnished the Company with a letter addressed to the SEC stating that it agrees with the statements above. A copy of the letter was included as an exhibit to the Form 8-K filed by the Company in May 2002.
The Company engaged PricewaterhouseCoopers LLP as its independent auditor, effective May 28, 2002. During the years ended December 31, 2000 and December 31, 2001, and the interim period between December 31, 2001 and May 28, 2002, neither the Company nor anyone on its behalf consulted with PricewaterhouseCoopers LLP regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, (ii) the type of audit opinion that might be rendered on the Company’s financial statements, or (iii) any matter that was either the subject of a disagreement (as described above) or a reportable event.
The Company has not been able to obtain, after reasonable efforts, the written consent of Arthur Andersen to the incorporation by reference in the Company’s previously filed Form S-3 Registration Statements (Nos. 333-74520 and 333-98995) and Form S-8 Registration Statement (No. 333-98729) of the report of Arthur Andersen on the 2000 and 2001 financial statements included in this Annual Report, as required by the Securities Act of 1933. Therefore, in reliance on Rule 437a promulgated under the Securities Act of 1933, the Company has dispensed with the requirement to file a written consent from Arthur Andersen with this Annual Report. As a result, the ability of persons who purchase the Company’s securities pursuant to these Registration Statements to assert claims against Arthur Andersen may be limited.
Because the Company has not been able to obtain the written consent of Arthur Andersen, such persons may not have an effective remedy against Arthur Andersen for any untrue statements of a material fact contained in Arthur Andersen’s report or the financial statements covered thereby or any omissions to state a material fact required to be stated therein.
11
Table of Contents
| DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
(a) Identification of Directors. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive Proxy Statement to be dated March 31, 2003, which by this reference is incorporated herein.
(b) Identification of Executive Officers. The name, age, position, and period position held during the last five years for each of the Executive Officers of the Company are as follows:
| Name |
|
Age |
|
Position |
|
Period |
| |
|
|
|
|
|
|
| Michael O. Maffie |
|
55 |
|
President and Chief Executive Officer |
|
1998-Present |
| George C. Biehl |
|
55 |
|
Executive Vice President/Chief Financial Officer and Corporate Secretary |
|
2000-Present |
| |
|
|
|
Senior Vice President/Chief Financial Officer and Corporate Secretary |
|
1998-2000 |
| James P. Kane |
|
56 |
|
Executive Vice President/Operations |
|
2000-Present |
| |
|
|
|
Senior Vice President/Operations |
|
1998-2000 |
| Edward S. Zub |
|
54 |
|
Executive Vice President/Consumer Resources and Energy Services |
|
2000-Present |
| |
|
|
|
Senior Vice President/Regulation and Product Pricing |
|
1998-2000 |
| James F. Lowman |
|
56 |
|
Senior Vice President/Central Arizona Division |
|
1998-Present |
| Jeffrey W. Shaw |
|
44 |
|
Senior Vice President/Gas Resources and Pricing |
|
2002-Present |
| |
|
|
|
Senior Vice President/Finance and Treasurer |
|
2000-2002 |
| |
|
|
|
Vice President/Treasurer |
|
1998-2000 |
| Thomas R. Sheets |
|
52 |
|
Senior Vice President/Legal Affairs and General Counsel |
|
2000-Present |
| |
|
|
|
Vice President/General Counsel |
|
1998-2000 |
| Dudley J. Sondeno |
|
50 |
|
Senior Vice President/Chief Knowledge and Technology Officer |
|
1998-Present |
| Edward A. Janov |
|
48 |
|
Vice President/Finance and Treasurer |
|
2002-Present |
| |
|
|
|
Vice President/Chief Accounting Officer |
|
2001-2002 |
| |
|
|
|
Vice President/Controller and Chief Accounting Officer |
|
1998-2000 |
| Roy R. Centrella |
|
45 |
|
Vice President/Controller and Chief Accounting Officer |
|
2002-Present |
| |
|
|
|
Controller |
|
2001-2002 |
| |
|
|
|
Assistant Controller |
|
1998-2001 |
(c) Identification of Certain Significant Employees. None.
(d) Family Relationships. No Directors or Executive Officers are related to any other either by blood, marriage, or adoption.
(e) Business Experience. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive Proxy Statement to be dated March 31, 2003, which by this reference is incorporated herein. All Executive Officers have held responsible positions with the Company for at least five years as described in (b) above.
(f) Involvement in Certain Legal Proceedings. None.
(g) Promoters and Control Persons. None.
Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act of 1934 requires officers and directors, and persons who own more than ten percent of a registered class of equity securities, to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange. Officers, directors,
12
Table of Contents
and beneficial owners of more than ten percent of any class of equity securities are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file.
The Company has adopted procedures to assist its directors and executive officers in complying with Section 16(a) of the Securities and Exchange Act of 1934, as amended, which includes assisting in the preparation of forms for filing. For 2002, all but one of the reports were timely filed. An amended Form 4 was filed by Dudley Sondeno, Senior Vice President/Chief Knowledge and Technology Officer, on April 12, 2002, listing the additional sale of 4,500 shares of Company common stock in March 2002.
| EXECUTIVE COMPENSATION |
Information with respect to executive compensation is set forth under the heading “Executive Compensation and Benefits” in the definitive Proxy Statement to be dated March 31, 2003, which by this reference is incorporated herein.
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
(a) Security Ownership of Certain Beneficial Owners. Information with respect to security ownership of certain beneficial owners is set forth under the heading “Securities Ownership by Nominees, Executive Officers, and Beneficial Owners” in the definitive Proxy Statement to be dated March 31, 2003, which by this reference is incorporated herein.
(b) Security Ownership of Management. Information with respect to security ownership of management is set forth under the heading “Securities Ownership by Nominees, Executive Officers, and Beneficial Owners” in the definitive Proxy Statement to be dated March 31, 2003, which by this reference is incorporated herein.
(c) Changes in Control. None.
(d) Securities authorized for issuance under equity compensation plans.
At December 31, 2002, the Company had two stock-based compensations plans. With respect to the first plan, the Company may grant options to purchase shares of common stock to key employees and outside directors.
| Equity Compensation Plan Information | ||||||||||
| | ||||||||||
| Plan category |
|
Number of securities |
|
Weighted average |
|
Number of securities |
| |||
| |
|
|
|
|
|
|
| |||
| (Thousands of shares) |
|
|
|
|
|
|
|
|
|
|
| Equity compensation plans approved by security holders |
|
|
1,260 |
|
$ |
21.66 |
|
|
1,364 |
|
| Equity compensation plans not approved by security holders |
|
|
— |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
1,260 |
|
$ |
21.66 |
|
|
1,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
13
Table of Contents
In addition to the option plan, the Company may issue restricted stock in the form of performance shares to encourage key employees to remain in its employment to achieve short-term and long-term performance goals.
| Plan category |
|
Number of securities |
|
Weighted-average |
|
Number of securities |
| |||
| |
|
|
|
|
|
|
| |||
| (Thousands of shares) |
|
|
|
|
|
|
|
|
|
|
| Equity compensation plans approved by security holders |
|
|
345 |
|
$ |
21.16 |
|
|
— |
|
| Equity compensation plans not approved by security holders |
|
|
— |
|
|
— |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
| Total |
|
|
345 |
|
$ |
21.16 |
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
Additional information regarding the two equity compensation plans is included in Note 9 of the Notes to Consolidated Financial Statements in the 2002 Annual Report to Shareholders.
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
None.
| CONTROLS AND PROCEDURES |
The Company has established disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
Based on the most recent evaluation, which was completed within 90 days of the filing of this Form 10-K, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are operating effectively.
In addition, there were no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date of management’s most recent evaluation.
| EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K |
(a) The following documents are filed as part of this report on Form 10-K:
|
|
(1) |
The Consolidated Financial Statements of the Company (including the Reports of Independent Accountants) required to be reported herein are incorporated by reference to the information reported in the 2002 Annual Report to Shareholders under the following captions: |
| Consolidated Balance Sheets |
58 |
| Consolidated Statements of Income |
60 |
| Consolidated Statements of Cash Flows |
61 |
| Consolidated Statements of Stockholders’ Equity |
62 |
| Notes to Consolidated Financial Statements |
63 |
| Report of Independent Accountants |
84 |
| Report of Independent Public Accountants |
85 |
14
Table of Contents
|
|
(2) |
All schedules have been omitted because the required information is either inapplicable or included in the Notes to Consolidated Financial Statements. |
|
|
|
|
|
|
(3) |
See LIST OF EXHIBITS. |
(b) Reports on Form 8-K.
The Company filed a Form 8-K, dated December 18, 2002 under Item 5 reporting a $16.25 million settlement with an insurance provider related to the now terminated acquisition of the Company by ONEOK and the rejection of competing offers from Southern Union.
The Company filed a Form 8-K, dated January 24, 2003, disclosing the upcoming redemption of rights under the Company’s Amended and Restated Rights Agreement.
The Company filed a Form 8-K, dated February 18, 2003 reporting summary financial information for the quarter and year ended December 31, 2002.
(c) See LIST OF EXHIBITS.
15
Table of Contents
| Exhibit |
|
Description of Document |
| |
|
|
|
|
|
|
| 3(i) |
|
Restated Articles of Incorporation, as amended. Incorporated herein by reference to the report on Form 10-Q for the quarter ended March 31, 1997. |
|
|
|
|
| 3(ii) |
|
Amended Bylaws of Southwest Gas Corporation. Incorporated herein by reference to the report on Form 10-Q for the quarter ended June 30, 2002. |
|
|
|
|
| 4.01 |
|
Indenture between Clark County, Nevada, and Bank of America Nevada as Trustee, dated September 1, 1992, with respect to the issuance of $130,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), $30,000,000 1992 Series A, due 2027, and $100,000,000 1992 Series B, due 2032. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1992. |
|
|
|
|
| 4.02 |
|
Indenture between Clark County, Nevada, and Harris Trust and Savings Bank as Trustee, dated December 1, 1993, with respect to the issuance of $75,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), 1993 Series A, due 2033. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993. |
|
|
|
|
| 4.03 |
|
Indenture between City of Big Bear Lake, California, and Harris Trust and Savings Bank as Trustee, dated December 1, 1993, with respect to the issuance of $50,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation Project), 1993 Series A, due 2028. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993. |
|
|
|
|
| 4.04 |
|
Form of Deposit Agreement. Incorporated herein by reference to the Registration Statement on Form S-3, No. 33-55621. |
|
|
|
|
| 4.05 |
|
Form of Depositary Receipt (attached as Exhibit A to Deposit Agreement included as Exhibit 4.05 hereto). Incorporated herein by reference to the Registration Statement on Form S-3, No. 33-55621. |
|
|
|
|
| 4.06 |
|
Certificate of Trust of Southwest Gas Capital I. Incorporated herein by reference to the Registration Statement on Form S-3, No. 33-62143. |
|
|
|
|
| 4.07 |
|
Southwest Gas Capital I Preferred Securities Guarantee by the Company and Harris Trust and Savings Bank, dated as of October 31, 1995. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1995. |
|
|
|
|
| 4.08 |
|
Subordinated Debt Securities Indenture between the Company and Harris Trust and Savings Bank, dated as of October 31, 1995. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1995. |
|
|
|
|
| 4.09 |
|
First Supplemental Indenture between the Company and Harris Trust and Savings Bank, dated as of October 31, 1995, supplementing and amending the Indenture dated as of October 31, 1995, with respect to the 9.125% Subordinated Debt Securities. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1995. |
|
|
|
|
| 4.10 |
|
Form of Subordinated Debt Security (included in the First Supplemental Indenture included as Exhibit 4.10 hereto). Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1995. |
16
Table of Contents
| 4.11 |
|
Form of Guarantee with respect to Preferred Securities. Incorporated herein by reference to Amendment No. 1 to Registration Statement on Form S-3, No. 33-62143. |
|
|
|
|
| 4.12 |
|
Amended and Restated Declaration of Trust of Southwest Gas Capital I. Incorporated herein by reference to the report on Form 8-K dated October 26, 1995. |
|
|
|
|
| 4.13 |
|
Form of Preferred Security (attached as Annex I to Exhibit A to the Amended and Restated Declaration of Trust of Southwest Gas Capital I included as Exhibit 4.13 hereto). Incorporated herein by reference to the report on Form 8-K dated October 26, 1995. |
|
|
|
|
| 4.14 |
|
Indenture between the Company and Harris Trust and Savings Bank dated July 15, 1996, with respect to Debt Securities. Incorporated herein by reference to the report on Form 8-K dated July 26, 1996. |
|
|
|
|
| 4.15 |
|
First Supplemental Indenture of the Company to Harris Trust and Savings Bank dated August 1, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to 7 1/2% and 8% Debentures, due 2006 and 2026, respectively. Incorporated herein by reference to the report on Form 8-K dated July 31, 1996. |
|
|
|
|
| 4.16 |
|
Second Supplemental Indenture of the Company to Harris Trust and Savings Bank dated December 30, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to Medium-Term Notes. Incorporated herein by reference to the report on Form 8-K dated December 30, 1996. |
|
|
|
|
| 4.17 |
|
Indenture between Clark County, Nevada, and Harris Trust and Savings Bank as Trustee, dated as of October 1, 1999, with respect to the issuance of $35,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), Series 1999A and Taxable Series 1999B or convertibles of Series B (Series C and D), due 2038. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999. |
|
|
|
|
| 4.18 |
|
Third Supplemental Indenture between the Company and The Bank of New York, dated as of February 13, 2001, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the $200,000,000, 8.375% Notes, due 2011. Incorporated herein by reference to the report on Form 8-K dated February 8, 2001. |
|
|
|
|
| 4.19 |
|
Fourth Supplemental Indenture of the Company to The Bank of New York as successor to Harris Trust and Savings Bank dated as of May 6, 2002, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the 7.625% Senior Unsecured Notes due 2012. Incorporated herein by reference to the report on Form 8-K dated May 1, 2002. |
|
|
|
|
| 4.20 |
|
The Company hereby agrees to furnish to the SEC, upon request, a copy of any instruments defining the rights of holders of long-term debt issued by Southwest Gas Corporation or its subsidiaries; the total amount of securities authorized thereunder does not exceed 10 percent of the consolidated total assets of Southwest Gas Corporation and its subsidiaries. |
|
|
|
|
| 10.01 |
|
Participation Agreement among the Company and General Electric Credit Corporation, Prudential Insurance Company of America, Aetna Life Insurance Company, Merrill Lynch Interfunding, Bank of America through purchase of Valley Bank of Nevada, Bankers Trust Company and First Interstate Bank of Nevada, dated as of July 1, 1982. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1982. |
|
|
|
|
| 10.02 |
|
Financing Agreement between the Company and Clark County, Nevada, dated September 1, 1992. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993. |
17
Table of Contents
| 10.03 |
|
Financing Agreement between the Company and Clark County, Nevada, dated as of December 1, 1993. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993. |
|
|
|
|
| 10.04 |
|
Project Agreement between the Company and City of Big Bear Lake, California, dated as of December 1, 1993. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993. |
|
|
|
|
| 10.05 |
|
Amended and Restated Lease Agreement between the Company and Spring Mountain Road Associates, dated as of July 1, 1996. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 1996. |
|
|
|
|
| 10.06 * |
|
Southwest Gas Corporation Supplemental Retirement Plan, amended and restated as of March 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999. |
|
|
|
|
| 10.07 * |
|
Southwest Gas Corporation Board of Directors Retirement Plan, amended and restated as of March 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999. |
|
|
|
|
| 10.08 |
|
Financing Agreement between the Company and Clark County, Nevada, dated as of October 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999. |
|
|
|
|
| 10.09 * |
|
Amended Form of Employment Agreement with Company Officers. Incorporated herein by reference to the reports on Form 10-Q for the quarters ended September 30, 1998, September 30, 2000 and September 30, 2001. |
|
|
|
|
| 10.10 * |
|
Amended Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to the reports on Form 10-Q for the quarters ended September 30, 1998, September 30, 2000 and September 30, 2001. |
|
|
|
|
| 10.11 * |
|
Southwest Gas Corporation Management Incentive Plan, amended and restated January 1, 2002. Incorporated herein by reference to the Proxy Statement dated April 2, 2002. |
|
|
|
|
| 10.12 * |
|
Southwest Gas Corporation 2002 Stock Incentive Plan. Incorporated herein by reference to the Proxy Statement dated April 2, 2002. |
|
|
|
|
| 10.13 |
|
Multi-Year Revolving Credit Agreement among the Company, The Bank of New York, et al., dated as of May 10, 2002. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 2002. |
|
|
|
|
| 10.14 * |
|
Southwest Gas Corporation Executive Deferral Plan, amended and restated as of November 19, 2002. |
|
|
|
|
| 10.15 * |
|
Southwest Gas Corporation Directors Deferral Plan, amended and restated as of November 19, 2002. |
|
|
|
|
| 10.16 |
|
Lease Supplement (attached as a supplement to Exhibit 10.01) as of December 12, 2002. |
|
|
|
|
| 12.01 |
|
Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation. |
|
|
|
|
| 13.01 |
|
Portions of 2002 Annual Report incorporated by reference to the Form 10-K. |
18
Table of Contents
| 16.01 |
|
Letter of Arthur Andersen LLP regarding change in certifying accountant. Incorporated herein by reference to the report on Form 8-K dated May 28, 2002. |
|
|
|
|
| 21.01 |
|
List of subsidiaries of Southwest Gas Corporation. |
|
|
|
|
| 23.01 |
|
Consent of PricewaterhouseCoopers LLP, Independent Accountants. |
|
|
|
|
| * Compensation Plans | ||
19
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
SOUTHWEST GAS CORPORATION | |
|
|
|
|
| Date: March 25, 2003 |
By |
/s/ MICHAEL O. MAFFIE |
|
|
|
|
|
|
|
Michael O. Maffie |
20
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| |
|
Title |
|
Date |
| |
|
|
|
|
| /s/ GEORGE C. BIEHL |
|
Director, Executive Vice President, |
|
March 25, 2003 |
| |
|
|
|
|
| (George C. Biehl) |
|
|
|
|
|
|
|
|
|
|
| /s/ MANUEL J. CORTEZ |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (Manuel J. Cortez) |
|
|
|
|
|
|
|
|
|
|
| /s/ MARK M. FELDMAN |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (Mark M. Feldman) |
|
|
|
|
|
|
|
|
|
|
| /s/ DAVID H. GUNNING |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (David H. Gunning) |
|
|
|
|
|
|
|
|
|
|
| /s/ THOMAS Y. HARTLEY |
|
Chairman of the Board of Directors |
|
March 25, 2003 |
| |
|
|
|
|
| (Thomas Y. Hartley) |
|
|
|
|
|
|
|
|
|
|
| /s/ MICHAEL B. JAGER |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (Michael B. Jager) |
|
|
|
|
|
|
|
|
|
|
| /s/ LEONARD R. JUDD |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (Leonard R. Judd) |
|
|
|
|
|
|
|
|
|
|
| /s/ JAMES J. KROPID |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (James J. Kropid) |
|
|
|
|
|
|
|
|
|
|
| /s/ MICHAEL O. MAFFIE |
|
Director, President, and Chief Executive Officer |
|
March 25, 2003 |
| |
|
|
|
|
| (Michael O. Maffie) |
|
|
|
|
|
|
|
|
|
|
| /s/ CAROLYN M. SPARKS |
|
Director |
|
March 25, 2003 |
| |
|
|
|
|
| (Carolyn M. Sparks) |
|
|
|
|
|
|
|
|
|
|
| /s/ TERRANCE L. WRIGHT |
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Director |
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March 25, 2003 |
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| (Terrance L. Wright) |
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| /s/ ROY R. CENTRELLA |
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Vice President, Controller, and Chief Accounting Officer |
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March 25, 2003 |
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| (Roy R. Centrella) |
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Table of Contents
I, Michael O. Maffie, certify that:
| 1. |
I have reviewed this annual report on Form 10-K of Southwest Gas Corporation; | ||
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| 2. |
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; | ||
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| 3. |
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; | ||
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| 4. |
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: | ||
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a) |
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; | |
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b) |
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and | |
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c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; | |
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| 5. |
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): | ||
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a) |
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and | |
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b) |
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and | |
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| 6. |
The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. | ||
| Date: March 25, 2003 |
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/s/ MICHAEL O. MAFFIE | |
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Michael O. Maffie | |
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Table of Contents
Certification on Form 10-K
I, George C. Biehl, certify that:
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I have reviewed this annual report on Form 10-K of Southwest Gas Corporation; | |
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| 2. |
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; | |
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| 3. |
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; | |
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| 4. |
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: | |
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a) |
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; |
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b) |
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and |
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c) |
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; |
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| 5. |
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): | |
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all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and |
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b) |
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and |
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| 6. |
The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. | |
| Date: March 25, 2003 |
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/s/ GEORGE C. BIEHL | |
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George C. Biehl | |
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Executive Vice President, Chief Financial Officer and Corporate Secretary | |
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EXHIBIT INDEX
| Exhibit |
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Description of Document |
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| 10.14 |
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Southwest Gas Corporation Executive Deferral Plan, amended and restated as of November 19, 2002. |
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| 10.15 |
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Southwest Gas Corporation Directors Deferral Plan, amended and restated as of November 19, 2002. |
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| 10.16 |
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Lease Supplement (attached as a supplement to Exhibit 10.01) as of December 12, 2002. |
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| 12.01 |
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Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation. |
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| 13.01 |
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Portions of 2002 Annual Report to Shareholders incorporated by reference to Form 10-K. |
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| 21.01 |
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List of Subsidiaries of Southwest Gas Corporation. |
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| 23.01 |
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Consent of PricewaterhouseCoopers LLP, Independent Accountants. |
24
Exhibit 10.14
MASTER PLAN DOCUMENT
SOUTHWEST GAS CORPORATION EXECUTIVE DEFERRAL
PLAN
Effective March 1, 1986
Amended and Restated March 1, 1988
Amended and Restated March 1, 1989
Amended and Restated March 1, 1990
Amended and Restated October 29, 1992
Amended and Restated May 10, 1994
Amended and Restated Effective March 1, 1999
Amended and Restated November 19, 2002
TABLE OF CONTENTS
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16 |
MASTER PLAN DOCUMENT
SOUTHWEST GAS CORPORATION EXECUTIVE DEFERRAL PLAN
PURPOSE
The purpose of this Plan is to provide specified benefits to a select group of key employees who contribute materially to the continued growth, development and future business success of SOUTHWEST GAS CORPORATION.
For purposes hereof, unless otherwise clearly apparent from the context, the words and phrases listed below shall be defined as follows:
| 1.1 |
“Account Balance” means a Participant’s individual fund comprised of Deferrals, Company Contributions and interest earnings credited thereon up to the time of Benefit Distribution. |
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| 1.2 |
“Base Annual Salary” means the yearly compensation paid to an Executive, excluding bonuses, commissions, overtime, and nonmonetary awards for employment services to the Company. |
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| 1.3 |
“Beneficiary” means the person or persons, or the estate of a Participant, named to receive any benefits under the Plan upon the death of a Participant. |
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| 1.4 |
“Benefit Account Balance” shall have the meaning set forth in Article 5.3. |
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| 1.5 |
“Benefit Distribution” means the date benefits under the Plan commence or are paid in full to a Participant, or because of his death, to his Beneficiary, which will occur within 90 days of notification to the Company of the event that gives rise to such distribution. |
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| 1.6 |
“Board of Directors” means the Board of Directors of Southwest Gas Corporation and any Successor Corporation. |
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| 1.7 |
“Bonus” means the portion of actual awards, if any, paid in cash under the terms of Southwest Gas Corporation’s 1993 Management Incentive Plan, as amended (“Management Incentive Plan”). |
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| 1.8 |
“Change in Control” means the first to occur of any of the following events: |
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(a) |
Any “person” (as the term is used in Section 13 and 14(d)(2) of the Securities Exchange Act of 1934 (“Exchange Act”)) becomes a beneficial owner (as that term is used in Section 13(d) of the Exchange Act), directly or indirectly, of 50% or more of the Company’s capital stock entitled to vote in the election of directors; or |
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(b) |
During any period of not more than two consecutive years, not including any period prior to the adoption of this Plan, individuals who, at the beginning of such period constitute the board of directors of the Company, and any new director (other than a director designated by a person who has entered into an agreement with the Company to effect a transaction described in clause (a) of this Article 1.8) whose election by the board of directors or nomination for election by the Company’s shareholders was approved by a vote of at least three-fourths (3/4ths) of the directors then still in office, who either were directors at the beginning of the period or whose election or nomination for election was previously approved, cease for any reason to constitute at least a majority thereof. |
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| 1.9 |
“Committee” means the administrative committee appointed by the Board of Directors to manage and administer the Plan in accordance with the provisions of the Plan. After a Change in Control, the Committee shall cease to have any powers under the Plan and all powers previously vested in the Committee under the Plan will then be vested in the Third Party Fiduciary. | |
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| 1.10 |
“Company” means Southwest Gas Corporation and such of its Subsidiaries as the Board of Directors may select to become parties to the Plan. The term “Company” shall also include any Successor Corporation. | |
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| 1.11 |
“Company Contributions” means the amount added, if any, to a Participant’s Account Balance in accordance with Article 3.2. | |
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| 1.12 |
“Deferral(s)” means the amount of Base Annual Salary, Bonus and special income, as referred to in Article 3.9, transferred to the Plan accounts. | |
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| 1.13 |
“Employee” means any full-time employee of Southwest Gas Corporation as determined under the personnel policies and practices of Southwest Gas Corporation prior to a Change in Control. | |
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| 1.14 |
“Executive” means any officer of Southwest Gas Corporation prior to a Change in Control. | |
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| 1.15 |
“Master Plan Document” means this legal instrument containing the provisions of the Plan. | |
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| 1.16 |
“Moody’s Rate” means Moody’s Seasoned Corporate Bond Rate which is an | |
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economic indicator consisting of an arithmetic average of yields of representative bonds (industrial and AAA, AA and A rated public utilities) as of January 1 prior to each Plan Year as published by Moody’s Investors Service, Inc. (or any successor thereto), or, if such index is no longer published, a substantially similar index selected by the Board of Directors. |
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| 1.17 |
“Moody’s Composite Rate” means the average of the Moody’s Rate on January 1 for the five (5) years prior to Benefit Distribution. |
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| 1.18 |
“Participant” means any Executive who executes a Plan Agreement or an Employee who has been selected to participate in the Plan and who executes a Plan Agreement. |
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| 1.19 |
“Plan” means the Executive Deferral Plan of the Company evidenced by this Master Plan Document. |
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| 1.20 |
“Plan Agreement” means the form of written agreement which is entered into from time to time, by and between the Company and a Participant. |
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| 1.21 |
“Plan Year” means the year beginning on March 1 of each year. |
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| 1.22 |
“Retire” or “Retirement” means the severance from employment with the Company on or after attaining age 55, other than by death, disability or Termination of Employment. |
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| 1.23 |
“Subsidiary” means any corporation, partnership, or other organization which is at least 50% owned by the Company or a Subsidiary of the Company. |
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| 1.24 |
“Successor Corporation” means any corporation or other legal entity which is the successor to Southwest Gas Corporation, whether resulting from merger, reorganization or transfer of substantially all of the assets of Southwest Gas Corporation, regardless of whether such entity shall expressly agree to continue the Plan. |
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| 1.25 |
“Terminates Employment” or “Termination of Employment” means the ceasing of employment with the Company, either voluntarily or involuntarily, excluding Retirement, disability or death. |
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| 1.26 |
“Third Party Fiduciary” means an independent third party (a corporate entity with no other relationship with the Company) selected by the Company to take over the administration of the Plan upon and after a Change in Control and to determine appeals of claims denied under the Plan before and after a Change in Control pursuant to a Third Party Fiduciary Services Agreement. |
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| 1.27 |
“Third Party Fiduciary Services Agreement” means the agreement with the Third |
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Party Fiduciary to perform services with respect to the Plan. |
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| 1.28 |
“Trust Agreement” means an agreement establishing a “grantor trust” of which the Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended (the “Code”). |
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| 1.29 |
“Trust Fund or Funds” means the assets of every kind and description held under any Trust Agreement forming a part of the Plan. |
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| 1.30 |
“Trustee” means any person or entity selected by the Company to act as trustee under any Trust Agreement at any time of reference. |
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| 1.31 |
“Years of Service” means a Participant’s Benefit Service as defined in the Retirement Plan for Employees of Southwest Gas Corporation, plus service with a Successor Corporation which is not taken into account for such plan. |
| 2.1 |
Selection of Participants. An Executive shall become eligible to participate in the Plan as of the effective date of his election by the Board of Directors as an officer of the Company (unless the Board of Directors determines, at that time, that such Executive will not become eligible to participate in the Plan). The Committee in its sole discretion may select any other Employee to become eligible to participate in the Plan. |
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| 2.2 |
Continued Eligibility. If a Participant ceases to be an Executive and he continues as an Employee, the Committee in its sole discretion will determine whether such Employee will continue to be eligible to participate in the Plan. Notwithstanding the foregoing and upon the occurrence of a Change in Control, a Participant will continue to participate in the Plan. |
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| 2.3 |
Participant Acceptance. Once eligible to participate in the Plan, an Executive or an Employee has to complete, execute and return to the Committee a Plan Agreement to become a Participant in the Plan. Continued participation in the Plan is subject to compliance with any further conditions as may be established by the Committee. Notwithstanding the foregoing and upon the occurrence of a Change in Control, no additional conditions regarding continued participation in the Plan may be established by the Committee or any Successor Corporation. |
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ARTICLE 3
DEFERRAL COMMITMENT AND COMPANY CONTRIBUTION
| 3.1 |
Deferrals. A Participant may defer up to 100% of his Base Annual Salary and Bonus received during a Plan Year; provided, that such Deferral exceeds $2,000 per Plan Year. Notwithstanding the foregoing, no election shall be effective to reduce the Base Annual Salary and Bonus paid to a Participant for a calendar year to an amount which is less than the amount that the Company is required to withhold from such Participant’s Base Annual Salary and Bonus for the calendar year for (a) applicable income and employment taxes (including Federal Insurance Contributions Act tax), (b) contributions to any employee benefit plan (other than this Plan), and (c) payroll transfers, in place, prior to such elections. |
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| 3.2 |
Company Matching Contributions. If a Participant makes a Deferral commitment with respect to Base Annual Salary and/or Bonus, the Company will contribute an amount equal to 50% of such Deferral, up to a maximum of 3% of the Participant’s Base Annual Salary, to the Participant’s Account Balance. |
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| 3.3 |
Timing of Deferral Election. Prior to the commencement of each Plan Year, a Participant will (a) advise the Committee, in writing, of his Base Annual Salary Deferral commitment for the upcoming Plan Year and (b) make his Deferral commitment for any Bonus earned during the calendar year ending in such Plan Year. If a Participant fails to so advise the Committee, through no fault of the Company, he will not be permitted to defer any of his Base Annual Salary or Bonus during the upcoming Plan Year. |
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| 3.4 |
Exercise of Deferral Commitment. A Participant’s Deferral commitment will be exercised on a per pay period basis for the portion of his Base Annual Salary that is deferred. The exercise of a Participant’s Deferral commitment with respect to his Bonus will occur at the time the Bonus is paid. |
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| 3.5 |
Adjustment to Deferral Commitment. The Committee reserves the right to adjust any Participant’s Deferral commitment during a Plan Year to ensure that a Participant’s actual Deferral does not exceed the maximum allowable amount. |
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| 3.6 |
Deferral Elections by New Participants. In the event an Executive or an Employee becomes a Participant in the Plan during a Plan Year, such Participant may defer up to 100% of the remaining portion of his Base Annual Salary for the current Plan Year. Such Participant must make his Deferral commitment by advising the Committee, in writing, at the time he elects to become a Participant in the Plan. |
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| 3.7 |
Deferral Commitment Default. In the event a Participant defaults on his Base Annual Salary Deferral commitment, the Participant will not be allowed to make any further Deferrals during the current Plan Year and may not make any Deferrals for the subsequent Plan Year. In the event a Participant defaults on his Bonus Deferral commitment for a particular Plan Year, the Participant will not be able to defer any |
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of his Bonus for that Plan Year or the subsequent Plan Year. |
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| 3.8 |
Waiver of Deferral Commitment Default. The Committee may waive for good cause the default penalty specified in Article 3.7 upon the request of the Participant. |
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| 3.9 |
Deferral of Special Income. A Participant who is entitled to receive cash (a) from the cancellation of stock options granted under the 1996 Stock Incentive Plan as a result of a Change in Control, (b) from the cancellation of outstanding performance shares issued pursuant to the Management Incentive Plan as a result of a Change in Control, or (c) under an employment, severance or special pay arrangement payable on account of termination of employment resulting from a Change in Control, may elect to defer receipt of all or a portion of such income; provided that such election is filed with the Committee at least six (6) months prior to the date such income would otherwise have become payable to the Participant. If the Participant makes such an election, such income shall not be paid to the Participant but rather shall be treated as a Deferral and added to the Participant’s Account Balance as of the date such income would otherwise have been paid to the Participant. In addition, for such election to be effective with respect to the deferral of income resulting from the cancellation of an option, the Participant must agree in writing that such option shall not be exercised at all after the date of the election. Notwithstanding the foregoing, a Participant’s election to defer income resulting from cancellation of an option shall terminate and the option may be exercised in accordance with its terms without regard to the election if the option would otherwise expire prior to cancellation (for example, because of the Participant’s termination of employment) or if the cancellation does not occur. |
ARTICLE 4
INTEREST, CREDITING AND VESTING
| 4.1 |
Interest Rate. A Participant’s Account Balance at the start of a Plan Year and any Deferrals and Company contributions made during a Plan Year will earn, except as provided for in Article 4.2, interest annually at 150% of the Moody’s Rate. Interest will be credited to a Participant’s account for Deferrals and Company contributions made during the Plan Year, as if all Deferrals and contributions were made on the first day of the Plan Year. |
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| 4.2 |
Adjustment to Interest Rate. If a Participant Terminates Employment prior to completing five (5) Years of Service with the Company, interest credited for all Deferrals and vested Company contributions to a Participant’s Account Balance will be adjusted based on the Moody’s Rate during the period he participated in the Plan. |
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| 4.3 |
Vesting of Company Contributions. Company contributions and interest earned |
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on such contributions will vest to a Participant at the rate of 20% per Year of Service and will vest completely once a Participant has five (5) Years of Service with the Company. |
ARTICLE 5
PLAN BENEFIT PAYMENTS
| 5.1 |
Lump-Sum Payment. A Participant’s Account Balance will be paid to the Participant in a lump-sum payment at the time of Benefit Distribution, unless the Participant qualifies to receive benefit payments over a specific benefit payment period. |
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| 5.2 |
Interest prior to Benefit Distribution. A Participant’s Account Balance will earn interest under the provisions of Article 4.1 or, if applicable, Article 4.2 until the time of Benefit Distribution. |
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| 5.3 |
Benefit Payment Periods. If a Participant is entitled to receive Plan benefit payments over a specific benefit payment period, his Account Balance at the commencement of Benefit Distribution will be credited with an amount equal to the interest such balance would have earned assuming distribution in equal monthly installments over the specific benefit payment period, at a specified interest rate, thereby creating a Benefit Account Balance. The Benefit Account Balance will then be paid to the Participant in equal monthly installments over the specific benefit payment period. |
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| 5.4 |
Payment Prior to Benefit Distribution. If there shall be a final determination by the Internal Revenue Service or a court of competent jurisdiction that the election by a Participant to defer the payment of any amount in accordance with the terms of this Plan was not effective to defer the taxation of such amount, then the Participant shall be entitled to receive a distribution of the amount determined to be taxable and the Participant’s Account Balance shall be reduced accordingly. |
ARTICLE 6
RETIREMENT AND TERMINATION BENEFIT PAYMENTS
| 6.1 |
Benefit Payment Periods; Elections. A Participant who Retires or Terminates Employment with more than five (5) Years of Service qualifies to receive his Account Balance over a period of 120, 180 or 240 months. The Participant shall elect the payment period; provided that written notice of such election is filed with the Committee at least one (1) year prior to his Retirement or Termination of Employment. If a Participant fails to make such election prior to the time specified, the payment period will be 240 months. |
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| 6.2 |
Changing Elections. A Participant who has made an election under this Article may subsequently revoke such election and make another election under this Article by providing written notice to the Committee; provided, however, that only the last such election or revocation in effect on the date which is one (1) year prior to the date on which the Participant Retires or Terminates Employment shall be effective. Notwithstanding the foregoing, if a Participant Terminates Employment or Retires as a result of a Change in Control, the foregoing provisions of this Article 6 shall be applied by substituting “six (6) months” for “one (1) year.” |
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| 6.3 |
Interest on Benefit Payments. The interest rate used to calculate the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3, will be 150% of the Moody’s Composite Rate. |
ARTICLE 7
PRE-RETIREMENT SURVIVOR BENEFIT PAYMENTS
| 7.1 |
Benefit Payments. Notwithstanding any elections made pursuant to Article 6, if a Participant dies while he is an employee of the Company, his Account Balance will be paid to his Beneficiary in equal monthly installments over the 180 month survivor benefit payment period. |
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| 7.2 |
Interest on Benefit Payments. The interest rate used to determine the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3 following the Participant’s death, will be 150% of the Moody’s Composite Rate. |
ARTICLE 8
POST-RETIREMENT SURVIVOR BENEFIT PAYMENTS
| 8.1 |
Benefit Payments. If a Participant dies after the commencement of Retirement, Termination of Employment or disability benefit payments under Articles 6 or 9 but prior to such benefits having been paid in full, the Participant’s benefit payments will continue to be paid to the Participant’s Beneficiary through the end of the originally awarded benefit payment period, except as provided for in Article 10.7. |
ARTICLE 9
DISABILITY BENEFIT PAYMENTS
| 9.1 |
Disability Determination. A Participant shall be considered disabled if he qualifies for a disability benefit under the Company’s group long-term disability plan. In the event a Participant does not qualify for benefits under the group long-term disability |
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plan, the Committee may determine that a Participant is disabled under the provisions of the Plan. |
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| 9.2 |
Vesting of Company Contributions. Notwithstanding the provisions of Article 4.3, Company contributions and interest earned on such contributions will be fully vested to the Participant at the time he is determined to be disabled under this Article. |
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| 9.3 |
Benefit Payments During First Five (5) Years of Service. If a Participant is disabled within the first five (5) Years of Service with the Company, he will receive his Account Balance in a lump sum payment at Benefit Distribution. |
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| 9.4 |
Benefit Payments After Five (5) Years of Service. Notwithstanding any elections made pursuant to Article 6, if a Participant is disabled after five (5) Years of Service with the Company, his Account Balance will be paid to him in equal monthly installments over the 180 month disability payment period. |
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| 9.5 |
Interest on Benefit Payments. If a Participant qualifies to receive his Account Balance over the disability benefit payment period, the interest rate used to calculate the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3, will be 150% of the Moody’s Composite Rate. |
| 10.1 |
Designation of Beneficiaries. A Participant shall have the right to designate any person as his Beneficiary to whom benefits under this Plan shall be paid in the event of the Participant’s death prior to the total distribution of his Benefit Account Balance under the Plan. If greater than 50% of the Benefit Account Balance is designated to a Beneficiary other than the Participant’s spouse, such Beneficiary designation must be consented to by the Participant’s spouse. Each Beneficiary designation must be in written form prescribed by the Committee and will be effective only when filed with the Committee during the Participant’s lifetime. |
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| 10.2 |
Changing Beneficiary Designation. A Participant shall have the right to change the Beneficiary designation, subject to spousal consent under the provisions of Article 10.1, without the consent of any designated Beneficiary by filing a new Beneficiary designation with the Committee. The filing of a new Beneficiary designation form will cancel all Beneficiary designations previously filed. |
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| 10.3 |
Acknowledgment. The Committee shall acknowledge, in writing, receipt of each Beneficiary designation form. |
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| 10.4 |
Discharge of Company Obligation. The Committee shall be entitled to rely on the |
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Beneficiary designation last filed by the Participant prior to his death. Any payment made in accordance with such designation shall fully discharge the Company from all further obligations with respect to the amount of such payments. |
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| 10.5 |
Minor or Incompetent Beneficiaries. If a Beneficiary entitled to receive benefits under the Plan is a minor or a person declared incompetent, the Committee may direct payment of such benefits to the guardian or legal representative of such minor or incompetent person. The Committee may require proof of incompetency, minority or guardianship as it may deem appropriate prior to distribution of any Plan benefits. Such distribution shall completely discharge the Committee and the Company from all liability with respect to such payments. |
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| 10.6 |
Effect of No Beneficiary Designation. If no Beneficiary designation is in effect at the time of the Participant’s death, or if the named Beneficiary predeceased the Participant, then the Beneficiary shall be: (a) the surviving spouse; (b) if there is no surviving spouse, then his issue per stirpes; or (c) if no surviving spouse or issue, then his estate. |
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| 10.7 |
Payment to Contingent Beneficiary. If a Beneficiary receiving benefit payments under the provisions of the Plan dies prior to the completion of the benefit payment period, the present value of the remaining benefit payments will be paid, in a lump sum amount, to the contingent Beneficiary designated by the Participant under the provisions of Article 10.1. If the Participant has failed to designate a contingent Beneficiary, the present value of the remaining benefit payments will be paid, in a lump sum amount, to the Beneficiary’s estate. The present value of the remaining benefit payments will be calculated using the same methodology, including the same interest rate, as was used to calculate the Participant’s annuity payment calculation, under Article 5.3. |
| 11.1 |
Continuation of Deferral Commitment. If a Participant is authorized by the Company for any reason to take a paid leave of absence, the Participant’s Deferral commitment shall remain in full force and effect. |
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| 11.2 |
Suspension of Deferral Commitment. If a Participant is authorized by the Company for any reason to take an unpaid leave of absence, the Participant’s Deferral commitment shall be suspended until the leave of absence ends and the Participant’s employment resumes. |
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| 12.1 |
Payment Obligation. Amounts payable to a Participant shall be paid from the general assets of the Company or from the assets of a grantor trust within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code, established for use in funding executive compensation arrangements and commonly known as a “rabbi trust.” |
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| 12.2 |
Limitation on Payment Obligation. The Company shall have no obligation under the Plan to a Participant or a Participant’s Beneficiary, except as provided in this Master Plan Document. |
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| 12.3 |
Furnishing Information. The Participant must cooperate with the Committee in furnishing all information requested by the Company to facilitate the payment of his Benefit Account Balance. Such information may include the results of a physical examination if any is required for participation in the Plan. |
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| 12.4 |
Unsecured General Creditor. Participants and their Beneficiaries, heirs, successors, and assigns shall have no legal or equitable rights, claims, or interest in any specific property or assets of the Company. No assets of the Company shall be held under any trust, or held in any way as collateral security for the fulfilling of the obligations of the Company under the Plan. Any and all of the Company’s assets shall be, and remain, the general unpledged, unrestricted assets of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise of the Company to pay money in the future, and the rights of the Participants and Beneficiaries shall be no greater than those of unsecured general creditors. It is the intention of the Company that this Plan (and the Trust Funds described in Article 14.1) be unfunded for purposes of the Code and for the purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). |
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| 12.5 |
Withholding. There shall be deducted from each payment made under the Plan or other compensation payable to the Participant (or Beneficiary) all taxes which are required to be withheld by the Company in respect to such payment or this Plan. The Company shall have the right to reduce any payment (or other compensation) by the amount of cash sufficient to provide the amount of said taxes. |
ARTICLE 13
NO GUARANTEE OF CONTINUING EMPLOYMENT
| 13.1 |
Future Employment. The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between the Company and a Participant. Moreover, nothing in the Plan shall be deemed to give a Participant the right to be retained in the service of the Company or to interfere with the right of the Company to discipline or discharge the Participant at any time. |
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| 14.1 |
Trusts. The Company may maintain one or more Trust Funds to finance all or a portion of the benefits under the Plan by entering into one or more Trust Agreements. Any Trust Agreement is designated as, and shall constitute, a part of the Plan, and all rights which may accrue to any person under the Plan shall be subject to all the terms and provisions of such Trust Agreement. A Trustee shall be appointed by the Committee or the Board of Directors and shall have such powers as provided in the Trust Agreement. The Committee or the Board of Directors may modify any Trust Agreement, in accordance with its terms, to accomplish the purposes of the Plan and appoint a successor Trustee under the provisions of such Trust Agreement. By entering into such Trust Agreement, the Committee or the Board of Directors may vest in the Trustee, or in one or more investment managers (as defined in ERISA) the power to manage and control the Trust Fund. The Committee’s authority under the provisions of this Article 14.1 will cease with a Change in Control. |
ARTICLE 15
TERMINATION, AMENDMENT OR MODIFICATION OF THE PLAN
| 15.1 |
Plan Amendment and Termination. The Board of Directors may, at any time, without notice, amend or modify the Plan in whole or in part; provided, however, that (a) no amendment or modification shall be effective to decrease or restrict (i) the amount of interest to be credited to a Participant’s Account Balance under the provisions of the Plan, (ii) the benefits the Participant qualifies for or may elect to receive under the provisions of the Plan, or (iii) benefit payments to Participants or Beneficiaries once such payments have commenced, and (b) effective March 1, 1999, no amendment or modification of this Article 15, Article 17, or Article 18 of the Plan shall be effective. |
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| 15.2 |
Plan Termination. The Board of Directors shall not terminate the Plan until all accrued benefits have been paid in full under the provisions of the Plan to the Participants and Beneficiaries. |
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| 15.3 |
Partial Plan Termination. Except for the Participants’ ability to defer special income under the provisions of Article 3.9, the Board of Directors may partially terminate the Plan by instructing the Committee not to accept any additional Deferral commitments. In the event of a partial termination, the remaining provisions of the Plan shall continue to operate and be effective for all Participants in the Plan, as of the date of such partial termination. |
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| 15.4 |
Change of Control. In the event of a hostile or non-negotiated Change of Control of the Company, the benefits of this Plan will become 100% vested for all Participants and the interest credited to a Participant’s Account Balance under any provision of this Plan will be adjusted, retroactively to the date an individual became a Participant and prospectively thereafter, to 200% of the Moody’s Rate. |
ARTICLE 16
RESTRICTIONS ON ALIENATION OF BENEFITS
| 16.1 |
Alienation of Benefits. To the maximum extent permitted by law, no interest or benefit under the Plan shall be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind. |
ARTICLE 17
ADMINISTRATION OF THE PLAN
| 17.1 |
Committee Duties. Except as otherwise provided in this Article 17, and subject to Article 18, the general administration of the Plan, as well as construction and interpretation thereof, shall be vested in the Committee. Members of the Committee may be Participants under the Plan. Specifically, the Committee shall have the discretion and authority to: (a) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan; and (b) decide or resolve any and all questions including interpretations of the Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. The number of members of the Committee shall be established by, and the members shall be appointed from time to time by, and shall serve at the pleasure of, the Board of Directors. |
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| 17.2 |
Administration After a Change in Control. Upon and after a Change in Control, the administration of the Plan shall be vested in a Third Party Fiduciary, as provided for herein and pursuant to the terms of a Third Party Fiduciary Services Agreement. Any Third Party Fiduciary Services Agreement is designated as, and shall constitute, a part of the Plan. The Third Party Fiduciary shall also have the discretion and authority to: (a) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan; and (b) decide or resolve any and all questions including interpretation of the Plan and the Trust Agreement. Except as otherwise provided for in any Trust Agreement, the Third Party Fiduciary shall have no power to direct the investment of Plan or Trust Funds or select any investment manager or custodial firm for the Plan or Trust Agreement. The Company shall pay all reasonable administrative expenses and fees of the Third Party Fiduciary when it acts as the administrator of the Plan or pursuant to Article 18. The Third Party Fiduciary may not be terminated by the Company without the |
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consent of 50% of the Participants in the Plan. |
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| 17.3 |
Agents. In the administration of the Plan, the Committee or the Third Party Fiduciary, as the case may be, may from time to time employ such agents, consultants, advisors, and managers as it deems necessary or useful in carrying out its duties as it sees fit (including acting through a duly authorized representative) and may from to time to time consult with counsel to the Company. |
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| 17.4 |
Binding Effect of Decisions. The decision or action of the Committee or the Third Party Fiduciary, as the case may be, with respect to any question arising out of or in connection with the administration, interpretation, and application of the Plan (and the Trust Agreement to the extent provided for in Article 17.2) and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. |
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| 17.5 |
Indemnity by Company. The Company shall indemnify and save harmless each member of the Committee, the Third Party Fiduciary, and any employee of the Company to whom the duties of the Committee may be delegated against any and all claims, losses, damages, expenses, and liabilities arising from any action or failure to act with respect to the Plan, except in the case of fraud, gross negligence, or willful misconduct by the Committee, any of its members, the Third Party Fiduciary, or any such employee. |
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| 17.6 |
Employer Information. To enable the Committee and the Third Party Fiduciary to perform their functions, the Company shall supply full and timely information to the Committee and the Third Party Fiduciary, as the case may be, on all matters relating to the compensation of all Participants, their Retirement, death or other cause for Termination of Employment, and such other pertinent facts as the Committee or the Third Party Fiduciary may require. |
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| 17.7 |
Manner and Timing of Benefit Payments. The Committee or the Third Party Fiduciary, as the case may be, may alter, at or after Benefit Distribution, the manner and time of payments to be made to a Participant or Beneficiary from that set forth herein, if requested to do so by such Participant or Beneficiary to meet existing financial hardships, which the Committee or the Third Party Fiduciary, as the case may be, determine are the same as or similar in nature to those identified in Section 1.401(k)-1(d)(2)(iv) of the federal treasury regulations. |
| 18.1 |
Presentation of Claims. Any Participant or Beneficiary of a deceased Participant (such Participant or Beneficiary being referred to below as a “Claimant”) may deliver to the Committee a written claim for determination with respect to benefits available |
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to such Claimant from the Plan. The claim must state with particularity the determination desired by the Claimant | |
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| 18.2 |
Notification of Decision. The Committee shall consider a claim and notify the Claimant within 90 calendar days after receipt of a claim in writing: | |
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(a) |
That the Claimant’s requested determination has been made, and that the claim has been allowed in full; or |
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That the Committee has reached a conclusion contrary, in whole or in part, to the Claimant’s requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant: (i) the specific reason(s) for the denial of the claim, or any part thereof; (ii) the specific reference(s) to pertinent provisions of the Plan upon which the denial was based; (iii) a description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and (iv) an explanation of the claim review procedure set forth in Article 18.3. |
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| 18.3 |
Review of a Denied Claim. Within 60 days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant’s duly authorized representative) may file with the Third Party Fiduciary a written request for a review of the denial of the claim. Thereafter, the Claimant (or the Claimant’s duly authorized representative) may review pertinent documents, submit written comments or other documents, and request a hearing, which the Third Party Fiduciary, in its sole discretion, may grant. | |
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| 18.4 |
Decision on Review. The Third Party Fiduciary shall render its decision on review promptly, and not later than 60 days after the filing of a written request for review of a denial, unless a hearing is held or other special circumstances require additional time, in which case the Third Party Fiduciary’s decision must be rendered within 120 calendar days after such date. Such decision must be written in a manner calculated to be understood by the Claimant, and it must contain: (i) the specific reason(s) for the decision; (ii) the specific reference(s) to the pertinent Plan provisions upon which the decision was based; and (iii) such other matters as the Third Party Fiduciary deems relevant. | |
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| 18.5 |
Legal Action. A Claimant’s compliance with the foregoing provisions of this Article 18 is a mandatory prerequisite to a Claimant’s right to commence any legal action with respect to any claim for benefits under the Plan. | |
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| 19.1 |
Notice. Any notice given under the Plan shall be in writing and shall be mailed or delivered to: | |
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SOUTHWEST GAS CORPORATION |
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Executive Deferral Plan |
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Administrative Committee |
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5241 Spring Mountain Road |
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Las Vegas, NV 89102 |
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and |
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CRG Fiduciary Services, Inc. |
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633 West Fifth Street, 53rd floor |
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Los Angeles, CA 90071-2086 |
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Attn: Managing Director |
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| 19.2 |
Assignment. The Plan shall be binding upon the Company and any of its successors and assigns, and upon a Participant, Participant’s Beneficiary, assigns, heirs, executors and administrators. | |
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| 19.3 |
Governing Laws. Except to the extent that federal law applies, the Plan shall be governed by and construed under the laws of the State of Nevada. | |
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| 19.4 |
Headings. Headings in this Master Plan Document are inserted for convenience of reference only. Any conflict between such headings and the text shall be resolved in favor of the text. | |
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| 19.5 |
Gender and Number. Masculine pronouns wherever used shall include feminine pronouns and when the context dictates, the singular shall include the plural. | |
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| 19.6 |
Effect of Illegality or Invalidity. In case any provision of the Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but the Plan shall be construed and enforced as if such illegal and invalid provisions had never been inserted herein. | |
IN WITNESS WHEREOF, the Company has executed this Amended and Restated Master Plan Document this 19th day of November 2002.
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SOUTHWEST GAS CORPORATION | ||
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By | ||
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Michael O. Maffie |
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President & Chief Executive Officer |
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16
Exhibit 10.15
MASTER PLAN DOCUMENT
SOUTHWEST GAS CORPORATION DIRECTORS DEFERRAL
PLAN
Effective March 15, 1986
Amended and Restated March 15, 1989
Amended and Restated October 29, 1992
Amended Effective March 1, 1996
Amended and Restated Effective March 1, 1999
Amended and Restated November 19, 2002
TABLE OF CONTENTS
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13 |
MASTER PLAN DOCUMENT
SOUTHWEST GAS CORPORATION DIRECTORS DEFERRAL PLAN
PURPOSE
The purpose of this Plan is to provide specified benefits to Directors of SOUTHWEST GAS CORPORATION.
For purposes hereof, unless otherwise clearly apparent from the context, the words and phrases listed below shall be defined as follows:
| 1.1 |
“Account Balance” means a Participant’s individual fund comprised of Deferrals, rollovers contributions from the PriMerit Bank, Federal Savings Bank directors deferral plan and interest earnings credited thereon up to the time of Benefit Distribution. | |
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| 1.2 |
“Beneficiary” means the person or persons, or the estate of a Participant, named to receive any benefits under the Plan upon the death of a Participant. | |
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| 1.3 |
“Benefit Account Balance” shall have the meaning set forth in Article 5.3. | |
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| 1.4 |
“Benefit Distribution” means the date benefits under the Plan commence or are paid in full to a Participant, or because of his death, to his Beneficiary, which will occur within 90 days of notification to the Company of the event that gives rise to such distribution. | |
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| 1.5 |
“Board Fees” means the compensation received by a Director for serving on the Board of Directors of Southwest Gas Corporation and the committees of the board. | |
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| 1.6 |
“Board of Directors” means the Board of Directors of the Company. | |
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| 1.7 |
“Change in Control” means the first to occur of any of the following events: | |
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(a) |
Any “person” (as the term is used in Section 13 and 14(d)(2) of the Securities Exchange Act of 1934 (“Exchange Act”)) becomes a beneficial owner (as that term is used in Section 13(d) of the Exchange Act), directly or indirectly, of 50% or more of the Company’s capital stock entitled to vote in the election of directors; or |
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(b) |
During any period of not more than two consecutive years, not including any period prior to the adoption of this Plan, individuals who, at the beginning of |
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such period constitute the board of directors of the Company, and any new director (other than a director designated by a person who has entered into an agreement with the Company to effect a transaction described in clause (a) of this Article 1.8) whose election by the board of directors or nomination for election by the Company’s shareholders was approved by a vote of at least three-fourths (3/4ths) of the directors then still in office, who either were directors at the beginning of the period or whose election or nomination for election was previously approved, cease for any reason to constitute at least a majority thereof. |
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| 1.8 |
“Committee” means the administrative committee appointed by the Board of Directors to manage and administer the Plan in accordance with the provisions of the Plan. After a Change in Control, the Committee shall cease to have any powers under the Plan and all powers previously vested in the Committee under the Plan will then be vested in the Third Party Fiduciary. | |
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| 1.9 |
“Company” means Southwest Gas Corporation and any Successor Corporation. | |
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| 1.10 |
“Deferral(s)” means the amount of Board Fees and special income, as referred to in Article 3.8, transferred to the Plan accounts. | |
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| 1.11 |
“Director” means any person on the board of directors of Southwest Gas Corporation prior to a Change in Control. | |
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| 1.12 |
“Master Plan Document” means this legal instrument containing the provisions of the Plan. | |
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| 1.13 |
“Moody’s Rate” means Moody’s Seasoned Corporate Bond Rate which is an economic indicator consisting of an arithmetic average of yields of representative bonds (industrial and AAA, AA and A rated public utilities) as of January 1 prior to each Plan Year as published by Moody’s Investors Service, Inc. (or any successor thereto), or, if such index is no longer published, a substantially similar index selected by the Board of Directors. | |
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| 1.14 |
“Moody’s Composite Rate” means the average of the Moody’s Rate on January 1 for the five years prior to Benefit Distribution. |
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| 1.15 |
“Participant” means any Director who executes a Plan Agreement. | |
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| 1.16 |
“Plan” means the Director Deferral Plan of the Company evidenced by this Master Plan Document. | |
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| 1.17 |
“Plan Agreement” means the form of written agreement which is entered into from time to time, by and between the Company and a Participant. | |
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| 1.18 |
“Plan Year” means the year beginning on March 15 of each year. | |
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| 1.19 |
“Retire” or “Retirement” means the cessation of service on the Board of Directors of | |
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the Company after attaining five Years of Service, other than by death, disability or Termination of Service. |
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| 1.20 |
“Successor Corporation” means any corporation or other legal entity which is the successor to Southwest Gas Corporation, whether resulting from merger, reorganization or transfer of substantially all of the assets of Southwest Gas Corporation, regardless of whether such entity shall expressly agree to continue the Plan. |
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| 1.21 |
“Subsidiaries” means any corporation, partnership, or other organization which is at least 50 percent owned by the Company or a Subsidiary of the Company. |
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| 1.22 |
“Terminates Service” or “Termination of Service” means the cessation of service on the Board of Directors of the Company, either voluntarily or involuntarily, excluding Retirement, disability or death. |
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| 1.23 |
“Third Party Fiduciary” means an independent third party (a corporate entity with no other relationship with the Company) selected by the Company to take over the administration of the Plan upon and after a Change in Control and to determine appeals of claims denied under the Plan before and after a Change in Control pursuant to a Third Party Fiduciary Services Agreement. |
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| 1.24 |
“Third Party Fiduciary Services Agreement” means the agreement with the Third Party Fiduciary to perform services with respect to the Plan. |
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| 1.25 |
“Trust Agreement” means an agreement establishing a “grantor trust” of which the Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended (the “Code”). |
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| 1.26 |
“Trust Fund or Funds” means the assets of every kind and description held under any Trust Agreement forming a part of the Plan. |
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| 1.27 |
“Trustee” means any person or entity selected by the Company to act as trustee under any Trust Agreement at any time of reference. |
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| 1.28 |
“Years of Service” means the length of time, in discrete 12-month periods, a Participant has served on the board of directors of Southwest Gas Corporation. |
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| 2.1 |
A Director shall become eligible to participate in the Plan as of the effective date of his election as a Director. |
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| 2.2 |
Once eligible to participate in the Plan, a Director has to complete, execute and |
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return to the Committee a Plan Agreement to become a Participant in the Plan. Continued participation in the Plan is subject to compliance with any further conditions as may be established by the Committee. |
| 3.1 |
A Participant may defer up to 100 percent of his Board Fees received during a Plan Year; provided, that such Deferral exceeds $2,000 per Plan Year. |
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| 3.2 |
Prior to the commencement of each Plan Year, a Participant will advise the Committee, in writing, of his deferral commitment for the upcoming Plan Year. If a Participant fails to so advise the Committee, through no fault of the Company, he will not be permitted to defer any of his Board Fees during the upcoming Plan Year. |
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| 3.3 |
A Participant’s Deferral commitment will be exercised on a per pay period basis. |
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| 3.4 |
In the event a Director becomes a Participant in the Plan during a Plan Year, such Participant may defer up to 100 percent of the remaining portion of his Board Fees for the Plan Year. Such Participant must make his Deferral commitment by advising the Committee, in writing, at the time he elects to become a Participant in the Plan. |
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| 3.5 |
In the event a Participant defaults on his Deferral commitment, the Participant will not be allowed to make any further Deferrals during the current Plan Year and may not make any Deferrals for the subsequent Plan Year. |
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| 3.6 |
The Committee may waive for good cause the default penalty specified in Article 3.5 upon the request of the Participant. |
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| 3.7 |
The Plan will accept rollover contributions for Participants from the PriMerit Bank, Federal Savings Bank directors deferral plan. |
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| 3.8 |
A Participant who is entitled to receive cash from the cancellation of stock options granted under the 1996 Stock Incentive Plan as a result of a Change in Control may elect to defer receipt of all or a portion of such income; provided that such election is filed with the Committee at least six (6) months prior to the date such income would otherwise have become payable to the Participant. If the Participant makes such an election, such income shall not be paid to the Participant but rather shall be treated as a Deferral and added to the Participant’s Account Balance as of the date such income would otherwise have been paid to the Participant. In addition, for such election to be effective, the Participant must agree in writing that such option shall not be exercised at all after the date of the election. Notwithstanding the foregoing, a Participant’s election to defer income resulting from cancellation of an option shall terminate and the option may be exercised in accordance with its terms without regard to the election if the option would otherwise expire prior to cancellation (for example, because of the Participant’s Termination of Service) or if the agreement |
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setting forth the terms of the Change in Control is terminated prior to the closing date set forth in such agreement. |
ARTICLE 4
INTEREST, CREDITING AND VESTING
| 4.1 |
A Participant’s Account Balance at the start of a Plan Year and any Deferrals made during a Plan Year and rollover contributions from the PriMerit Bank, Federal Savings Bank directors deferral plan will earn interest annually at 150 percent of the Moody’s Rate. Interest will be credited to a Participant’s account for Deferrals made during the Plan Year, as if all Deferrals were made on the first day of the Plan Year. Interest will be credited to a Participant’s account for rollover contributions, from the date such contributions are accepted by the Plan. |
ARTICLE 5
PLAN BENEFIT PAYMENTS
| 5.1 |
A Participant’s Account Balance will be paid to the Participant as provided for under the provisions of the Plan. |
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| 5.2 |
A Participant’s Account Balance will earn interest under the provisions of Article 4.1 until the time of Benefit Distribution. |
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| 5.3 |
If a Participant is entitled to receive Plan benefit payments over a specific benefit payment period, his Account Balance at the commencement of Benefit Distribution will be credited with an amount equal to the interest such balance would have earned assuming distribution in equal monthly installments over the specific benefit payment period, at a specified interest rate, thereby creating a Benefit Account Balance. The Benefit Account Balance will then be paid to the Participant in equal monthly installments over the specific benefit payment period. |
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| 5.4 |
If there shall be a final determination by the Internal Revenue Service or a court of competent jurisdiction that the election by a Participant to defer the payment of any amount in accordance with the terms of this Plan was not effective to defer the taxation of such amount, then the Participant shall be entitled to receive a distribution of the amount determined to be taxable and the Participant’s Account Balance shall be reduced accordingly. |
ARTICLE 6
RETIREMENT AND TERMINATION BENEFIT PAYMENTS
| 6.1 |
A Participant who Retires or Terminates Service qualifies to receive his Account |
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Balance over a period of 60, 120, 180 or 240 months. The Participant shall elect the payment period; provided that written notice of such election is filed with the Committee at least one (1) year prior to his Retirement or Termination of Employment. If a Participant fails to make such election prior to the time specified, the payment period will be 240 months. |
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| 6.2 |
A Participant who has made an election under this Article may subsequently revoke such election and make another election under this Article by providing written notice to the Committee; provided, however, that only the last such election or revocation in effect on the date which is one (1) year prior to the date on which the Participant Retires or Terminates Service shall be effective. Notwithstanding the foregoing, if a Participant Retires or Terminates Service as a result of a Change in Control or within one (1) year after March 1, 1999, the date of amendment and restatement of this Plan, the foregoing provisions of this Article 6 shall be applied by substituting “six (6) months” for “one (1) year.” |
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| 6.3 |
The interest rate used to calculate the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3, will be 150 percent of the Moody’s Composite Rate. |
ARTICLE 7
PRE-RETIREMENT SURVIVOR BENEFIT PAYMENTS
| 7.1 |
Notwithstanding any elections made pursuant to Article 6, if a Participant dies while he is on the Board of Directors, his Account Balance will be paid to his Beneficiary in equal monthly installments over the 180 month survivor benefit payment period. |
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| 7.2 |
The interest rate used to determine the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3 following the Participant’s death, will be 150% of the Moody’s Composite Rate. |
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ARTICLE 8
POST-RETIREMENT SURVIVOR BENEFIT PAYMENTS
| 8.1 |
If a Participant dies after the commencement of benefit payments under Articles 6 or 9 but prior to such benefits having been paid in full, the Participant’s benefit payments will continue to be paid to the Participant’s Beneficiary through the end of the originally awarded benefit payment period, except as provided for in Article 10.7. |
6
ARTICLE 9
DISABILITY BENEFIT PAYMENTS
| 9.1 |
The Committee will, in its sole discretion, determine whether a Participant is disabled under the provisions of the Plan. |
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| 9.2 |
If a Participant is disabled within the first five Years of Service with the Company, he will receive his Account Balance in a lump sum payment at Benefit Distribution. |
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| 9.3 |
Notwithstanding any elections made pursuant to Article 6, if a Participant is disabled after five Years of Service with the Company, his Account Balance will be paid to him in equal monthly installments over the 180-month disability benefit payment period. |
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| 9.4 |
If a Participant qualifies to receive his Account Balance over the disability benefit payment period, the interest rate used to calculate the amount that will be credited to a Participant’s Account Balance, to determine his Benefit Account Balance under the provisions of Article 5.3, will be 150 percent of the Moody’s Composite Rate. |
| 10.1 |
A Participant shall have the right to designate any person as his Beneficiary to whom benefits under this Plan shall be paid in the event of the Participant’s death prior to the total distribution of his Benefit Account Balance under the Plan. If greater than 50 percent of the Benefit Account Balance is designated to a Beneficiary other than the Participant’s spouse, such Beneficiary designation must be consented to by the Participant’s spouse. Each Beneficiary designation must be in written form prescribed by the Committee and will be effective only when filed with the Committee during the Participant’s lifetime. |
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| 10.2 |
A Participant shall have the right to change the Beneficiary designation, subject to spousal consent under the provisions of Article 10.1, without the consent of any designated Beneficiary by filing a new Beneficiary designation with the Committee. The filing of a new Beneficiary designation form will cancel all Beneficiary designations previously filed. |
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| 10.3 |
The Committee shall acknowledge, in writing, receipt of each Beneficiary designation form. |
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| 10.4 |
The Committee shall be entitled to rely on the Beneficiary designation last filed by the Participant prior to his death. Any payment made in accordance with such designation shall fully discharge the Company from all further obligations with respect to the amount of such payments. |
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| 10.5 |
If a Beneficiary entitled to receive benefits under the Plan is a minor or a person declared incompetent, the Committee may direct payment of such benefits to the |
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guardian or legal representative of such minor or incompetent person. The Committee may require proof of incompetency, minority or guardianship as it may deem appropriate prior to distribution of any Plan benefits. Such distribution shall completely discharge the Committee and the Company from all liability with respect to such payments. |
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| 10.6 |
If no Beneficiary designation is in effect at the time of the Participant’s death, or if the named Beneficiary predeceased the Participant, then the Beneficiary shall be: (1) the surviving spouse; (2) if there is no surviving spouse, then his issue per stirpes; or (3) if no surviving spouse or issue, then his estate. |
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| 10.7 |
If a Beneficiary receiving benefit payments under the provisions of the Plan dies prior to the completion of the benefit payment period, the present value of the remaining benefit payments will be paid, in a lump sum amount, to the contingent Beneficiary designated by the Participant under the provisions of Article 10.1. If the Participant has failed to designate a contingent Beneficiary, the present value of the remaining benefit payments will be paid, in a lump sum amount, to the Beneficiary’s estate. The present value of the remaining benefit payments will be calculated using the same methodology, including the same interest rate, as was used to calculate the Participant’s annuity payment calculation, under Article 5.3. |
| 11.1 |
Amounts payable to a Participant shall be paid exclusively from the general assets of the Company or from the assets of a grantor trust within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code, established for use in funding executive compensation arrangements and commonly known as a “rabbi trust.” |
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| 11.2 |
The Company shall have no obligation under the Plan to a Participant or a Participant’s Beneficiary, except as provided in this Master Plan Document. |
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| 11.3 |
The Participant shall cooperate with the Committee in furnishing all information requested by the Company to facilitate the payment of his Benefit Account Balance. Such information may include the results of a physical examination if any is required for participation in the Plan. |
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| 11.4 |
Participants and their Beneficiaries, heirs, successors, and assigns shall have no legal or equitable rights, claims, or interest in any specific property or assets of the Company. No assets of the Company shall be held under any trust, or held in any way as collateral security for the fulfilling of the obligations of the Company under the Plan. Any and all of the Company’s assets shall be, and remain, the general unpledged, unrestricted assets of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise of the Company to pay money in the future, and the rights of the Participants and Beneficiaries shall be no greater than those of unsecured general creditors. It is the |
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intention of the Company that this Plan (and the Trust Funds described in Article 13.1) be unfunded for purposes of the Code. |
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| 11.5 |
There shall be deducted from each payment made under the Plan or other compensation payable to the Participant (or Beneficiary) all taxes which are required to be withheld by the Company in respect to such payment or this Plan. The Company shall have the right to reduce any payment (or other compensation) by the amount of cash sufficient to provide the amount of said taxes. |
ARTICLE 12
NO GUARANTEE OF CONTINUING DIRECTORSHIP
| 12.1 |
The Company is without power to lawfully assure a Participant continued tenure as a Director, and nothing herein constitutes a contract of continuing directorship between the Company and the Participant. |
| 13.1 |
The Company may maintain one or more Trust Funds to finance all or a portion of the benefits under the Plan by entering into one or more Trust Agreements. Any Trust Agreement is designated as, and shall constitute, a part of the Plan, and all rights which may accrue to any person under the Plan shall be subject to all the terms and provisions of such Trust Agreement. A Trustee shall be appointed by the Committee or the Board of Directors and shall have such powers as provided in the Trust Agreement. The Committee or the Board of Directors may modify any Trust Agreement, in accordance with its terms, to accomplish the purposes of the Plan and appoint a successor Trustee under the provisions of such Trust Agreement. By entering into such Trust Agreement, the Committee or the Board of Directors may vest in the Trustee, or in one or more investment managers (as defined in ERISA) the power to manage and control the Trust Fund. The Committee’s authority under the provisions of this Article 13.1 will cease with a Change in Control. |
ARTICLE 14
TERMINATION, AMENDMENT OR MODIFICATION OF THE PLAN
| 14.1 |
The Board of Directors may at any time, without notice, amend or modify the Plan in whole or in part; provided, however, that (i) no amendment shall be effective to decrease or restrict (a) the amount of interest to be credited under the provisions of the Plan, (b) the benefits the Participant qualifies for or may elect to receive under the provisions of the Plan, or (c) benefit payments to Participants or Beneficiaries once such payments have commenced, and (ii) effective March 1,1999, no amendment or modification of this Article 14, Article 16, or Article 17 of the Plan |
9
| . |
shall be effective. |
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| 14.2 |
The Board of Directors shall not terminate the Plan until all accrued benefits have been paid in full under the provisions of the Plan to the Participants and Beneficiaries. |
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| 14.3 |
The Board of Directors may partially terminate the Plan by instructing the Committee not to accept any additional Deferral commitments. In the event of a partial termination, the remaining provisions of the Plan shall continue to operate and be effective for all Participants in the Plan, as of the date of such partial termination. |
ARTICLE 15
RESTRICTIONS ON ALIENATION OF BENEFITS
| 15.1 |
To the maximum extent permitted by law, no interest or benefit under the Plan shall be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind. |
ARTICLE 16
ADMINISTRATION OF THE PLAN
| 16.1 |
Except as otherwise provided in this Article 16, and subject to Article 17, the general administration of the Plan, as well as construction and interpretation thereof, shall be vested in the Committee. Members of the Committee may be Participants under the Plan. Specifically, the Committee shall have the discretion and authority to: (a) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan; and (b) decide or resolve any and all questions including interpretations of the Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. The number of members of the Committee shall be established by, and the members shall be appointed from time to time by, and shall serve at the pleasure of, the Board of Directors. |
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| 16.2 |
Upon and after a Change in Control, the administration of the Plan shall be vested in a Third Party Fiduciary, as provided for herein and pursuant to the terms of a Third Party Fiduciary Services Agreement. Any Third Party Fiduciary Services Agreement is designated as, and shall constitute, a part of the Plan. The Third Party Fiduciary shall also have the discretion and authority to: (a) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan; and (b) decide or resolve any and all questions including interpretation of the Plan and the Trust Agreement. Except as otherwise provided for in any Trust Agreement, the Third Party Fiduciary shall have no power to direct the investment of Plan or Trust Funds or select any investment manager or custodial firm for the Plan or Trust Agreement. The Company shall pay all reasonable administrative |
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expenses and fees of the Third Party Fiduciary when it acts as the administrator of the Plan or pursuant to Article 17. The Third Party Fiduciary may not be terminated by the Company without the consent of 50% of the Participants in the Plan. |
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| 16.3 |
In the administration of the Plan, the Committee or the Third Party Fiduciary, as the case may be, may from time to time employ such agents, consultants, advisors, and managers as it deems necessary or useful in carrying out its duties as it sees fit (including acting through a duly authorized representative) and may from to time to time consult with counsel to the Company. |
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| 16.4 |
The decision or action of the Committee or the Third Party Fiduciary, as the case may be, with respect to any question arising out of or in connection with the administration, interpretation, and application of the Plan (and the Trust Agreement to the extent provided for in Article 16.2) and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. |
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| 16.5 |
The Company shall indemnify and save harmless each member of the Committee, the Third Party Fiduciary, and any employee of the Company to whom the duties of the Committee may be delegated against any and all claims, losses, damages, expenses, and liabilities arising from any action or failure to act with respect to the Plan, except in the case of fraud, gross negligence, or willful misconduct by the Committee, any of its members, the Third Party Fiduciary, or any such employee. |
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| 16.6 |
To enable the Committee and the Third Party Fiduciary to perform their functions, the Company shall supply full and timely information to the Committee and the Third Party Fiduciary, as the case may be, on all matters relating to the compensation of all Participants, their Retirement, death or other cause for Termination of Employment, and such other pertinent facts as the Committee or the Third Party Fiduciary may require. |
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| 16.7 |
The Committee or the Third Party Fiduciary, as the case may be, may alter, at or after Benefit Distribution, the manner and time of payments to be made to a Participant or Beneficiary from that set forth herein, if requested to do so by such Participant or Beneficiary to meet existing financial hardships, which the Committee or the Third Party Fiduciary, as the case may be, determine are the same as or similar in nature to those identified in Section 1.401(k)-1(d)(2)(iv) of the federal treasury regulations. |
| 17.1 |
Any Participant or Beneficiary of a deceased Participant (such Participant or Beneficiary being referred to below as a “Claimant”) may deliver to the Committee a written claim for determination with respect to benefits available to such Claimant from the Plan. The claim must state with particularity the determination desired by the Claimant. |
11
| 17.2 |
The Committee shall consider a claim and notify the Claimant within 90 calendar days after receipt of a claim in writing: | |
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(a) |
That the Claimant’s requested determination has been made, and that the claim has been allowed in full; or |
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(b) |
That the Committee has reached a conclusion contrary, in whole or in part, to the Claimant’s requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant: (i) the specific reason(s) for the denial of the claim, or any part thereof; (ii) the specific reference(s) to pertinent provisions of the Plan upon which the denial was based; (iii) a description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and (iv) an explanation of the claim review procedure set forth in Article 17.3. |
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| 17.3 |
Within 60 days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant’s duly authorized representative) may file with the Third Party Fiduciary a written request for a review of the denial of the claim. Thereafter, the Claimant (or the Claimant’s duly authorized representative) may review pertinent documents, submit written comments or other documents, and request a hearing, which the Third Party Fiduciary, in its sole discretion, may grant. | |
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| 17.4 |
The Third Party Fiduciary shall render its decision on review promptly, and not later than 60 days after the filing of a written request for review of a denial, unless a hearing is held or other special circumstances require additional time, in which case the Third Party Fiduciary’s decision must be rendered within 120 calendar days after such date. Such decision must be written in a manner calculated to be understood by the Claimant, and it must contain: (i) the specific reason(s) for the decision; (ii) the specific reference(s) to the pertinent Plan provisions upon which the decision was based; and (iii) such other matters as the Third Party Fiduciary deems relevant. | |
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| 17.5 |
A Claimant’s compliance with the foregoing provisions of this Article 17 is a mandatory prerequisite to a Claimant’s right to commence any legal action with respect to any claim for benefits under the Plan. | |
| 18.1 |
Any notice given under the Plan shall be in writing and shall be mailed or delivered to: |
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SOUTHWEST GAS CORPORATION |
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Directors Deferral Plan |
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Administrative Committee |
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5241 Spring Mountain Road |
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Las Vegas, NV 89102 |
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and |
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CRG Fiduciary Services, Inc. |
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633 West Fifth Street, 53rd floor |
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Los Angeles, CA 90071-2086 |
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Attn: Managing Director |
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| 18.2 |
The Plan shall be binding upon the Company and any of its successors and assigns, and upon a Participant, Participant’s Beneficiary, assigns, heirs, executors and administrators. | |
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| 18.3 |
The Plan shall be governed by and construed under the laws of the State of Nevada. | |
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| 18.4 |
Headings in this Master Plan Document are inserted for convenience of reference only. Any conflict between such headings and the text shall be resolved in favor of the text. | |
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| 18.5 |
Masculine pronouns wherever used shall include feminine pronouns and when the context dictates, the singular shall include the plural. | |
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| 18.6 |
In case any provision of the Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but the Plan shall be construed and enforced as if such illegal and invalid provisions had never been inserted herein. | |
IN WITNESS WHEREOF, the Company has executed this Amended and Restated Master Plan Document this 19th day of November 2002.
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SOUTHWEST GAS CORPORATION | ||
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By |
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Michael O. Maffie |
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13
EXHIBIT 10.16
LEASE SUPPLEMENT (FIRST RENEWAL)
LEASE SUPPLEMENT (FIRST RENEWAL) dated as of December 12, 2002 between US Bank Trust National Association, as successor trustee to Valley Bank of Nevada, not in its corporate capacity but solely as Owner Trustee (the “Lessor”), and SOUTHWEST GAS CORPORATION, a California Corporation (the “Lessee”).
INTRODUCTION
Lessee and Lessor have heretofore entered into a Project Lease Agreement dated as of July 1, 1982 (herein, as heretofore or hereafter amended, modified or supplemented in accordance with the provisions thereof, the “Lease”).
The Lease has been recorded on August 11, 1982 in Book 36, Page 435 under File No. 127089 in the office of the County Recorder of Pershing County, Nevada, and on November 12, 1982 in Book 1803, Page 406 under File No. 823985 in the office of the Counter Recorder of Washoe County, Nevada, and in Book 213, Page 857 under File No. 192481 in the office of the County Recorder of Churchill County, Nevada.
On July 2, 2002, pursuant to clause (i) of Section 24(b) (Renewal Option) of the Lease, Lessee provided notice to Lessor of Lessee’s election to exercise its option to renew the Lease for one 2.5 year term, commencing on January 6, 2003 and ending on July 6, 2005, with semi-annual Project Rent for the Project equal to one half of the average amount of the semi-annual Project Rent paid by the Lessee during the Basic Term of the Lease.
Pursuant to such election, the Lessor has requested that Lessee execute and deliver to the Lessor this Lease Supplement (First Renewal).
Pursuant to Section 28 of the Lease, the Lessor has requested that Lessee cause a counterpart of this Lease Supplement (First Renewal) to be recorded and filed.
NOW THEREFORE, in consideration of the premises and other and good and sufficient consideration, and pursuant to clause (i) of Section 24 (b) (Renewal Option) of the Lease, Lessor and Lessee hereby agree as follows:
1. The Term of the Lease of the Project is extended to include one 2.5 year renewal term, commencing on January 6, 2003 and ending on July 6, 2005 (the “First Renewal Term”).
2. The Rent Payment Dates during the First Renewal Term are January 6, 2003, July 6, 2003, January 6, 2004, July 6, 2004, and January 6, 2005.
3. The Lessee shall pay to Lessor in advance on each Rent Payment Date during the First Renewal Term semi-annual Project Rent in the amount of $1,668,644.57
(One Million, Six Hundred and Sixty-Eight Thousand, Six Hundred and Forty-Four Dollars and Fifty-Seven Cents).
4. The Stipulated Loss Value of the Facility during the renewal Term is equal to 20% of the Facility Cost and the Stipulated Loss Value of the Pipeline during the renewal Term is equal 20% of the Pipeline Cost.
5. This Lease Supplement (First Renewal) is supplemental to the Lease. As supplemented by this Lease Supplement (First Renewal), the Lease is in all respects ratified, approved and confirmed, and the Lease and this Lease Supplement (First Renewal) shall together constitute one and the same instrument.
6. This Lease Supplement (First Renewal) is being executed in more than one counterpart, each of which shall be deemed an original, but all such counterparts together constitute but one and the same instrument. To the extent, if any, that this Lease Supplement (First Renewal) constitutes chattel paper (as such term in defined in the Uniform Commercial Code as in effect in any applicable jurisdiction), no security interest in this Lease Supplement (First Renewal) may be created by the transfer or possession of any counterpart thereof other than the counterpart containing the receipt therefor executed by Owner Trustee on or immediately following the signature page thereof.
7. The Lessee represents that as of the date of this Lease Supplement (First Renewal) no Event of Default has occurred and is continuing.
IN WITNESS WHEREOF, Lessee and Lessor have caused this Lease Supplement (First Renewal) to be duly executed and their corporate seals to be hereunto affixed and attested by their respective officers thereunto duly authorized to be effective as of the day and year first above written.
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LESSEE: |
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SOUTHWEST GAS CORPORATION |
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By: |
/s/ JEFFREY W. SHAW |
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Name: |
Jeffrey W. Shaw |
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Title: |
Senior Vice President/Gas Resources and Pricing |
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-2-
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LESSOR: |
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US BANK TRUST NATIONAL ASSOCIATION, as Owner Trustee |
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By: |
/s/ JULIA HOMMEL |
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Name: |
Julia Hommel |
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Title: |
Assistant Vice President |
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RECEIVED BY US BANK TRUST NATIONAL ASSOCIATION, as Owner Trustee |
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Receipt Acknowledged |
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By: |
/s/ JULIA HOMMEL |
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Name: |
Julia Hommel |
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Title: |
Assistant Vice President |
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Date: |
December 16, 2002 |
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The undersigned hereby authorizes and directs US Bank National Association, in its capacity as Owner Trustee as aforesaid, to enter into the foregoing instrument. | |||
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OWNER PARTICIPANT |
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PSEG RESOURCES INC. |
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By: |
/s/ EILEEN A. MORAN |
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Name: |
Eileen A. Moran |
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Title: |
President |
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-3-
Exhibit 12.01
SOUTHWEST GAS CORPORATION
COMPUTATION OF RATIOS OF EARNINGS TO FIXED
CHARGES
(Thousands of dollars)
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For the Year Ended December 31, |
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2002 |
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2001 |
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2000 |
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1999 |
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1998 |
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| 1. Fixed charges: |
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A) Interest expense |
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$ |
79,586 |
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$ |
80,139 |
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$ |
70,659 |
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$ |
63,110 |
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$ |
63,416 |
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B) Amortization |
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2,278 |
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1,886 |
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1,564 |
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1,366 |
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1,243 |
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C) Interest portion of rentals |
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8,846 |
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9,346 |
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8,572 |
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8,217 |
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7,531 |
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D) Preferred securities distributions |
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5,475 |
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5,475 |
|
|
5,475 |
|
|
5,475 |
|
|
5,475 |
| |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| |
Total fixed charges |
|
$ |
96,185 |
|
$ |
96,846 |
|
$ |
86,270 |
|
$ |
78,168 |
|
$ |
77,665 |
| |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| 2. Earnings (as defined): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| |
E) Pretax income from continuing operations |
|
$ |
65,382 |
|
$ |
56,741 |
|
$ |
51,939 |
|
$ |
60,955 |
|
$ |
83,951 |
| |
| |
Fixed Charges (1. above) |
|
|
96,185 |
|
|
96,846 |
|
|
86,270 |
|
|
78,168 |
|
|
77,665 |
| |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| |
Total earnings as defined |
|
$ |
161,567 |
|
$ |
153,587 |
|
$ |
138,209 |
|
$ |
139,123 |
|
$ |
161,616 |
| |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| 3. Ratio of earnings to fixed charges |
|
|
1.68 |
|
|
1.59 |
|
|
1.60 |
|
|
1.78 |
|
|
2.08 |
| ||
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Exhibit 13
Financial Information
| Consolidated Selected Financial Statistics |
40 | |
| Natural Gas Operations |
41 | |
| Management’s Discussion and Analysis |
42 | |
| Consolidated Balance Sheets |
58 | |
| Consolidated Statements of Income |
60 | |
| Consolidated Statements of Cash Flows |
61 | |
| Consolidated Statements of Stockholders’ Equity |
62 | |
| Notes to Consolidated Financial Statements |
63 | |
| Report of Independent Accountants |
84 | |
39
Consolidated Selected Financial Statistics
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
1999 |
1998 |
|||||||||||||||
| (thousands of dollars, except per share amounts) |
||||||||||||||||||||
| Operating revenues |
$ |
1,320,909 |
|
$ |
1,396,688 |
|
$ |
1,034,087 |
|
$ |
936,866 |
|
$ |
917,309 |
| |||||
| Operating expenses |
|
1,174,410 |
|
|
1,262,705 |
|
|
905,457 |
|
|
805,654 |
|
|
763,139 |
| |||||
| Operating income |
$ |
146,499 |
|
$ |
133,983 |
|
$ |
128,630 |
|
$ |
131,212 |
|
$ |
154,170 |
| |||||
| Net income |
$ |
43,965 |
|
$ |
37,156 |
|
$ |
38,311 |
|
$ |
39,310 |
|
$ |
47,537 |
| |||||
| Total assets at year end |
$ |
2,377,928 |
|
$ |
2,369,612 |
|
$ |
2,232,337 |
|
$ |
1,923,442 |
|
$ |
1,830,694 |
| |||||
| Capitalization at year end |
||||||||||||||||||||
| Common equity |
$ |
596,167 |
|
$ |
561,200 |
|
$ |
533,467 |
|
$ |
505,425 |
|
$ |
476,400 |
| |||||
| Preferred securities |
|
60,000 |
|
|
60,000 |
|
|
60,000 |
|
|
60,000 |
|
|
60,000 |
| |||||
| Long-term debt |
|
1,092,148 |
|
|
796,351 |
|
|
896,417 |
|
|
859,291 |
|
|
812,906 |
| |||||
| $ |
1,748,315 |
|
$ |
1,417,551 |
|
$ |
1,489,884 |
|
$ |
1,424,716 |
|
$ |
1,349,306 |
| ||||||
| Common stock data |
||||||||||||||||||||
| Return on average common equity |
|
7.5 |
% |
|
6.8 |
% |
|
7.4 |
% |
|
8.0 |
% |
|
11.0 |
% | |||||
| Earnings per share |
$ |
1.33 |
|
$ |
1.16 |
|
$ |
1.22 |
|
$ |
1.28 |
|
$ |
1.66 |
| |||||
| Diluted earnings per share |
$ |
1.32 |
|
$ |
1.15 |
|
$ |
1.21 |
|
$ |
1.27 |
|
$ |
1.65 |
| |||||
| Dividends paid per share |
$ |
0.82 |
|
$ |
0.82 |
|
$ |
0.82 |
|
$ |
0.82 |
|
$ |
0.82 |
| |||||
| Payout ratio |
|
62 |
% |
|
71 |
% |
|
67 |
% |
|
64 |
% |
|
49 |
% | |||||
| Book value per share at year end |
$ |
17.91 |
|
$ |
17.27 |
|
$ |
16.82 |
|
$ |
16.31 |
|
$ |
15.67 |
| |||||
| Market value per share at year end |
$ |
23.45 |
|
$ |
22.35 |
|
$ |
21.88 |
|
$ |
23.00 |
|
$ |
26.63 |
| |||||
| Market value per share to book value per share |
|
131 |
% |
|
129 |
% |
|
130 |
% |
|
141 |
% |
|
170 |
% | |||||
| Common shares outstanding at year end (000) |
|
33,289 |
|
|
32,493 |
|
|
31,710 |
|
|
30,985 |
|
|
30,410 |
| |||||
| Number of common shareholders at year end |
|
22,119 |
|
|
23,243 |
|
|
24,092 |
|
|
22,989 |
|
|
24,489 |
| |||||
| Ratio of earnings to fixed charges |
|
1.68 |
|
|
1.59 |
|
|
1.60 |
|
|
1.78 |
|
|
2.08 |
| |||||
40
Natural Gas Operations
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
1999 |
1998 |
|||||||||||||||
| (thousands of dollars) |
||||||||||||||||||||
| Sales |
$ |
1,069,917 |
|
$ |
1,149,918 |
|
$ |
816,358 |
|
$ |
740,900 |
|
$ |
753,338 |
| |||||
| Transportation |
|
45,983 |
|
|
43,184 |
|
|
54,353 |
|
|
50,255 |
|
|
46,259 |
| |||||
| Operating revenue |
|
1,115,900 |
|
|
1,193,102 |
|
|
870,711 |
|
|
791,155 |
|
|
799,597 |
| |||||
| Net cost of gas sold |
|
563,379 |
|
|
677,547 |
|
|
394,711 |
|
|
330,031 |
|
|
329,849 |
| |||||
| Operating margin |
|
552,521 |
|
|
515,555 |
|
|
476,000 |
|
|
461,124 |
|
|
469,748 |
| |||||
| Expenses |
||||||||||||||||||||
| Operations and maintenance |
|
264,188 |
|
|
253,026 |
|
|
231,175 |
|
|
221,258 |
|
|
209,172 |
| |||||
| Depreciation and amortization |
|
115,175 |
|
|
104,498 |
|
|
94,689 |
|
|
88,254 |
|
|
80,231 |
| |||||
| Taxes other than income taxes |
|
34,565 |
|
|
32,780 |
|
|
29,819 |
|
|
27,610 |
|
|
31,646 |
| |||||
| Operating income |
$ |
138,593 |
|
$ |
125,251 |
|
$ |
120,317 |
|
$ |
124,002 |
|
$ |
148,699 |
| |||||
| Contribution to consolidated net income |
$ |
39,228 |
|
$ |
32,626 |
|
$ |
33,908 |
|
$ |
35,473 |
|
$ |
44,830 |
| |||||
| Total assets at year end |
$ |
2,290,407 |
|
$ |
2,289,111 |
|
$ |
2,154,641 |
|
$ |
1,855,114 |
|
$ |
1,772,418 |
| |||||
| Net gas plant at year end |
$ |
1,979,459 |
|
$ |
1,825,571 |
|
$ |
1,686,082 |
|
$ |
1,581,102 |
|
$ |
1,459,362 |
| |||||
| Construction expenditures and property additions |
$ |
263,576 |
|
$ |
248,352 |
|
$ |
205,161 |
|
$ |
207,773 |
|
$ |
179,361 |
| |||||
| Cash flow, net |
||||||||||||||||||||
| From operating activities |
$ |
281,329 |
|
$ |
103,848 |
|
$ |
109,872 |
|
$ |
165,220 |
|
$ |
189,465 |
| |||||
| From investing activities |
|
(243,373 |
) |
|
(246,462 |
) |
|
(203,325 |
) |
|
(207,024 |
) |
|
(176,731 |
) | |||||
| From financing activities |
|
(49,187 |
) |
|
154,727 |
|
|
95,481 |
|
|
40,674 |
|
|
(12,632 |
) | |||||
| Net change in cash |
$ |
(11,231 |
) |
$ |
12,113 |
|
$ |
2,028 |
|
$ |
(1,130 |
) |
$ |
102 |
| |||||
| Total throughput (thousands of therms) | ||||||||||||||||||||
| Sales |
|
1,214,041 |
|
|
1,261,263 |
|
|
1,107,674 |
|
|
1,037,409 |
|
|
1,103,264 |
| |||||
| Transportation |
|
1,325,149 |
|
|
1,268,203 |
|
|
1,482,700 |
|
|
1,186,859 |
|
|
1,001,372 |
| |||||
| Total throughput |
|
2,539,190 |
|
|
2,529,466 |
|
|
2,590,374 |
|
|
2,224,268 |
|
|
2,104,636 |
| |||||
| Weighted average cost of gas purchased ($/therm) |
$ |
0.38 |
|
$ |
0.55 |
|
$ |
0.42 |
|
$ |
0.28 |
|
$ |
0.27 |
| |||||
| Customers at year end |
|
1,455,000 |
|
|
1,397,000 |
|
|
1,337,000 |
|
|
1,274,000 |
|
|
1,209,000 |
| |||||
| Employees at year end |
|
2,546 |
|
|
2,507 |
|
|
2,491 |
|
|
2,482 |
|
|
2,429 |
| |||||
| Degree days – actual |
|
1,912 |
|
|
1,963 |
|
|
1,938 |
|
|
1,928 |
|
|
2,321 |
| |||||
| Degree days – ten-year average |
|
1,963 |
|
|
1,970 |
|
|
1,991 |
|
|
2,031 |
|
|
2,043 |
| |||||
41
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
The following discussion of Southwest Gas Corporation and subsidiaries (the Company) includes information related to regulated natural gas transmission and distribution activities and non-regulated activities.
The Company is comprised of two business segments: natural gas operations (Southwest or the natural gas operations segment) and construction services. Southwest is engaged in the business of purchasing, transporting, and distributing natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor and transporter of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.
As of December 31, 2002, Southwest had 1,455,000 residential, commercial, industrial, and other customers, of which 812,000 customers were located in Arizona, 511,000 in Nevada, and 132,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2002, Southwest added 58,000 customers, a four percent increase, of which 27,000 customers were added in Arizona, 26,000 in Nevada, and 5,000 in California. Customer growth over the past three years averaged nearly five percent annually. These additions are largely attributed to population growth in the service areas. Based on current commitments from builders, customer growth is expected to approximate four percent in 2003. During 2002, 56 percent of operating margin was earned in Arizona, 36 percent in Nevada, and 8 percent in California. During this same period, Southwest earned 83 percent of operating margin from residential and small commercial customers, 7 percent from other sales customers, and 10 percent from transportation customers. These patterns are expected to continue.
Northern Pipeline Construction Co. (Northern or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor which provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
CAPITAL RESOURCES AND LIQUIDITY
The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.
Southwest continues to experience significant customer growth. This growth has required significant capital outlays for new transmission and distribution plant, to keep up with consumer demand. During the three-year period ended December 31, 2002, total gas plant increased from $2.2 billion to $2.8 billion, or at an annual rate of eight percent. Customer growth was the primary reason for the plant increase as Southwest added 181,000 net new customers during the three-year period. Southwest expects that customer growth will approximate four percent in 2003.
42
During 2002, capital expenditures for the natural gas operations segment were $264 million. Approximately 66 percent of these current-period expenditures represented new construction and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant. The percentage related to replacement costs was higher, when compared to recent years, due, in large part, to the undertaking of pipeline replacement projects and the upgrading of Company-wide computer applications. Cash flows from operating activities of Southwest (net of dividends) provided $254 million of the required capital resources pertaining to total construction expenditures in 2002. The remainder was provided from external financing activities. Operating cash flows were favorably impacted by changes in the purchased gas adjustment (PGA) recovery rates resulting in the collection of previously deferred purchased gas costs from customers (totaling approximately $110 million) and general rate relief.
Asset Purchases and Sales
In January 2002, the Company sold all of its interests in undeveloped property located in northern Arizona. The property was originally acquired as a potential site for underground natural gas storage during the gas supply shortages of the 1970s, but was never developed. The sale resulted in a one-time pre-tax gain of $8.9 million, which was recognized in the first quarter of 2002.
In June 2002, the Company announced an agreement to purchase Black Mountain Gas Company (BMG), a gas utility serving Cave Creek and Page, Arizona. BMG has approximately 7,300 natural gas customers in a rapidly growing area north of Phoenix, Arizona. Regulatory approvals by the Arizona Corporation Commission (ACC) and the Securities and Exchange Commission (SEC) are needed to consummate the purchase, which is expected to be completed in the second quarter of 2003. The acquisition will be financed using existing credit facilities.
2002 Financing Activity
In May 2002, the Company issued $200 million in Senior Unsecured Notes, due 2012, bearing interest at 7.625%. The net proceeds from the sale of the Senior Unsecured Notes were used to redeem the $100 million 9¾% Debentures, Series F, in June 2002, and to reduce outstanding revolving credit loans.
In May 2002, the Company replaced the existing $350 million revolving credit facility that was to expire in June 2002 with a $125 million three-year facility and a $125 million 364-day facility. Of the total $250 million facility, $100 million is designated as long-term debt. Interest rates for the new facility are calculated at either London Interbank Offering Rate (LIBOR) plus or minus a competitive margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate.
In October 2002, the Company entered into a $50 million commercial paper program. Any issuance under the commercial paper program would be supported by the Company’s current revolving credit facility and, therefore, does not represent new borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the new program are calculated at the then current commercial paper rate.
In March 2002, the Job Creation and Worker Assistance Act of 2002 (Act) was signed into law. This Act provides a three-year, 30 percent “bonus” tax depreciation deduction for businesses. Southwest
43
estimates the bonus depreciation deduction will reduce federal income taxes paid by approximately $50 million over its three-year term, including $40 million over the next two years (2003-2004).
2003 Construction Expenditures and Financing
Southwest estimates construction expenditures during the three-year period ending December 31, 2005 will be approximately $675 million. Of this amount, $240 million are expected to be incurred in 2003. During the three-year period, cash flow from operating activities (net of dividends) is estimated to fund approximately 75 percent of the gas operations total construction expenditures, including the impacts of the Act. The Company expects to raise $55 million to $60 million from its Dividend Reinvestment and Stock Purchase Plan (DRSPP). The remaining cash requirements are expected to be provided by other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing. Southwest has a total of $200 million in securities registered with the SEC which are available for future financing needs.
The Company is pursuing the issuance of $165 million of Clark County, Nevada Industrial Development Revenue Bonds (IDRBs). The net proceeds from the sale of the bonds will be used, in part, to refinance the $30 million 7.30% 1992 Series A, due 2027 and the $100 million 7.50% 1992 Series B, due 2032 fixed-rate IDRBs. The remainder of the proceeds will be used to finance construction expenditures in southern Nevada.
Off Balance Sheet Arrangements and Contractual Obligations
All Company debt is recorded on its balance sheets. The Company has long-term operating leases, which are described in Note 2 – Utility Plant of the Notes to Consolidated Financial Statements. No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain customary leverage, net worth and other covenants, and securities ratings covenants that, if set in motion, would increase financing costs. To date, the Company has not incurred any increased financing costs as a result of these covenants. Estimated maturities of long-term debt for the next five years are provided in Note 6 – Long-Term Debt of the Notes to Consolidated Financial Statements.
The Company does not currently utilize stand-alone derivative instruments for speculative purposes or for hedging and does not have foreign currency exposure. None of the Company’s long-term financial instruments or other contracts are derivatives, or contain embedded derivatives with significant mark-to-market value. Southwest has fixed-price gas purchase contracts, which are considered normal purchases occurring in the ordinary course of business. These gas purchase contracts are entered into annually to mitigate market price volatility. During 2002, Southwest entered into approximately 50 fixed-price gas purchase contracts for the 2002/2003 supply portfolio period (November through October). These fixed-price gas purchase contracts were for approximately 55 million dekatherms, or approximately 50 percent, of the forecasted normal weather requirement for the 2002/2003 supply portfolio period. The purchase price for these contracts range from $2.67 to $4.82 per dekatherm.
44
The Company’s pension and related benefits plans utilize various assumptions which impact the expense and funding levels of these plans. The Company is lowering the expected rate of return on plan assets assumption for these plans from 9.25% to 8.95% for 2003. The lower rate of return reflects anticipated investment returns on a long-term basis considering asset mix and historical investment returns. This change, coupled with reductions in the discount rate and salary increase assumptions, will result in a $1.5 million increase in pension expense for 2003. In addition, pension plan funding is expected to increase from $5.1 million in 2002 to approximately $11.2 million in 2003. The increase is primarily due to lower-than-expected returns on plan assets during 2002.
Liquidity
Liquidity refers to the ability of an enterprise to generate adequate amounts of cash to meet its cash requirements. Several general factors that could significantly affect capital resources and liquidity in future years include inflation, growth in the economy, changes in income tax laws, changes in the ratemaking policies of regulatory commissions, interest rates, the level of natural gas prices, and the level of Company earnings.
The rate schedules in all of the service territories of Southwest contain PGA clauses which permit adjustments to rates as the cost of purchased gas changes. The PGA mechanism allows Southwest to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service. On an interim basis, Southwest generally defers over or under collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2002, the combined balances in PGA accounts totaled an over-collection of $27 million versus an under-collection of $84 million at December 31, 2001. Recently approved PGA filings have reduced rates in Arizona and Nevada. See PGA Filings for more information on these and other PGA filings. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances. Southwest has a total short-term borrowing capacity of $150 million (with $97 million available at December 31, 2002), which the Company believes is adequate to meet anticipated needs.
In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments are designed to provide a more timely recovery of gas costs and to send appropriate pricing signals to customers. In Nevada, tariffs provide for annual adjustment dates for changes in purchased gas costs. In addition, Southwest may request to adjust rates more often, if conditions warrant. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. See Rates and Regulatory Proceedings for details of these filings.
PGA changes affect cash flows but have no direct impact on profit margin. In addition, since Southwest is permitted to accrue interest on PGA balances, the cost of incremental, PGA-related short-term borrowings will be offset, and there should be no material negative impact to earnings. However, gas
45
cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions and Other income (deductions).
The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend was 20.5 cents per share throughout 2002. The dividend of 20.5 cents per share has been paid quarterly since September 1994.
In August 2002, the Company registered additional shares of common stock with the SEC for issuance under both the Employees’ Investment Plan and the DRSPP. The amounts of additional shares registered for each plan were 400,000 and 800,000, respectively.
Security Ratings
Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., the better the rating, the lower the cost to borrow funds).
Since January 1997, Moody’s Investors Service, Inc. (Moody’s) has rated Company unsecured long-term debt at Baa2. Moody’s debt ratings range from Aaa (best quality) to C (lowest quality). Moody’s applies a Baa2 rating to obligations which are considered medium grade obligations (i.e., they are neither highly protected nor poorly secured).
The Company’s unsecured long-term debt rating from Fitch, Inc. (Fitch) is BBB. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB indicates a credit quality that is considered prudent for investment.
The Company’s unsecured long-term debt rating from Standard and Poor’s Ratings Services (S&P) is BBB-. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB- indicates the debt is regarded as having an adequate capacity to pay interest and repay principal.
A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency.
Inflation
Results of operations are impacted by inflation. Natural gas, labor, and construction costs are the categories most significantly impacted by inflation. Changes to cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor is a component of the cost
46
of service, and construction costs are the primary component of rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.
2003 Redemption of Shareholder Rights
In January 2003, the Company announced that the Board of Directors had undertaken a review of the Company’s Amended and Restated Rights Agreement and determined to redeem the rights associated therewith. The redemption price of $0.01 per right was paid on March 3, 2003 to shareholders of record as of February 18, 2003. As a result of this redemption, the shareholders will no longer be able to exercise such rights and, in the future, rights will no longer attach to issuances of the Company’s common stock.
CONSOLIDATED RESULTS OF OPERATIONS
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 | ||||||
| (thousands of dollars, except per share amounts) |
|||||||||
| Contribution to net income |
|||||||||
| Natural gas operations |
$ |
39,228 |
$ |
32,626 |
$ |
33,908 | |||
| Construction services |
|
4,737 |
|
4,530 |
|
4,403 | |||
| Net income |
$ |
43,965 |
$ |
37,156 |
$ |
38,311 | |||
| Basic earnings per share |
|||||||||
| Natural gas operations |
$ |
1.19 |
$ |
1.02 |
$ |
1.08 | |||
| Construction services |
|
0.14 |
|
0.14 |
|
0.14 | |||
| Consolidated |
$ |
1.33 |
$ |
1.16 |
$ |
1.22 | |||
See separate discussions at Results of Natural Gas Operations and Results of Construction Services. Average shares outstanding increased by 831,000 shares between 2002 and 2001, and 751,000 shares between 2001 and 2000, primarily resulting from continuing issuances under the DRSPP.
47
RESULTS OF NATURAL GAS OPERATIONS
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
|||||||
| (thousands of dollars) |
||||||||||
| Gas operating revenues |
$ |
1,115,900 |
$ |
1,193,102 |
$ |
870,711 |
| |||
| Net cost of gas sold |
|
563,379 |
|
677,547 |
|
394,711 |
| |||
| Operating margin |
|
552,521 |
|
515,555 |
|
476,000 |
| |||
| Operations and maintenance expense |
|
264,188 |
|
253,026 |
|
231,175 |
| |||
| Depreciation and amortization |
|
115,175 |
|
104,498 |
|
94,689 |
| |||
| Taxes other than income taxes |
|
34,565 |
|
32,780 |
|
29,819 |
| |||
| Operating income |
|
138,593 |
|
125,251 |
|
120,317 |
| |||
| Other income (expense) |
|
3,108 |
|
7,694 |
|
(1,765 |
) | |||
| Income before interest and income taxes |
|
141,701 |
|
132,945 |
|
118,552 |
| |||
| Net interest deductions |
|
78,505 |
|
78,746 |
|
68,892 |
| |||
| Preferred securities distributions |
|
5,475 |
|
5,475 |
|
5,475 |
| |||
| Income tax expense |
|
18,493 |
|
16,098 |
|
10,277 |
| |||
| Contribution to consolidated net income |
$ |
39,228 |
$ |
32,626 |
$ |
33,908 |
| |||
2002 vs. 2001
The gas segment contribution to consolidated net income for 2002 increased $6.6 million from 2001. Growth in operating margin was partially offset by higher operating costs and a decline in other income (expense).
Operating margin, defined as operating revenues less the cost of gas sold, increased $37 million, or seven percent, in 2002 as compared to 2001. The increase was a result of rate relief and customer growth, partially offset by the impacts of warm weather between periods. General rate relief granted during the fourth quarter of 2001, in both Arizona and Nevada, increased operating margin by $33 million. Southwest added 58,000 customers during the last 12 months, an increase of four percent. New customers contributed $20 million in incremental margin. Differences in heating demand caused by weather variations between periods and conservation resulted in a $16 million margin decrease. Warmer-than-normal temperatures were experienced during the second and fourth quarters of 2002, whereas during 2001, temperatures were relatively normal.
Operations and maintenance expense increased $11.2 million, or four percent, reflecting general increases in labor and maintenance costs, and incremental costs associated with servicing additional customers. Uncollectible expenses in 2002 were slightly below the amounts recorded in 2001 as natural gas prices have declined, lowering average customer bills.
Depreciation expense and general taxes increased $12.5 million, or nine percent, as a result of construction activities. Average gas plant in service increased $207 million, or eight percent, compared to the prior year. This was attributed to the continued expansion and upgrading of the gas system to accommodate customer growth.
Other income (expense) declined $4.6 million between years principally because of a $5 million decrease in interest income earned on the balance of deferred purchased gas costs. Significant components of the
48
2002 balance, which are not expected in the future, include: an $8.9 million gain on the sale of undeveloped property, $4 million of net merger-related litigation costs (see Merger-related Litigation Settlements for additional information), and $2.7 million of charges associated with the settlement of a regulatory issue in California.
Net interest deductions declined $241,000 between years. Strong cash flows during the first half of 2002, from the recovery of previously deferred purchased gas costs and general rate relief, mitigated the amount of incremental borrowings needed to finance construction expenditures. Declining interest rates on variable-rate debt instruments were also a contributing favorable factor.
During 2002, Southwest recognized $2.7 million of income tax benefits associated with state taxes, plant, and non-plant related items. In 2001, the resolution of state income tax issues resulted in a $2.5 million income tax benefit.
2001 vs. 2000
The gas segment contribution to consolidated net income for 2001 decreased $1.3 million from 2000. Growth in operating margin and improvement in other income (expense) was more than offset by higher operating and financing costs.
Operating margin increased $39.6 million, or eight percent, in 2001 as a result of customer growth, rate relief, and a return to normal weather. Southwest added 60,000 new customers during 2001. This customer growth, coupled with increased margin from electric generation and industrial customers, contributed $30 million in incremental margin. An additional $5.3 million of incremental margin was realized in 2001 from general rate relief. In Arizona, annualized rate relief of $21.6 million was granted effective November 2001. The Company expected the general rate increase in April 2001. This seven-month delay resulted in unrealized operating margin of approximately $15 million. In Nevada, annualized rate relief of $19.4 million was granted effective December 2001. The remainder of the net change in operating margin between periods was due to weather as average temperatures during 2001 were normal versus moderately warmer-than-normal average temperatures during 2000.
Operations and maintenance expense increased $21.9 million, or nine percent, reflecting general increases in labor and maintenance costs, higher uncollectible expenses, and incremental costs associated with servicing additional customers.
Depreciation expense and general taxes increased $12.8 million, or ten percent, as a result of construction activities. Average gas plant in service increased $180 million, or eight percent, compared to the prior year. This was attributed to the continued expansion and upgrading of the gas system to accommodate customer growth.
Other income (expense) improved $9.5 million in 2001, primarily as a result of increased interest income of $5.9 million on PGA balances and a $3 million pretax gain on the sale of certain assets.
49
Net interest deductions increased $9.9 million, or 14 percent, as the Company financed both the new construction necessary to keep up with customer growth, and unrecovered purchased gas costs.
During 2001, Southwest recognized $2.5 million of income tax benefits associated with the resolution of state income tax issues. During 2000, Southwest recognized $6 million of income tax benefits associated with the favorable resolution of certain federal income tax issues and the statutory closure of open federal tax years. The 2001 effective income tax rate for the gas operations segment was 33 percent.
RATES AND REGULATORY PROCEEDINGS
Arizona General Rate Case. In May 2000, Southwest last filed a general rate application with the ACC for its Arizona rate jurisdiction. The ACC authorized Southwest to increase rates by $21.6 million, or five percent, annually, effective November 2001. Approximately $16.8 million of the increase was reflected in 2002 operating margin. Currently, Southwest has no plans to file a general rate case during 2003.
Nevada General Rate Cases. In July 2001, Southwest filed general rate applications with the Public Utilities Commission of Nevada (PUCN) for its southern Nevada and northern Nevada rate jurisdictions. In November 2001, Southwest received approval from the PUCN to increase rates by $13.5 million, or five percent, annually in southern Nevada and $5.9 million, or five percent, annually in northern Nevada effective December 2001. In January 2002, the PUCN settled several open issues in the case regarding rate design. Changes included increasing the residential basic service charge by $2.00 per month in both jurisdictions, which should improve revenue stability in Nevada. The changes were effective February 2002 and did not impact the amount of rate relief granted. Overall, approximately $16 million of the increase was reflected in 2002 operating margin. Southwest has no current plans to file a general rate case in 2003.
California General Rate Cases. In February 2002, Southwest filed general rate applications with the California Public Utilities Commission (CPUC) for its northern and southern California jurisdictions. The applications sought annual increases over a five-year rate case cycle with a cumulative total of $6.3 million in northern California and $17.2 million in southern California.
In July 2002, the Office of Ratepayer Advocates (ORA) filed testimony in the rate case recommending significant reductions to the rate increases sought by Southwest. The ORA did concur with the majority of the Southwest rate design proposals including a margin tracking mechanism to mitigate weather-related and other usage variations. At the hearing that was held in August 2002, Southwest modified its proposal from a five-year to a three-year rate case cycle and accordingly reduced its cumulative request to $4.8 million in northern California and $10.7 million in southern California. For 2003, the amounts requested were reduced to $2.6 million in northern California and $5.7 million in southern California. A decision is expected during the summer of 2003, with rates to become effective in the second half of 2003. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.
FERC Jurisdiction. In July 1996, Paiute Pipeline Company, a wholly owned subsidiary of the Company, filed its most recent general rate case with the Federal Energy Regulatory Commission (FERC). The FERC authorized a general rate increase effective January 1997. Currently, Paiute has no plans to file a general rate case during 2003.
50
PGA FILINGS
Arizona PGA Filings. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. In January 2002, Southwest filed an advice letter with the ACC to eliminate a temporary rate adjustment surcharge, which was otherwise set to expire at the end of the second quarter of 2002. This action was taken in recognition of moderating gas costs and projections of PGA balancing account activity. The filing was approved effective February 2002 and reduces revenues by $31.9 million annually.
In October 2002, Southwest submitted a PGA filing to the ACC to reduce rates based on an over-collected PGA balance at August 2002 of $18.8 million. The ACC approved the rate reduction as filed with new rates effective November 2002. At December 31, 2002, Southwest had an over-recovered PGA balance of $24 million.
Nevada PGA Filings. In December 2001, Southwest submitted an out-of-cycle PGA filing to the PUCN for a $29.2 million decrease for southern Nevada customers. In January 2002, an additional decrease of $13.9 million was requested. The total of the two filings, $43.1 million, was agreed to in a settlement among all parties and approved by the PUCN effective February 2002. The filings were made in advance of the scheduled annual date to allow customers to receive the benefit of decreases experienced in natural gas costs. In June 2002, Southwest filed its annual PGA, which requested no change in effective rates for either the southern or northern Nevada rate jurisdiction. However, subsequent to the filing, natural gas prices declined further, and in October 2002, through an all-party stipulation, Southwest agreed to decreases in PGA rates. The PUCN approved annual decreases of $13.5 million, or 14 percent, in northern Nevada and $8.7 million, or 4 percent, in southern Nevada. The new rates became effective in November 2002. At December 31, 2002, Southwest had an over-recovered balance of $21.9 million in its southern jurisdiction and an under-recovered balance of $8.3 million in its northern jurisdiction.
California PGA Filings. In California, Southwest is authorized to change the cost of gas included in sales rates each month to reflect the projected cost of gas for the current month. The treatment of monthly over/under-recoveries of gas costs varies by magnitude. Small amounts may be included in the following month’s estimated cost of gas for immediate recovery/refund. Large amounts may be deferred to the PGA account to be amortized over longer periods to avoid excessive fluctuation in prices. At December 31, 2002, Southwest had under-recovered PGA balances related to California jurisdictions of $10.9 million.
California Order Instituting Investigation (OII). In June 2001, the CPUC ordered an investigation into the reasonableness of Southwest natural gas procurement practices and costs from June 1999 through May 2001, and related measures taken to minimize gas costs beyond May 2001. During the third quarter of 2001, Southwest filed a detailed report and testimony with the CPUC on these matters for both its northern and southern California service territories. The OII resulted from complaints by southern California customers about the size of monthly PGA rate increases that were necessary due to the unusually high cost of natural gas during the winter of 2000-2001. In regards to the southern California jurisdiction, the ORA and County of San Bernardino recommended disallowances of $7.3 million and $11.7 million, respectively. No issues were raised related to the northern California rate jurisdiction. The
51
proposed disallowances were based solely on decisions by Southwest related to the level of gas held in storage during the winter of 2000-2001. Hearings were held in January 2002. Southwest defended its decisions related to storage, based on testimony which demonstrated that injecting additional volumes of natural gas into storage during the 2000 injection season (April through September) could not be economically justified based on market conditions and price forecasts that existed at the time decisions were made.
During May 2002, the Administrative Law Judge issued a proposed decision and the Presiding Commissioner issued an alternate decision (AD) related to this matter. The proposed decision recommended that Southwest be disallowed $3.2 million, while the AD recommended a $5.8 million disallowance. The $3.2 million proposed decision contained calculation errors which, when corrected, reduced the proposed decision to $2.7 million. Both draft decisions concluded that Southwest should have had a higher gas storage inventory level than it had going into the winter of 2000-2001.
During July 2002, a second AD was drafted by another Commissioner, recommending a disallowance of nearly $1.5 million. An estimated $1.5 million liability was recognized in the Company’s second quarter 2002 financial statements based on management’s belief that a disallowance would be ordered. In August 2002, the CPUC issued a final order which disallowed $2.7 million of gas costs. Based on the CPUC decision, an additional $1.2 million liability was recognized in the Company’s third quarter 2002 financial statements. The CPUC ordered the $2.7 million be returned to customers through bill credits, which began in November 2002, based on each customer’s usage during the five month period from November 2000 through March 2001.
OTHER FILINGS
Since November 1999, the FERC has been examining capacity allocation issues on the El Paso system in several proceedings. During that time, the demand for natural gas on the El Paso system has risen primarily due to increased electric power generation fuel needs and market area growth. As a result, shippers have been increasingly receiving reductions in the quantities of gas that they have been nominating for transportation each day. Many of the contract demand shippers have argued that the growth in the full requirements shippers’ volumes, coupled with El Paso’s failure to expand its system, have impaired their ability to receive all of the service to which they are entitled.
In May 2002, the FERC issued an order requiring that full requirements service be terminated as of November 2002. The order stated that full requirements transportation service agreements were to be converted to contract demand-type service agreements, and full requirements customers were to have an opportunity to negotiate an allocation of the system capacity determined by El Paso to be in excess of the capacity needed to fully serve the contract demand shippers. If the customers failed to agree upon an allocation, then the FERC would establish an allocation methodology for the customers. Following the order, various parties including Southwest submitted comments to the FERC seeking clarification or petitioning for rehearing.
52
In September 2002, the FERC issued an order on clarification of the May 2002 order. Among other things, the FERC determined that the full requirements customers had not agreed upon an allocation of capacity and, therefore, the FERC established a methodology to allocate capacity among the full requirements customers. In addition, the FERC postponed the conversion of full requirements service agreements to contract demand-type service agreements until May 2003. Because the proceeding is still ongoing, further modifications to previous orders as well as additional rulings may occur.
Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. However, by delaying the effective date of the order, Arizona had sufficient capacity during the winter of 2002-2003. Management also expects that sufficient capacity will be available to Southwest in the future, but additional costs may be incurred to acquire such capacity. It is anticipated that any additional costs will be collected from customers, principally through the PGA mechanism.
RESULTS OF CONSTRUCTION SERVICES
| Year Ended December 31, |
2002 |
2001 |
2000 | ||||||
| (thousands of dollars) |
|||||||||
| Construction revenues |
$ |
205,009 |
$ |
203,586 |
$ |
163,376 | |||
| Cost of construction |
|
191,561 |
|
189,429 |
|
150,678 | |||
| Gross profit |
|
13,448 |
|
14,157 |
|
12,698 | |||
| General and administrative expenses |
|
5,542 |
|
5,026 |
|
3,986 | |||
| Operating income |
|
7,906 |
|
9,131 |
|
8,712 | |||
| Other income (expense) |
|
1,221 |
|
871 |
|
821 | |||
| Income before interest and income taxes |
|
9,127 |
|
10,002 |
|
9,533 | |||
| Interest expense |
|
1,466 |
|
1,985 |
|
1,779 | |||
| Income tax expense |
|
2,924 |
|
3,487 |
|
3,351 | |||
| Contribution to consolidated net income |
$ |
4,737 |
$ |
4,530 |
$ |
4,403 | |||
2002 vs. 2001
The 2002 contribution to consolidated net income from construction services increased $207,000 from the prior year. The increase was primarily due to a decline in Income tax expense and an increase in Other income. Revenues remained relatively constant, while the gross profit margin percentage decreased slightly.
Gross profit decreased $709,000 because of the absorption of significant increases in insurance costs. Gross profit is expected to increase in 2003. Other income in 2001 and 2000 included $400,000 of goodwill amortization that was not included in 2002 due to the adoption of a new accounting pronouncement. General and administrative expenses increased by $516,000 due to increased labor costs and additional depreciation related to a new computer system. Interest expense declined as a result of the refinancing of long-term debt to take advantage of lower interest rates. Income tax expense decreased largely as a result of a $274,000 tax credit in the state of Arizona.
53
2001 vs. 2000
The 2001 contribution to consolidated net income from construction services increased $127,000 from the prior year. The increase was principally due to higher revenues that resulted from obtaining additional work. Revenues increased 25 percent, while the gross profit margin percentage decreased slightly. Gross profit increased $1.5 million.
General and administrative expenses, as a percent of revenue, remained relatively constant as did interest expense.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. The Company adopted the provisions of SFAS No. 143 on January 1, 2003. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs.
SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, or normal operation of long-lived assets. For purposes of SFAS No. 143, legal obligations are defined as obligations that a party is required to settle as a result of an existing or enacted law, statute, ordinance, written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. SFAS No. 143 requires that all asset retirement obligations within the scope of the standard be recognized when a reasonable estimate of the fair value can be made. One of the key factors in determining the fair value is the length of time until settlement of the obligation. If the length of time until settlement is not determinable, the asset retirement obligation is not reasonably estimable and no liability can be established.
In accordance with regulatory requirements, Southwest currently accrues for retirement obligations (whether legal or due to deterioration) ratably over the estimated useful life of long-lived assets as a component of depreciation expense. Examples of retirement obligations include such costs as capping and purging gas lines, abandoning in place, or otherwise removing plant from service. These future costs of retirement obligations are included in Southwest’s depreciation rates so that current accounting periods reflect a proportional share of the ultimate retirement cost at the end of the property service life.
The transmission, distribution, and compression facilities of Southwest are of a perpetual nature. Substantially all gas main and service lines are constructed across property owned by others under easements and rights-of-way grants obtained from the record owners thereof, on streets and grounds of municipalities under authority conferred by franchises or otherwise, or on public highways or public lands under authority of various federal and state statutes. None of the numerous county and municipal franchises are exclusive and some are of a limited duration.
Southwest has determined that it has limited legal obligations related to retirement costs for portions of its system that are subject to the limited-duration easements and rights-of-way agreements. However, Southwest has traditionally been able to renew its easements and rights-of-way without having to retire,
54
abandon, or remove facilities, and anticipates no serious difficulties in obtaining future renewals. In addition, certain franchises and provisions of federal and state statutes for abandonment of facilities impose removal obligations. Southwest has the intent and the ability to operate such facilities indefinitely (other than for replacements due to ordinary deterioration). As a result, the length of time until settlement of the asset retirement obligation is unknown. Therefore, the future obligation cannot be reasonably estimated, resulting in no liability being established.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements.” The rescission of SFAS Nos. 4 and 64 was effective for fiscal years beginning after May 15, 2002. All other provisions of SFAS No. 145 were effective for transactions entered into, or financial statements issued, after May 15, 2002. The standard was adopted without impact to the financial position or results of operations of the Company.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability be recognized at fair value for a cost associated with an exit or disposal activity when the liability is incurred. Exit or disposal activities include a sale or termination of a line of business, the closure of business activities in a particular location, the relocation of business activities from one location to another, changes in management structure, and a fundamental reorganization that affects the nature and focus of operations. The provisions of SFAS No. 146 are effective for exit or disposal activities that were initiated after December 31, 2002, with early application encouraged. SFAS No. 146 was adopted with no material effect on the financial position or results of operations of the Company.
In November 2002, the FASB issued Interpretation (FIN) No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – an Interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34.” FIN No. 45 clarifies disclosures that a guarantor is required to include in its financial statements. FIN No. 45 also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the obligations it has undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN No. 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements in FIN No. 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. FIN No. 45 was adopted without impact to the financial position or results of operations of the Company.
In January 2003, the FASB issued FIN No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51.” This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements”, addresses consolidation by business enterprises of variable interest entities. FIN No. 46 explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. FIN No. 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an
55
enterprise obtains an interest after that date. FIN No. 46 was adopted without impact to the financial position or results of operations of the Company.
MERGER-RELATED LITIGATION SETTLEMENTS
Litigation related to the now terminated acquisition of the Company by ONEOK, Inc. (ONEOK) and the rejection of competing offers from Southern Union Company (Southern Union) was resolved during 2002. In August 2002, the Company reached final settlements with both Southern Union and ONEOK related to this litigation. The Company paid Southern Union $17.5 million to resolve all remaining Southern Union claims against the Company and its officers. ONEOK paid the Company $3 million to resolve all claims between the Company and ONEOK. The net after-tax impact of the settlements was a $9 million charge and was reflected in the second quarter 2002 financial statements. The Company and one of its insurance providers were in dispute over whether the insurance coverage applied to the Southern Union settlement and related litigation defense costs. Because of the dispute, the Company did not recognize any benefit for potential insurance recoveries related to the Southern Union settlement in the second quarter.
In December 2002, the Company negotiated a $16.25 million settlement with the insurance provider related to the coverage dispute. Income from the settlement was recognized in the fourth quarter of 2002 and amounted to $9 million after-tax.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one which is very important to the portrayal of the financial condition and results of a company, and requires the most difficult, subjective, or complex judgments of management. The need to make estimates about the effect of items that are uncertain is what makes these judgments difficult, subjective, and/or complex. Management makes subjective judgments about the accounting and regulatory treatment of many items. The following are examples of accounting policies that are critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1 – Summary of Significant Accounting Policies.
| • | Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated enterprises (including SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”) and reflect the effects of the ratemaking process. As such, the Company is allowed to defer as regulatory assets, costs that otherwise would be expensed if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets. |
| • | The income tax calculations of the Company require estimates due to regulatory differences between the multiple states in which the Company operates, and future tax rate changes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and |
56
| their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A change in the regulatory treatment, or significant changes in tax-related estimates, assumptions, or enacted tax rates could have a material impact on the financial position and results of operations of the Company. |
| • | Depreciation is computed at composite rates considered sufficient to amortize costs over the estimated remaining lives of assets, and includes adjustments for the cost of removal, and salvage value. Depreciation studies are performed periodically and prospective changes in rates are estimated to make up for past differences. These studies are reviewed and approved by the appropriate regulatory agency. Changes in estimates of depreciable lives or changes in depreciation rates mandated by regulations could affect the results of operations of the Company in periods subsequent to the change. |
Management believes that regulation and the effects of regulatory accounting have the most significant impact on the financial statements. When Southwest files rate cases, capital assets, costs and gas purchasing practices are subject to review, and disallowances can occur. Regulatory disallowances in the past have not been frequent but have on occasion been significant to the operating results of the Company.
FORWARD-LOOKING STATEMENTS
This annual report contains statements which constitute “forward-looking statements” within the meaning of the Securities Litigation Reform Act of 1995 (Reform Act). All such forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act. A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, natural gas prices, the effects of regulation/deregulation, the timing and amount of rate relief, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, acquisitions, and competition. For additional information on the risks associated with the Company’s business see, Item 1. Business-Company Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.
COMMON STOCK PRICE AND DIVIDEND INFORMATION
| 2002 |
2001 |
Dividends Paid | ||||||||||||||||
| High |
Low |
High |
Low |
2002 |
2001 | |||||||||||||
| First Quarter |
$ |
25.35 |
$ |
21.80 |
$ |
22.60 |
$ |
19.81 |
$ |
0.205 |
$ |
0.205 | ||||||
| Second Quarter |
|
24.99 |
|
22.60 |
|
24.29 |
|
20.18 |
|
0.205 |
|
0.205 | ||||||
| Third Quarter |
|
24.75 |
|
18.10 |
|
24.38 |
|
18.85 |
|
0.205 |
|
0.205 | ||||||
| Fourth Quarter |
|
23.63 |
|
19.82 |
|
23.00 |
|
20.50 |
|
0.205 |
|
0.205 | ||||||
| $ |
0.820 |
$ |
0.820 | |||||||||||||||
The principal markets on which the common stock of the Company is traded are the New York Stock Exchange and the Pacific Stock Exchange. At March 10, 2003, there were 21,974 holders of record of common stock and the market price of the common stock was $19.60.
57
Consolidated Balance Sheets
| December 31, |
||||||||
| 2002 |
2001 |
|||||||
| (thousands of dollars) |
||||||||
| ASSETS |
||||||||
| Utility plant: |
||||||||
| Gas plant |
$ |
2,779,960 |
|
$ |
2,561,937 |
| ||
| Less: accumulated depreciation |
|
(869,908 |
) |
|
(789,751 |
) | ||
| Acquisition adjustments, net |
|
2,714 |
|
|
2,894 |
| ||
| Construction work in progress |
|
66,693 |
|
|
50,491 |
| ||
| Net utility plant (Note 2) |
|
1,979,459 |
|
|
1,825,571 |
| ||
| Other property and investments |
|
87,391 |
|
|
92,511 |
| ||
| Current assets: |
||||||||
| Cash and cash equivalents |
|
19,392 |
|
|
32,486 |
| ||
| Accounts receivable, net of allowances (Note 3) |
|
130,695 |
|
|
155,382 |
| ||
| Accrued utility revenue |
|
65,073 |
|
|
63,773 |
| ||
| Income taxes receivable, net |
|
– |
|
|
26,697 |
| ||
| Deferred income taxes (Note 10) |
|
3,084 |
|
|
– |
| ||
| Deferred purchased gas costs (Note 4) |
|
– |
|
|
83,501 |
| ||
| Prepaids and other current assets (Note 4) |
|
43,524 |
|
|
38,310 |
| ||
| Total current assets |
|
261,768 |
|
|
400,149 |
| ||
| Deferred charges and other assets (Note 4) |
|
49,310 |
|
|
51,381 |
| ||
| Total assets |
$ |
2,377,928 |
|
$ |
2,369,612 |
| ||
58
| December 31, | ||||||
| 2002 |
2001 | |||||
| (thousands of dollars, except par value) |
||||||
| CAPITALIZATION AND LIABILITIES |
||||||
| Capitalization: |
||||||
| Common stock, $1 par (authorized – 45,000,000 shares; issued and outstanding – 33,289,015 and 32,492,832 shares) |
$ |
34,919 |
$ |
34,123 | ||
| Additional paid-in capital |
|
487,788 |
|
470,410 | ||
| Retained earnings |
|
73,460 |
|
56,667 | ||
| Total equity |
|
596,167 |
|
561,200 | ||
| Mandatorily redeemable preferred securities due 2025 (Note 5) |
|
60,000 |
|
60,000 | ||
| Long-term debt, less current maturities (Note 6) |
|
1,092,148 |
|
796,351 | ||
| Total capitalization |
|
1,748,315 |
|
1,417,551 | ||
| Commitments and contingencies (Note 8) |
||||||
| Current liabilities: |
||||||
| Current maturities of long-term debt (Note 6) |
|
8,705 |
|
307,641 | ||
| Short-term debt (Note 7) |
|
53,000 |
|
93,000 | ||
| Accounts payable |
|
88,309 |
|
109,167 | ||
| Customer deposits |
|
34,313 |
|
30,288 | ||
| Income taxes payable, net |
|
10,969 |
|
– | ||
| Accrued general taxes |
|
28,400 |
|
32,069 | ||
| Accrued interest |
|
21,137 |
|
20,423 | ||
| Deferred income taxes (Note 10) |
|
– |
|
24,154 | ||
| Deferred purchased gas costs (Note 4) |
|
26,718 |
|
– | ||
| Other current liabilities |
|
41,630 |
|
36,299 | ||
| Total current liabilities |
|
313,181 |
|
653,041 | ||
| Deferred income taxes and other credits: |
||||||
| Deferred income taxes and investment tax credits (Note 10) |
|
229,358 |
|
217,804 | ||
| Other deferred credits (Note 4) |
|
87,074 |
|
81,216 | ||
| Total deferred income taxes and other credits |
|
316,432 |
|
299,020 | ||
| Total capitalization and liabilities |
$ |
2,377,928 |
$ |
2,369,612 | ||
The accompanying notes are an integral part of these statements.
59
Consolidated Statements of Income
| Year Ended December 31, |
||||||||||||
| 2002 |
2001 |
2000 |
||||||||||
| (in thousands, except per share amounts) |
||||||||||||
| Operating revenues: |
||||||||||||
| Gas operating revenues |
$ |
1,115,900 |
|
$ |
1,193,102 |
|
$ |
870,711 |
| |||
| Construction revenues |
|
205,009 |
|
|
203,586 |
|
|
163,376 |
| |||
| Total operating revenues |
|
1,320,909 |
|
|
1,396,688 |
|
|
1,034,087 |
| |||
| Operating expenses: |
||||||||||||
| Net cost of gas sold |
|
563,379 |
|
|
677,547 |
|
|
394,711 |
| |||
| Operations and maintenance |
|
264,188 |
|
|
253,026 |
|
|
231,175 |
| |||
| Depreciation and amortization |
|
130,210 |
|
|
118,448 |
|
|
106,640 |
| |||
| Taxes other than income taxes |
|
34,565 |
|
|
32,780 |
|
|
29,819 |
| |||
| Construction expenses |
|
182,068 |
|
|
180,904 |
|
|
143,112 |
| |||
| Total operating expenses |
|
1,174,410 |
|
|
1,262,705 |
|
|
905,457 |
| |||
| Operating income |
|
146,499 |
|
|
133,983 |
|
|
128,630 |
| |||
| Other income and (expenses): |
||||||||||||
| Net interest deductions |
|
(79,971 |
) |
|
(80,731 |
) |
|
(70,671 |
) | |||
| Preferred securities distributions (Note 5) |
|
(5,475 |
) |
|
(5,475 |
) |
|
(5,475 |
) | |||
| Other income (deductions) |
|
4,329 |
|
|
8,964 |
|
|
(545 |
) | |||
| Total other income and (expenses) |
|
(81,117 |
) |
|
(77,242 |
) |
|
(76,691 |
) | |||
| Income before income taxes |
|
65,382 |
|
|
56,741 |
|
|
51,939 |
| |||
| Income tax expense (Note 10) |
|
21,417 |
|
|
19,585 |
|
|
13,628 |
| |||
| Net income |
$ |
43,965 |
|
$ |
37,156 |
|
$ |
38,311 |
| |||
| Basic earnings per share (Note 12) |
$ |
1.33 |
|
$ |
1.16 |
|
$ |
1.22 |
| |||
| Diluted earnings per share (Note 12) |
$ |
1.32 |
|
$ |
1.15 |
|
$ |
1.21 |
| |||
| Average number of common shares outstanding |
|
32,953 |
|
|
32,122 |
|
|
31,371 |
| |||
| Average shares outstanding (assuming dilution) |
|
33,233 |
|
|
32,398 |
|
|
31,575 |
| |||
The accompanying notes are an integral part of these statements.
60
Consolidated Statements of Cash Flows
| Year Ended December 31, |
||||||||||||
| 2002 |
2001 |
2000 |
||||||||||
| (thousands of dollars) |
||||||||||||
| CASH FLOW FROM OPERATING ACTIVITIES: |
||||||||||||
| Net income |
$ |
43,965 |
|
$ |
37,156 |
|
$ |
38,311 |
| |||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
|
130,210 |
|
|
118,448 |
|
|
106,640 |
| |||
| Deferred income taxes |
|
(15,684 |
) |
|
(11,175 |
) |
|
80,836 |
| |||
| Changes in current assets and liabilities: |
||||||||||||
| Accounts receivable, net of allowances |
|
24,687 |
|
|
(19,773 |
) |
|
(47,133 |
) | |||
| Accrued utility revenue |
|
(1,300 |
) |
|
(5,900 |
) |
|
(1,500 |
) | |||
| Deferred purchased gas costs |
|
110,219 |
|
|
8,563 |
|
|
(83,013 |
) | |||
| Accounts payable |
|
(20,858 |
) |
|
(85,512 |
) |
|
130,432 |
| |||
| Accrued taxes |
|
33,997 |
|
|
18,766 |
|
|
(54,005 |
) | |||
| Other current assets and liabilities |
|
4,763 |
|
|
34,051 |
|
|
(44,917 |
) | |||
| Other |
|
(11,525 |
) |
|
28,128 |
|
|
(344 |
) | |||
| Net cash provided by operating activities |
|
298,474 |
|
|
122,752 |
|
|
125,307 |
| |||
| CASH FLOW FROM INVESTING ACTIVITIES: |
||||||||||||
| Construction expenditures and property additions |
|
(282,851 |
) |
|
(265,580 |
) |
|
(223,240 |
) | |||
| Other |
|
23,985 |
|
|
4,318 |
|
|
3,923 |
| |||
| Net cash used in investing activities |
|
(258,866 |
) |
|
(261,262 |
) |
|
(219,317 |
) | |||
| CASH FLOW FROM FINANCING ACTIVITIES: |
||||||||||||
| Issuance of common stock, net |
|
18,174 |
|
|
17,061 |
|
|
15,595 |
| |||
| Dividends paid |
|
(27,009 |
) |
|
(26,323 |
) |
|
(25,715 |
) | |||
| Issuance of long-term debt, net |
|
206,161 |
|
|
213,026 |
|
|
45,101 |
| |||
| Retirement of long-term debt, net |
|
(210,028 |
) |
|
(14,723 |
) |
|
(8,142 |
) | |||
| Change in short-term debt |
|
(40,000 |
) |
|
(38,000 |
) |
|
70,000 |
| |||
| Net cash provided by (used in) financing activities |
|
(52,702 |
) |
|
151,041 |
|
|
96,839 |
| |||
| Change in cash and cash equivalents |
|
(13,094 |
) |
|
12,531 |
|
|
2,829 |
| |||
| Cash at beginning of period |
|
32,486 |
|
|
19,955 |
|
|
17,126 |
| |||
| Cash at end of period |
$ |
19,392 |
|
$ |
32,486 |
|
$ |
19,955 |
| |||
| Supplemental information: |
||||||||||||
| Interest paid, net of amounts capitalized |
$ |
76,867 |
|
$ |
74,032 |
|
$ |
67,638 |
| |||
| Income taxes paid (received), net |
$ |
1,797 |
|
$ |
13,186 |
|
$ |
(13,417 |
) | |||
The accompanying notes are an integral part of these statements.
61
Consolidated Statements of Stockholders’ Equity
| Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Total |
|||||||||||||
| Shares |
Amount |
|||||||||||||||
| (in thousands, except per share amounts) |
||||||||||||||||
| DECEMBER 31, 1999 |
30,985 |
$ |
32,615 |
$ |
439,262 |
$ |
33,548 |
|
$ |
505,425 |
| |||||
| Common stock issuances |
725 |
|
725 |
|
14,870 |
|
15,595 |
| ||||||||
| Net income |
|
38,311 |
|
|
38,311 |
| ||||||||||
| Dividends declared |
||||||||||||||||
| Common: $0.82 per share |
|
(25,864 |
) |
|
(25,864 |
) | ||||||||||
| DECEMBER 31, 2000 |
31,710 |
|
33,340 |
|
454,132 |
|
45,995 |
|
|
533,467 |
| |||||
| Common stock issuances |
783 |
|
783 |
|
16,278 |
|
17,061 |
| ||||||||
| Net income |
|
37,156 |
|
|
37,156 |
| ||||||||||
| Dividends declared |
||||||||||||||||
| Common: $0.82 per share |
|
(26,484 |
) |
|
(26,484 |
) | ||||||||||
| DECEMBER 31, 2001 |
32,493 |
|
34,123 |
|
470,410 |
|
56,667 |
|
|
561,200 |
| |||||
| Common stock issuances |
796 |
|
796 |
|
17,378 |
|
18,174 |
| ||||||||
| Net income |
|
43,965 |
|
|
43,965 |
| ||||||||||
| Dividends declared |
||||||||||||||||
| Common: $0.82 per share |
|
(27,172 |
) |
|
(27,172 |
) | ||||||||||
| DECEMBER 31, 2002 |
33,289* |
$ |
34,919 |
$ |
487,788 |
$ |
73,460 |
|
$ |
596,167 |
| |||||
* At December 31, 2002, 2.2 million common shares were registered and available for issuance under provisions of the Employee Investment Plan, the Stock Incentive Plan, and the Dividend Reinvestment and Stock Purchase Plan.
The accompanying notes are an integral part of these statements.
62
Notes to Consolidated Financial Statements
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations. Southwest Gas Corporation (the Company) is comprised of two segments: natural gas operations (Southwest or the natural gas operations segment) and construction services. Southwest purchases, transports, and distributes natural gas to customers in portions of Arizona, Nevada, and California. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas sales are seasonal, peaking during the winter months. Variability in weather from normal temperatures can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Northern Pipeline Construction Co. (Northern or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor which provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
Basis of Presentation. The Company follows generally accepted accounting principles (GAAP) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with GAAP as applied to regulated companies and as prescribed by federal agencies and the commissions of the various states in which the utility operates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and Northern in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”
Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction less contributions in aid of construction.
Deferred Purchased Gas Costs. The various regulatory commissions have established procedures to enable Southwest to adjust its billing rates for changes in the cost of gas purchased. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred. Generally, these deferred amounts are recovered or refunded within one year.
Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using
63
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date.
For regulatory and financial reporting purposes, investment tax credits (ITC) related to gas utility operations are deferred and amortized over the life of related fixed assets.
Gas Operating Revenues. Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs. Southwest also recognizes accrued utility revenues for the estimated amount of services rendered between the meter-reading dates in a particular month and the end of such month.
Construction Revenues. The majority of the Northern contracts are performed under unit price contracts. These contracts state prices per unit of installation. Revenues are recorded as installations are completed. Fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements.
Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which adjust for salvage value and removal costs, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Acquisition adjustments are amortized, as ordered by regulators, over periods which approximate the remaining estimated life of the acquired properties. Costs related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues. Other regulatory assets, when appropriate, are amortized over time periods authorized by regulators. Nonutility property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. Goodwill amortization for each of the years 2000 and 2001 was $400,000. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets,” goodwill amortization was eliminated as of January 2002.
Allowance for Funds Used During Construction (AFUDC). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The Company capitalized $3.1 million in 2002, $2.5 million in 2001, and $1.6 million in 2000 of AFUDC related to natural gas utility operations. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.
64
Earnings Per Share. Basic earnings per share (EPS) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of additional weighted-average common stock equivalents (stock options and performance shares). Unless otherwise noted, the term “Earnings Per Share” refers to Basic EPS. A reconciliation of the shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.
| 2002 |
2001 |
2000 | ||||
| (in thousands) |
||||||
| Average basic shares |
32,953 |
32,122 |
31,371 | |||
| Effect of dilutive securities: |
||||||
| Stock options |
94 |
122 |
85 | |||
| Performance shares |
186 |
154 |
119 | |||
| Average diluted shares |
33,233 |
32,398 |
31,575 | |||
Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a maturity of three months or less, but exclude funds held in trust from the issuance of industrial development revenue bonds (IDRB).
Recently Issued Accounting Pronouncements. In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. The Company adopted the provisions of SFAS No. 143 on January 1, 2003. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs.
SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, or normal operation of long-lived assets. For purposes of SFAS No. 143, legal obligations are defined as obligations that a party is required to settle as a result of an existing or enacted law, statute, ordinance, written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. SFAS No. 143 requires that all asset retirement obligations within the scope of the standard be recognized when a reasonable estimate of the fair value can be made. One of the key factors in determining the fair value is the length of time until settlement of the obligation. If the length of time until settlement is not determinable, the asset retirement obligation is not reasonably estimable and no liability can be established.
In accordance with regulatory requirements, Southwest currently accrues for retirement obligations (whether legal or due to deterioration) ratably over the estimated useful life of long-lived assets as a component of depreciation expense. Examples of retirement obligations include such costs as capping and purging gas lines, abandoning in place, or otherwise removing plant from service. These future costs of retirement obligations are included in Southwest’s depreciation rates so that current accounting periods reflect a proportional share of the ultimate retirement cost at the end of the property service life.
65
The transmission, distribution, and compression facilities of Southwest are of a perpetual nature. Substantially all gas main and service lines are constructed across property owned by others under easements and rights-of-way grants obtained from the record owners thereof, on streets and grounds of municipalities under authority conferred by franchises or otherwise, or on public highways or public lands under authority of various federal and state statutes. None of the numerous county and municipal franchises are exclusive and some are of a limited duration.
Southwest has determined that it has limited legal obligations related to retirement costs for portions of its system that are subject to the limited-duration easements and rights-of-way agreements. However, Southwest has traditionally been able to renew its easements and rights-of-way without having to retire, abandon, or remove facilities, and anticipates no serious difficulties in obtaining future renewals. In addition, certain franchises and provisions of federal and state statutes for abandonment of facilities impose removal obligations. Southwest has the intent and the ability to operate such facilities indefinitely (other than for replacements due to ordinary deterioration). As a result, the length of time until settlement of the asset retirement obligation is unknown. Therefore, the future obligation cannot be reasonably estimated, resulting in no liability being established.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements.” The rescission of SFAS Nos. 4 and 64 was effective for fiscal years beginning after May 15, 2002. All other provisions of SFAS No. 145 were effective for transactions entered into, or financial statements issued, after May 15, 2002. The standard was adopted without impact to the financial position or results of operations of the Company.
In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability be recognized at fair value for a cost associated with an exit or disposal activity when the liability is incurred. Exit or disposal activities include a sale or termination of a line of business, the closure of business activities in a particular location, the relocation of business activities from one location to another, changes in management structure, and a fundamental reorganization that affects the nature and focus of operations. The provisions of SFAS No. 146 are effective for exit or disposal activities that were initiated after December 31, 2002, with early application encouraged. SFAS No. 146 was adopted with no material effect on the financial position or results of operations of the Company.
In November 2002, the FASB issued FASB Interpretation (FIN) No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others – an Interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34.” FIN No. 45 clarifies disclosures that a guarantor is required to include in its financial statements. FIN No. 45 also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the obligations it has undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN No. 45 are applicable on a prospective basis to guarantees issued or modified after
66
December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements in FIN No. 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. FIN No. 45 was adopted without impact to the financial position or results of operations of the Company.
In January 2003, the FASB issued FIN No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51.” This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements”, addresses consolidation by business enterprises of variable interest entities. FIN No. 46 explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. FIN No. 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. FIN No. 46 was adopted without impact to the financial position or results of operations of the Company.
Stock-Based Compensation. At December 31, 2002, the Company had two stock-based compensation plans, which are described more fully in Note 9 – Employee Benefits. These plans are accounted for in accordance with Accounting Principles Board (APB) Opinion No. 25 “Accounting for Stock Issued to Employees” and related interpretations. In December 2002, the FASB issued SFAS No. 148,”Accounting for Stock-Based Compensation – Transition and Disclosure – an Amendment of FASB Statement No. 123,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The Company has no current plans to adopt the fair value recognition provision of SFAS No. 123, “Accounting for Stock-Based Compensation”. The Company adopted the disclosure requirements of SFAS No. 148 effective December 2002. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123 to its stock-based employee compensation (thousands of dollars, except per share amounts):
| 2002 |
2001 |
2000 |
||||||||||
| Net income, as reported |
$ |
43,965 |
|
$ |
37,156 |
|
$ |
38,311 |
| |||
| Add: Stock-based employee compensation expense included in reported net income, net of related tax benefits |
|
1,783 |
|
|
1,879 |
|
|
582 |
| |||
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax benefits |
|
(2,024 |
) |
|
(2,222 |
) |
|
(934 |
) | |||
| Pro forma net income |
$ |
43,724 |
|
$ |
36,813 |
|
$ |
37,959 |
| |||
| Earnings per share: |
||||||||||||
| Basic – as reported |
$ |
1.33 |
|
$ |
1.16 |
|
$ |
1.22 |
| |||
| Basic – pro forma |
|
1.33 |
|
|
1.15 |
|
|
1.21 |
| |||
| Diluted – as reported |
|
1.32 |
|
|
1.15 |
|
|
1.21 |
| |||
| Diluted – pro forma |
|
1.32 |
|
|
1.14 |
|
|
1.20 |
| |||
67
NOTE 2 UTILITY PLANT
Net utility plant as of December 31, 2002 and 2001 was as follows (thousands of dollars):
| DECEMBER 31, |
2002 |
2001 |
||||||
| Gas plant: |
||||||||
| Storage |
$ |
4,213 |
|
$ |
3,992 |
| ||
| Transmission |
|
196,997 |
|
|
187,393 |
| ||
| Distribution |
|
2,293,655 |
|
|
2,104,006 |
| ||
| General |
|
198,093 |
|
|
188,998 |
| ||
| Other |
|
87,002 |
|
|
77,548 |
| ||
|
|
2,779,960 |
|
|
2,561,937 |
| |||
| Less: accumulated depreciation |
|
(869,908 |
) |
|
(789,751 |
) | ||
| Acquisition adjustments, net |
|
2,714 |
|
|
2,894 |
| ||
| Construction work in progress |
|
66,693 |
|
|
50,491 |
| ||
| Net utility plant |
$ |
1,979,459 |
|
$ |
1,825,571 |
| ||
Depreciation and amortization expense on gas plant was $113 million in 2002, $102 million in 2001, and $92.4 million in 2000.
Leases and Rentals. Southwest leases the liquefied natural gas (LNG) facilities on its northern Nevada system, a portion of its corporate headquarters office complex in Las Vegas, and its administrative offices in Phoenix. The leases provide for current terms which expire in 2005, 2017, and 2009, respectively, with optional renewal terms available at the expiration dates. The LNG facility lease was recently renewed for an additional two and one-half year period. The rental payments for the LNG facilities are $3.3 million for each of the years 2003 and 2004, and $1.7 million in 2005, when the lease expires in July. The rental payments for the corporate headquarters office complex are $1.9 million in 2003, $2 million in each of the years 2004 through 2007, and $20.4 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.3 million in 2003, $1.4 million in 2004, $1.5 million for each of the years 2005 through 2007, and $2.5 million cumulatively thereafter. In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. Rentals included in operating expenses for all operating leases were $26.5 million in 2002, $28 million in 2001, and $25.7 million in 2000. These amounts include Northern lease expenses of approximately $12.3 million in 2002, $12.6 million in 2001, and $9.2 million in 2000 for various short-term leases of equipment and temporary office sites.
68
The following is a schedule of future minimum lease payments for noncancellable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2002 (thousands of dollars):
| YEAR ENDING DECEMBER 31, |
|||
| 2003 |
$ |
8,618 | |
| 2004 |
|
8,267 | |
| 2005 |
|
6,218 | |
| 2006 |
|
3,914 | |
| 2007 |
|
3,758 | |
| Thereafter |
|
23,009 | |
| Total minimum lease payments |
$ |
53,784 | |
NOTE 3 RECEIVABLES AND RELATED ALLOWANCES
Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. At December 31, 2002, the gas utility customer accounts receivable balance was $88 million. Approximately 56 percent of the gas utility customers were in Arizona, 35 percent in Nevada, and 9 percent in California. Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Provisions for uncollectible accounts are recorded monthly, as needed, and are included in the ratemaking process as a cost of service. Activity in the allowance for uncollectibles is summarized as follows (thousands of dollars):
| Allowance for Uncollectibles |
||||
| Balance, December 31, 1999 |
$ |
1,730 |
| |
| Additions charged to expense |
|
1,036 |
| |
| Accounts written off, less recoveries |
|
(1,202 |
) | |
| Balance, December 31, 2000 |
|
1,564 |
| |
| Additions charged to expense |
|
3,874 |
| |
| Accounts written off, less recoveries |
|
(3,567 |
) | |
| Balance, December 31, 2001 |
|
1,871 |
| |
| Additions charged to expense |
|
3,824 |
| |
| Accounts written off, less recoveries |
|
(3,870 |
) | |
| Balance, December 31, 2002 |
$ |
1,825 |
| |
69
NOTE 4 REGULATORY ASSETS AND LIABILITIES
Natural gas operations are subject to the regulation of the Arizona Corporation Commission (ACC), the Public Utilities Commission of Nevada (PUCN), the California Public Utilities Commission (CPUC), and the Federal Energy Regulatory Commission (FERC). Company accounting policies conform to generally accepted accounting principles applicable to rate-regulated enterprises, principally SFAS No. 71, and reflect the effects of the ratemaking process. SFAS No. 71 allows for the deferral as regulatory assets, costs that otherwise would be expensed if it is probable future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write off the related regulatory asset.
The following table represents existing regulatory assets and liabilities (thousands of dollars):
| DECEMBER 31, |
2002 |
2001 |
||||||
| Regulatory assets: |
||||||||
| Deferred purchased gas costs |
$ |
– |
|
$ |
83,501 |
| ||
| SFAS No. 109 – Income taxes, net |
|
5,035 |
|
|
4,434 |
| ||
| Unamortized premium on reacquired debt |
|
12,614 |
|
|
13,607 |
| ||
| Other |
|
27,873 |
|
|
29,063 |
| ||
|
|
45,522 |
|
|
130,605 |
| |||
| Regulatory liabilities: |
||||||||
| Deferred purchased gas costs |
|
(26,718 |
) |
|
– |
| ||
| Other |
|
(422 |
) |
|
(342 |
) | ||
| Net regulatory assets |
$ |
18,382 |
|
$ |
130,263 |
| ||
NOTE 5 PREFERRED SECURITIES
Preferred Securities of Southwest Gas Capital I. In October 1995, Southwest Gas Capital I (the Trust), a consolidated wholly owned subsidiary of the Company, issued $60 million of 9.125% Trust Originated Preferred Securities (the Preferred Securities). In connection with the Trust issuance of the Preferred Securities and the related purchase by the Company of all of the Trust common securities (the Common Securities), the Company issued to the Trust $61.8 million principal amount of its 9.125% Subordinated Deferrable Interest Notes, due 2025 (the Subordinated Notes). The sole assets of the Trust are and will be the Subordinated Notes. The interest and other payment dates on the Subordinated Notes correspond to the distribution and other payment dates on the Preferred Securities and Common Securities. Under certain circumstances, the Subordinated Notes may be distributed to the holders of the Preferred Securities and holders of the Common Securities in liquidation of the Trust. The Subordinated Notes are redeemable at the option of the Company at any time at a redemption price of $25 per Subordinated Note plus accrued and unpaid interest. In the event that the Subordinated Notes are repaid, the Preferred Securities and the Common Securities will be redeemed on a pro rata basis at $25 per Preferred Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Notes, the Declaration of Trust (the agreement under which the Trust was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with
70
respect to the Preferred Securities to the extent the Trust has funds available therefore and the indenture governing the Subordinated Notes, including the Company agreement pursuant to such indenture to pay all fees and expenses of the Trust, other than with respect to the Preferred Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Securities. As of December 31, 2002, 2.4 million Preferred Securities were outstanding.
The Company has the right to defer payments of interest on the Subordinated Notes by extending the interest payment period at any time for up to 20 consecutive quarters (each, an Extension Period). If interest payments are so deferred, distributions will also be deferred. During such Extension Period, distributions will continue to accrue with interest thereon (to the extent permitted by applicable law) at an annual rate of 9.125% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Notes. If the Company exercises the right to extend an interest payment period, the Company shall not during such Extension Period (i) declare or pay dividends on, or make a distribution with respect to, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, or (ii) make any payment of interest, principal, or premium, if any, on or repay, repurchase, or redeem any debt securities issued by the Company that rank equal with or junior to the Subordinated Notes; provided, however, that restriction (i) above does not apply to any stock dividends paid by the Company where the dividend stock is the same as that on which the dividend is being paid. The Company has no present intention of exercising its right to extend the interest payment period.
71
NOTE 6 LONG-TERM DEBT
| DECEMBER 31, |
2002 |
2001 | ||||||||||||
| Carrying Amount |
Market Value |
Carrying Amount |
Market Value | |||||||||||
| (thousands of dollars) |
||||||||||||||
| Debentures: |
||||||||||||||
| 9¾% Series F, due 2002 |
$ |
– |
|
$ |
– |
$ |
100,000 |
|
$ |
102,868 | ||||
| 7½% Series, due 2006 |
|
75,000 |
|
|
81,889 |
|
75,000 |
|
|
79,277 | ||||
| 8.375% due 2011 |
|
200,000 |
|
|
226,128 |
|
200,000 |
|
|
218,794 | ||||
| 7.625% due 2012 |
|
200,000 |
|
|
218,166 |
|
– |
|
|
– | ||||
| 8% Series, due 2026 |
|
75,000 |
|
|
79,017 |
|
75,000 |
|
|
78,343 | ||||
| Medium-term notes, 7.75% series, due 2005 |
|
25,000 |
|
|
27,342 |
|
25,000 |
|
|
26,812 | ||||
| Medium-term notes, 6.89% series, due 2007 |
|
17,500 |
|
|
18,781 |
|
17,500 |
|
|
17,973 | ||||
| Medium-term notes, 6.27% series, due 2008 |
|
25,000 |
|
|
25,946 |
|
25,000 |
|
|
24,865 | ||||
| Medium-term notes, 7.59% series, due 2017 |
|
25,000 |
|
|
26,711 |
|
25,000 |
|
|
25,555 | ||||
| Medium-term notes, 7.78% series, due 2022 |
|
25,000 |
|
|
25,725 |
|
25,000 |
|
|
25,124 | ||||
| Medium-term notes, 7.92% series, due 2027 |
|
25,000 |
|
|
26,134 |
|
25,000 |
|
|
25,327 | ||||
| Medium-term notes, 6.76% series, due 2027 |
|
7,500 |
|
|
6,870 |
|
7,500 |
|
|
6,813 | ||||
| Unamortized discount |
|
(6,534 |
) |
|
– |
|
(5,103 |
) |
|
– | ||||
|
|
693,466 |
|
|
594,897 |
|
|||||||||
| Revolving credit facility and commercial paper |
|
100,000 |
|
|
100,000 |
|
200,000 |
|
|
200,000 | ||||
| Industrial development revenue bonds: |
||||||||||||||
| Variable-rate bonds: |
||||||||||||||
| Tax-exempt Series A, due 2028 |
|
50,000 |
|
|
50,000 |
|
50,000 |
|
|
50,000 | ||||
| Fixed-rate bonds: |
||||||||||||||
| 7.30% 1992 Series A, due 2027 |
|
30,000 |
|
|
30,600 |
|
30,000 |
|
|
30,900 | ||||
| 7.50% 1992 Series B, due 2032 |
|
100,000 |
|
|
102,000 |
|
100,000 |
|
|
103,000 | ||||
| 6.50% 1993 Series A, due 2033 |
|
75,000 |
|
|
75,000 |
|
75,000 |
|
|
75,000 | ||||
| 6.10% 1999 Series A, due 2038 |
|
12,410 |
|
|
13,744 |
|
12,410 |
|
|
13,310 | ||||
| 5.95% 1999 Series C, due 2038 |
|
14,320 |
|
|
15,322 |
|
14,320 |
|
|
15,287 | ||||
| 5.55% 1999 Series D, due 2038 |
|
8,270 |
|
|
8,332 |
|
8,270 |
|
|
8,311 | ||||
| Unamortized discount |
|
(3,169 |
) |
|
– |
|
(3,276 |
) |
|
– | ||||
|
|
236,831 |
|
|
236,724 |
|
|||||||||
| Other |
|
20,556 |
|
|
– |
|
22,371 |
|
|
– | ||||
|
|
1,100,853 |
|
|
1,103,992 |
|
|||||||||
| Less: current maturities |
|
(8,705 |
) |
|
(307,641 |
) |
||||||||
| Long-term debt, less current maturities |
$ |
1,092,148 |
|
$ |
796,351 |
|
||||||||
72
In May 2002, the Company issued $200 million in Senior Unsecured Notes, due 2012, bearing interest at 7.625%. The net proceeds from the sale of the Senior Unsecured Notes were used to redeem the $100 million 9¾% Debentures, Series F, in June 2002, and to reduce outstanding revolving credit loans.
In May 2002, the Company replaced the existing $350 million revolving credit facility that was to expire in June 2002 with a $125 million three-year facility and a $125 million 364-day facility. Interest rates for the new facility are calculated at either the London Interbank Offering Rate (LIBOR) plus or minus a competitive margin, or the greater of the prime rate or one half of one percent plus the Federal Funds rate. The Company has designated $100 million of the total facility as long-term debt and uses the remaining $150 million for working capital purposes and has designated the related outstanding amounts as short-term debt.
In October 2002, the Company entered into a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent new borrowing capacity. Interest rates for the new program are calculated at the then current commercial paper rate. At December 31, 2002, $30 million was outstanding on the commercial paper program.
The interest rate on the tax-exempt variable-rate IDRBs averaged 2.82 percent in 2002 and 3.81 percent in 2001. The rates for the variable-rate IDRBs are established on a weekly basis. The Company has the option to convert from the current weekly rates to daily rates, term rates, or variable-term rates.
The fair value of the revolving credit facility approximates carrying value. Market values for the debentures and fixed-rate IDRBs were determined based on dealer quotes using trading records for December 31, 2002 and 2001, as applicable, and other secondary sources which are customarily consulted for data of this kind. The carrying values of variable-rate IDRBs were used as estimates of fair value based upon the variable interest rates of the bonds.
Estimated maturities of long-term debt for the next five years are $8.7 million, $7.3 million, $128.5 million, $76 million, and $17.5 million, respectively.
The $7.5 million medium-term notes, 6.76% series, due 2027 contains a put feature at the discretion of the bondholder on one date only in 2007. If the bondholder does not exercise the put on that date, the notes will reach maturity in 2027. If the bondholder exercises the put, the maturities of long-term debt for 2007 will total $25 million.
The Company is pursuing the issuance of $165 million of Clark County, Nevada Industrial Development Revenue Bonds (IDRBs). The net proceeds from the sale of the bonds will be used, in part, to refinance the $30 million 7.30% 1992 Series A, due 2027 and the $100 million 7.50% 1992 Series B, due 2032 fixed-rate IDRBs. The remainder of the proceeds will be used to finance construction expenditures in southern Nevada.
73
NOTE 7 SHORT-TERM DEBT
As discussed in Note 6, a portion of the $250 million revolving credit facility is designated as short-term debt. In May 2002, the Company replaced the existing $350 million revolving credit facility that was to expire in June 2002 with a $125 million three-year facility and a $125 million 364-day facility. Of the total $250 million facility, $150 million is designated as short-term debt. Interest rates for the new facility are calculated at either LIBOR plus or minus a competitive margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate.
Short-term borrowings were $53 million and $93 million at December 31, 2002 and 2001, respectively. The weighted-average interest rates on these borrowings were 2.35 percent at December 31, 2002 and 2.47 percent at December 31, 2001.
NOTE 8 COMMITMENTS AND CONTINGENCIES
Legal and Regulatory Proceedings. The Company has been named as defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is subject will have a material adverse impact on its financial position or results of operations.
74
NOTE 9 EMPLOYEE BENEFITS
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. Southwest also provides postretirement benefits other than pensions (PBOP) to its qualified retirees for health care, dental, and life insurance benefits.
The following tables set forth the retirement plan and PBOP funded status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.
| Qualified Retirement Plan |
PBOP |
|||||||||||||||||
| 2002 |
2001 |
2002 |
2001 |
|||||||||||||||
| (thousands of dollars) |
||||||||||||||||||
| Change in benefit obligations |
||||||||||||||||||
| Benefit obligation for service rendered to date at beginning of year (PBO/APBO) |
$ |
288,046 |
|
$ |
262,981 |
|
$ |
28,204 |
|
$ |
26,245 |
| ||||||
| Service cost |
|
11,585 |
|
|
11,057 |
|
|
595 |
|
|
591 |
| ||||||
| Interest cost |
|
20,568 |
|
|
18,805 |
|
|
1,992 |
|
|
1,856 |
| ||||||
| Actuarial loss (gain) |
|
7,905 |
|
|
2,403 |
|
|
1,966 |
|
|
812 |
| ||||||
| Benefits paid |
|
(8,700 |
) |
|
(7,200 |
) |
|
(1,450 |
) |
|
(1,300 |
) | ||||||
| Benefit obligation at end of year (PBO/APBO) |
$ |
319,404 |
|
$ |
288,046 |
|
$ |
31,307 |
|
$ |
28,204 |
| ||||||
| Change in plan assets |
||||||||||||||||||
| Market value of plan assets at beginning of year |
$ |
274,103 |
|
$ |
281,280 |
|
$ |
12,402 |
|
$ |
10,958 |
| ||||||
| Actual return on plan assets |
|
(28,344 |
) |
|
23 |
|
|
(647 |
) |
|
218 |
| ||||||
| Employer contributions |
|
5,100 |
|
|
– |
|
|
1,157 |
|
|
1,226 |
| ||||||
| Benefits paid |
|
(8,700 |
) |
|
(7,200 |
) |
|
– |
|
|
– |
| ||||||
| Market value of plan assets at end of year |
$ |
242,159 |
|
$ |
274,103 |
|
$ |
12,912 |
|
$ |
12,402 |
| ||||||
| Funded status |
$ |
(77,245 |
) |
$ |
(13,943 |
) |
$ |
(18,395 |
) |
$ |
(15,802 |
) | ||||||
| Unrecognized net actuarial loss (gain) |
|
52,936 |
|
|
(10,698 |
) |
|
6,760 |
|
|
2,367 |
| ||||||
| Unrecognized transition obligation (2004/2012) |
|
795 |
|
|
1,632 |
|
|
8,669 |
|
|
9,537 |
| ||||||
| Unrecognized prior service cost |
|
66 |
|
|
123 |
|
|
– |
|
|
– |
| ||||||
| Prepaid (accrued) benefit cost |
$ |
(23,448 |
) |
$ |
(22,886 |
) |
$ |
(2,966 |
) |
$ |
(3,898 |
) | ||||||
| Weighted-average assumptions |
||||||||||||||||||
| Discount rate as of December 31 |
|
6.75 |
% |
|
7.25 |
% |
|
6.75 |
% |
|
7.25 |
% | ||||||
| Expected return on plan assets as of January 1 |
|
9.25 |
% |
|
9.25 |
% |
|
9.25 |
% |
|
9.25 |
% | ||||||
| Rate of compensation increase as of December 31 |
|
4.25 |
% |
|
4.75 |
% |
|
4.25 |
% |
|
4.75 |
% | ||||||
For PBOP measurement purposes, the per capita cost of covered health care benefits is assumed to increase five percent annually. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. The assumed annual rate of increase noted above applies to the benefit obligations of pre-1989 retirees only.
75
The Company’s pension and related benefits plans utilize various assumptions which impact the expense and funding levels of these plans. The Company is lowering the expected rate of return on plan assets assumption for these plans from 9.25% to 8.95% for 2003. The lower rate of return reflects anticipated investment returns on a long-term basis considering asset mix and historical investment returns. This change, coupled with reductions in the discount rate and salary increase assumptions, will result in a $1.5 million increase in pension expense for 2003. In addition, pension plan funding is expected to increase from $5.1 million in 2002 to approximately $11.2 million in 2003. The increase is primarily due to lower-than-expected returns on plan assets during 2002.
COMPONENTS OF NET PERIODIC BENEFIT COST:
| Qualified Retirement Plan |
PBOP |
|||||||||||||||||||||||
| 2002 |
2001 |
2000 |
2002 |
2001 |
2000 |
|||||||||||||||||||
| (thousands of dollars) |
||||||||||||||||||||||||
| Service cost |
$ |
11,585 |
|
$ |
11,057 |
|
$ |
10,455 |
|
$ |
595 |
|
$ |
591 |
|
$ |
558 |
| ||||||
| Interest cost |
|
20,568 |
|
|
18,805 |
|
|
16,919 |
|
|
1,992 |
|
|
1,856 |
|
|
1,762 |
| ||||||
| Expected return on plan assets |
|
(27,178 |
) |
|
(25,383 |
) |
|
(22,681 |
) |
|
(1,184 |
) |
|
(1,073 |
) |
|
(858 |
) | ||||||
| Amortization of prior service costs |
|
57 |
|
|
57 |
|
|
57 |
|
|
– |
|
|
– |
|
|
– |
| ||||||
| Amortization of unrecognized |
|
837 |
|
|
837 |
|
|
837 |
|
|
867 |
|
|
867 |
|
|
867 |
| ||||||
| Amortization of net (gain) loss |
|
(207 |
) |
|
(568 |
) |
|
(694 |
) |
|
– |
|
|
– |
|
|
– |
| ||||||
| Net periodic benefit cost |
$ |
5,662 |
|
$ |
4,805 |
|
$ |
4,893 |
|
$ |
2,270 |
|
$ |
2,241 |
|
$ |
2,329 |
| ||||||
In addition to the retirement plan, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The plan is noncontributory with defined benefits. Plan costs were $3 million in 2002, $2.9 million in 2001, and $2.2 million in 2000. The accumulated benefit obligation of the plan was $22 million at December 31, 2002.
The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches one-half of amounts deferred. The maximum matching contribution is three percent of an employee’s annual compensation. The cost of the plan was $3.1 million in 2002, $3 million in 2001, and $3 million in 2000. Northern has a separate plan, the cost and liability for which are not significant.
Southwest has a deferred compensation plan for all officers and members of the Board of Directors. The plan provides the opportunity to defer up to 100 percent of annual cash compensation. Southwest matches one-half of amounts deferred by officers. The maximum matching contribution is three percent of an officer’s annual salary. Payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150 percent of Moody’s Seasoned Corporate Bond Rate Index.
76
At December 31, 2002, the Company had two stock-based compensation plans. These plans are accounted for in accordance with APB Opinion No. 25 “Accounting for Stock Issued to Employees.” In connection with the stock-based compensation plans, the Company recognized compensation expense of $3 million in 2002, $3.1 million in 2001, and $970,000 in 2000.
With respect to the first plan, the Company may grant options to purchase shares of common stock to key employees and outside directors. Each option has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years. The options vest 40 percent at the end of year one and 30 percent at the end of years two and three. The grant date fair value of the options was estimated using the extended binomial option pricing model. The following assumptions were used in the valuation calculation:
| 2002 |
2001 |
2000 | ||||
| Dividend yield |
3.64% |
3.60% |
3.90% | |||
| Risk-free interest rate range |
1.70 to 2.63% |
2.17 to 3.82% |
4.74 to 4.86% | |||
| Expected volatility range |
23 to 31% |
22 to 27% |
25 to 30% | |||
| Expected life |
1 to 3 years |
1 to 3 years |
1 to 3 years | |||
The following tables summarize Company stock option plan activity and related information (thousands of options):
| 2002 |
2001 |
2000 | ||||||||||||||||
| Number of options |
Weighted- average exercise price |
Number of options |
Weighted- average exercise price |
Number of options |
Weighted- average exercise price | |||||||||||||
| Outstanding at the beginning of the year |
1,123 |
|
$ |
20.79 |
990 |
|
$ |
18.94 |
704 |
|
$ |
19.32 | ||||||
| Granted during the year |
320 |
|
|
21.97 |
317 |
|
|
23.23 |
297 |
|
|
17.96 | ||||||
| Exercised during the year |
(183 |
) |
|
16.95 |
(184 |
) |
|
15.07 |
(7 |
) |
|
15.80 | ||||||
| Forfeited during the year |
– |
|
|
– |
– |
|
|
– |
(4 |
) |
|
17.94 | ||||||
| Expired during the year |
– |
|
|
– |
– |
|
|
– |
– |
|
|
– | ||||||
| Outstanding at year end |
1,260 |
|
$ |
21.66 |
1,123 |
|
$ |
20.79 |
990 |
|
$ |
18.94 | ||||||
| Exercisable at year end |
677 |
|
$ |
21.46 |
597 |
|
$ |
21.00 |
591 |
|
$ |
24.18 | ||||||
The weighted-average grant-date fair value of options granted was $2.69 for 2002, $2.81 for 2001, and $2.51 for 2000. The exercise prices for the options outstanding range from $15.00 to $28.94. On December 31, 2002, the options outstanding had a weighted-average remaining contractual life of approximately 7.6 years.
77
In addition to the option plan, the Company may issue restricted stock in the form of performance shares to encourage key employees to remain in its employment to achieve short-term and long-term performance goals. Plan participants are eligible to receive a cash bonus (i.e., short-term incentive) and performances shares (i.e., long-term incentive). The performance shares vest after three years from issuance and are subject to a final adjustment as determined by the Board of Directors. The following table summarizes the activity of this plan (thousands of shares):
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
|||||||||
| Nonvested performance shares at beginning of year |
|
314 |
|
|
237 |
|
|
193 |
| |||
| Performance shares granted |
|
122 |
|
|
142 |
|
|
111 |
| |||
| Performance shares forfeited |
|
– |
|
|
– |
|
|
(6 |
) | |||
| Shares vested and issued |
|
(91 |
) |
|
(65 |
) |
|
(61 |
) | |||
| Nonvested performance shares at end of year |
|
345 |
|
|
314 |
|
|
237 |
| |||
| Average grant date fair value of award |
$ |
22.35 |
|
$ |
19.91 |
|
$ |
21.63 |
| |||
NOTE 10 INCOME TAXES
Income tax expense (benefit) consists of the following (thousands of dollars):
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
|||||||||
| Current: |
||||||||||||
| Federal |
$ |
5,546 |
|
$ |
27,750 |
|
$ |
(60,628 |
) | |||
| State |
|
3,462 |
|
|
2,078 |
|
|
(7,465 |
) | |||
|
|
9,008 |
|
|
29,828 |
|
|
(68,093 |
) | ||||
| Deferred: |
||||||||||||
| Federal |
|
14,819 |
|
|
(9,902 |
) |
|
76,334 |
| |||
| State |
|
(2,410 |
) |
|
(341 |
) |
|
5,387 |
| |||
|
|
12,409 |
|
|
(10,243 |
) |
|
81,721 |
| ||||
| Total income tax expense |
$ |
21,417 |
|
$ |
19,585 |
|
$ |
13,628 |
| |||
|
Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
| ||||||||||||
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
|||||||||
| Deferred federal and state: |
||||||||||||
| Property-related items |
$ |
44,491 |
|
$ |
19,560 |
|
$ |
28,184 |
| |||
| Purchased gas cost adjustments |
|
(29,087 |
) |
|
(26,975 |
) |
|
56,321 |
| |||
| Employee benefits |
|
(5,113 |
) |
|
(2,121 |
) |
|
(3,687 |
) | |||
| All other deferred |
|
2,986 |
|
|
161 |
|
|
1,771 |
| |||
| Total deferred federal and state |
|
13,277 |
|
|
(9,375 |
) |
|
82,589 |
| |||
| Deferred ITC, net |
|
(868 |
) |
|
(868 |
) |
|
(868 |
) | |||
| Total deferred income tax expense |
$ |
12,409 |
|
$ |
(10,243 |
) |
$ |
81,721 |
| |||
78
| The consolidated effective income tax rate for the period ended December 31, 2002 and the two prior periods differs from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:
| |||||||||
| YEAR ENDED DECEMBER 31, |
2002 |
2001 |
2000 |
||||||
| Federal statutory income tax rate |
35.0 |
% |
35.0 |
% |
35.0 |
% | |||
| Net state tax liability |
1.0 |
|
3.2 |
|
2.9 |
| |||
| Property-related items |
– |
|
1.5 |
|
1.7 |
| |||
| Effect of closed tax years and resolved issues |
– |
|
(4.4 |
) |
(11.6 |
) | |||
| Tax credits |
(1.3 |
) |
(1.5 |
) |
(1.7 |
) | |||
| Tax exempt interest |
– |
|
– |
|
(0.3 |
) | |||
| Corporate owned life insurance |
– |
|
(0.5 |
) |
(0.8 |
) | |||
| All other differences |
(1.9 |
) |
1.2 |
|
1.0 |
| |||
| Consolidated effective income tax rate |
32.8 |
% |
34.5 |
% |
26.2 |
% | |||
Deferred tax assets and liabilities consist of the following (thousands of dollars):
| DECEMBER 31, |
2002 |
2001 | |||||
| Deferred tax assets: |
|||||||
| Deferred income taxes for future amortization of ITC |
$ |
8,574 |
|
$ |
9,280 | ||
| Employee benefits |
|
25,650 |
|
|
23,214 | ||
| Alternative minimum tax |
|
23,874 |
|
|
– | ||
| Other |
|
4,195 |
|
|
6,601 | ||
| Valuation Allowance |
|
– |
|
|
– | ||
|
|
62,293 |
|
|
39,095 | |||
| Deferred tax liabilities: |
|||||||
| Property-related items, including accelerated depreciation |
|
247,954 |
|
|
208,285 | ||
| Regulatory balancing accounts |
|
4,349 |
|
|
33,436 | ||
| Property-related items previously flowed through |
|
13,609 |
|
|
13,713 | ||
| Unamortized ITC |
|
13,801 |
|
|
14,668 | ||
| Debt-related costs |
|
4,378 |
|
|
4,792 | ||
| Other |
|
4,476 |
|
|
6,159 | ||
|
|
288,567 |
|
|
281,053 | |||
| Net deferred tax liabilities |
$ |
226,274 |
|
$ |
241,958 | ||
| Current |
$ |
(3,084 |
) |
$ |
24,154 | ||
| Noncurrent |
|
229,358 |
|
|
217,804 | ||
| Net deferred tax liabilities |
$ |
226,274 |
|
$ |
241,958 | ||
79
NOTE 11 SEGMENT INFORMATION
Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, transporting, and distributing natural gas. Revenues are generated from the sale and transportation of natural gas. The construction services segment is engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
The accounting policies of the reported segments are the same as those described within Note 1 –Summary of Significant Accounting Policies. Northern accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2002 and 2001, consolidated accounts receivable included $6 million and $4.3 million, respectively, which were not eliminated during consolidation.
The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2002 is as follows (thousands of dollars):
| 2002 |
Gas Operations |
Construction Services |
Adjustments |
Total | |||||||||
| Revenues from unaffiliated customers |
$ |
1,115,900 |
$ |
134,625 |
$ |
1,250,525 | |||||||
| Intersegment sales |
|
– |
|
70,384 |
|
70,384 | |||||||
| Total |
$ |
1,115,900 |
$ |
205,009 |
$ |
1,320,909 | |||||||
| Interest expense |
$ |
78,505 |
$ |
1,466 |
$ |
79,971 | |||||||
| Depreciation and amortization |
$ |
115,175 |
$ |
15,035 |
$ |
130,210 | |||||||
| Income tax expense |
$ |
18,493 |
$ |
2,924 |
$ |
21,417 | |||||||
| Segment income |
$ |
39,228 |
$ |
4,737 |
$ |
43,965 | |||||||
| Segment assets |
$ |
2,290,407 |
$ |
87,521 |
$ |
2,377,928 | |||||||
| Capital expenditures |
$ |
263,576 |
$ |
19,275 |
$ |
282,851 | |||||||
| 2001 |
Gas Operations |
Construction Services |
Adjustments |
Total | |||||||||
| Revenues from unaffiliated customers |
$ |
1,193,102 |
$ |
135,655 |
$ |
1,328,757 | |||||||
| Intersegment sales |
|
– |
|
67,931 |
|
67,931 | |||||||
| Total |
$ |
1,193,102 |
$ |
203,586 |
$ |
1,396,688 | |||||||
| Interest expense |
$ |
78,746 |
$ |
1,985 |
$ |
80,731 | |||||||
| Depreciation and amortization |
$ |
104,498 |
$ |
13,950 |
$ |
118,448 | |||||||
| Income tax expense |
$ |
16,098 |
$ |
3,487 |
$ |
19,585 | |||||||
| Segment income |
$ |
32,626 |
$ |
4,530 |
$ |
37,156 | |||||||
| Segment assets |
$ |
2,289,111 |
$ |
83,228 |
$ |
(2,727 |
) |
$ |
2,369,612 | ||||
| Capital expenditures |
$ |
248,352 |
$ |
17,228 |
$ |
265,580 | |||||||
80
| 2000 |
Gas Operations |
Construction Services |
Adjustments |
Total | |||||||||
| Revenues from unaffiliated customers |
$ |
870,711 |
$ |
107,686 |
$ |
978,397 | |||||||
| Intersegment sales |
|
– |
|
55,690 |
|
55,690 | |||||||
| Total |
$ |
870,711 |
$ |
163,376 |
$ |
1,034,087 | |||||||
| Interest expense |
$ |
68,892 |
$ |
1,779 |
$ |
70,671 | |||||||
| Depreciation and amortization |
$ |
94,689 |
$ |
11,951 |
$ |
106,640 | |||||||
| Income tax expense |
$ |
10,277 |
$ |
3,351 |
$ |
13,628 | |||||||
| Segment income |
$ |
33,908 |
$ |
4,403 |
$ |
38,311 | |||||||
| Segment assets |
$ |
2,154,641 |
$ |
79,790 |
$ |
(2,094 |
) |
$ |
2,232,337 | ||||
| Capital expenditures |
$ |
205,161 |
$ |
18,079 |
$ |
223,240 | |||||||
Construction services segment assets include deferred tax assets of $2.5 million in 2001, which were netted against gas operations segment deferred tax liabilities during consolidation. Construction services segment liabilities include taxes payable of $204,000 in 2001, which were netted against gas operations segment tax receivable during consolidation. Construction services segment assets include deferred tax assets of $2.1 million in 2000, which were netted against gas operations segment deferred tax liabilities during consolidation.
81
NOTE 12 QUARTERLY FINANCIAL DATA (UNAUDITED)
| Quarter Ended | ||||||||||||||
| March 31 |
June 30 |
September 30 |
December 31 | |||||||||||
| (thousands of dollars, except per share amounts) |
||||||||||||||
| 2002 |
||||||||||||||
| Operating revenues |
$ |
499,501 |
$ |
261,123 |
|
$ |
223,863 |
|
$ |
336,422 | ||||
| Operating income (loss) |
|
80,317 |
|
7,044 |
|
|
(3,337 |
) |
|
62,475 | ||||
| Net income (loss) |
|
42,896 |
|
(20,610 |
) |
|
(16,136 |
) |
|
37,815 | ||||
| Basic earnings (loss) per common share* |
|
1.32 |
|
(0.63 |
) |
|
(0.49 |
) |
|
1.14 | ||||
| Diluted earnings (loss) per common share* |
|
1.30 |
|
(0.63 |
) |
|
(0.49 |
) |
|
1.13 | ||||
| 2001 |
||||||||||||||
| Operating revenues |
$ |
487,498 |
$ |
278,960 |
|
$ |
246,094 |
|
$ |
384,136 | ||||
| Operating income (loss) |
|
74,106 |
|
1,111 |
|
|
(4,597 |
) |
|
63,363 | ||||
| Net income (loss) |
|
33,809 |
|
(11,140 |
) |
|
(16,488 |
) |
|
30,975 | ||||
| Basic earnings (loss) per common share* |
|
1.06 |
|
(0.35 |
) |
|
(0.51 |
) |
|
0.96 | ||||
| Diluted earnings (loss) per common share* |
|
1.05 |
|
(0.35 |
) |
|
(0.51 |
) |
|
0.95 | ||||
| 2000 |
||||||||||||||
| Operating revenues |
$ |
296,815 |
$ |
197,634 |
|
$ |
198,962 |
|
$ |
340,676 | ||||
| Operating income (loss) |
|
56,619 |
|
2,583 |
|
|
(4,197 |
) |
|
73,625 | ||||
| Net income (loss) |
|
25,198 |
|
(9,729 |
) |
|
(9,680 |
) |
|
32,522 | ||||
| Basic earnings (loss) per common share* |
|
0.81 |
|
(0.31 |
) |
|
(0.31 |
) |
|
1.03 | ||||
| Diluted earnings (loss) per common share* |
|
0.80 |
|
(0.31 |
) |
|
(0.31 |
) |
|
1.02 | ||||
* The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted average number of common shares outstanding.
The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for the interim periods do not reliably reflect overall trends and changes in the operations of the Company. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.
82
NOTE 13 MERGER-RELATED LITIGATION SETTLEMENTS
Litigation related to the now terminated acquisition of the Company by ONEOK, Inc. (ONEOK) and the rejection of competing offers from Southern Union Company (Southern Union) was resolved during 2002. In August 2002, the Company reached final settlements with both Southern Union and ONEOK related to this litigation. The Company paid Southern Union $17.5 million to resolve all remaining Southern Union claims against the Company and its officers. ONEOK paid the Company $3 million to resolve all claims between the Company and ONEOK. The net after-tax impact of the settlements was a $9 million charge and was reflected in the second quarter 2002 financial statements. The Company and one of its insurance providers were in dispute over whether the insurance coverage applied to the Southern Union settlement and related litigation defense costs. Because of the dispute, the Company did not recognize any benefit for potential insurance recoveries related to the Southern Union settlement in the second quarter.
In December 2002, the Company negotiated a $16.25 million settlement with the insurance provider related to the coverage dispute. Income from the settlement was recognized in the fourth quarter of 2002 and amounted to $9 million after-tax.
83
Report of Independent Accountants
To the Shareholders of
Southwest Gas Corporation:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2002, and the results of their operations and their cash flows for the year ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2001 and for the two years then ended were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those statements in their report dated February 8, 2002.
PricewaterhouseCoopers LLP
Los Angeles, California
March 3, 2003
84
Report of Independent Public Accountants
To the Shareholders of
Southwest Gas Corporation:
We have audited the accompanying consolidated balance sheets of Southwest Gas Corporation (a California corporation) and its subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of the Southwest Gas Corporation and its subsidiaries as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Las Vegas, Nevada
February 8, 2002
The aforementioned report on the consolidated balance sheets of Southwest Gas Corporation and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2001 is a copy of a previously issued Arthur Andersen LLP report. Arthur Andersen LLP has not reissued this report.
85
Shareholder Information
| Stock Listing Information Southwest Gas Corporation’s common stock is listed on the New York Stock Exchange under the ticker symbol “SWX.” Quotes may be obtained in daily financial newspapers or some local newspapers where it is listed under “SoWestGas.”
Annual Meeting The Annual Meeting of Shareholders will be held on May 8, 2003 at 10:00 a.m. at the Rio Suites Hotel and Casino, I-15 and Flamingo Road, Las Vegas, Nevada.
Dividend Reinvestment and Stock Purchase Plan The Southwest Gas Corporation Dividend Reinvestment and Stock Purchase Plan (DRSPP) provides its shareholders, natural gas customers, employees and residents of Arizona, California and Nevada with a simple and convenient method of investing cash dividends in additional shares of the Company’s common stock without payment of any brokerage commission.
The DRSPP features include: Initial investments of $100, up to $100,000 annually Automatic investing No commissions on purchases Safekeeping for common stock certificates
For more information contact: Shareholder Services, Southwest Gas Corporation, P.O. Box 98511, Las Vegas, NV 89193-8511 or call (800) 331-1119.
Dividends Dividends on common stock are declared quarterly by the Board of Directors. As a general rule, they are payable on the first day of March, June, September and December. |
Investor Relations Southwest Gas Corporation is committed to providing relevant and complete investment information to shareholders, individual investors and members of the investment community. Additional copies of the Company’s 2002 Annual Report on Form 10-K, without exhibits, as filed with the Securities and Exchange Commission may be obtained upon request free of charge. Additional financial information may be obtained by contacting Kenneth J. Kenny, Investor Relations, Southwest Gas Corporation, P. O. Box 98510, Las Vegas, NV 89193-8510 or by calling (702) 876-7237.
Southwest Gas Corporation information is also available on the Internet at www.swgas.com. For non-financial information, please call (702) 876-7011
Transfer Agent Shareholder Services Southwest Gas Corporation P.O. Box 98511 Las Vegas, NV 89193-8511
Registrar Southwest Gas Corporation P.O. Box 98510 Las Vegas, NV 89193-8510
Auditors PricewaterhouseCoopers 350 S. Grand Avenue Los Angeles, CA 90071 |
86
EXHIBIT 21.01
SOUTHWEST GAS CORPORATION
LIST OF SUBSIDIARIES OF THE REGISTRANT
AT DECEMBER 31, 2002
| SUBSIDIARY NAME |
|
STATE OF INCORPORATION |
| |
|
|
| LNG Energy, Inc. |
|
Nevada |
| Paiute Pipeline Company |
|
Nevada |
| Northern Pipeline Construction Co. |
|
Nevada |
| Southwest Gas Transmission Company |
|
Partnership between Southwest Gas Corporation and Utility Financial Corp. |
| Southwest Gas Capital I |
|
Delaware |
| Utility Financial Corp. |
|
Nevada |
EXHIBIT 23.01
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-74520 and 333-98995) and Form S-8 (File No. 333-98729) of Southwest Gas Corporation of our report dated March 3, 2003 relating to the financial statements which are incorporated by reference in this Form 10-K.
PRICEWATERHOUSECOOPERS LLP
Los Angeles, California
March 25, 2003