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Form 10-K for Southwest Gas Corporation

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, 2003

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION

(Exact name of registrant as specified in its charter)


California		88-0085720
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5241 Spring Mountain Road Post Office Box 98510 Las Vegas, Nevada		89193-8510
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (702) 876-7237

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, $1 par value		New York Stock Exchange, Inc.
		Pacific Exchange, Inc.
7.70% Preferred Trust Securities		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 þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is an accelerated filer. Yes þ No ¨

Aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant:

$715,068,782 as of June 30, 2003

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 34,517,481 shares as of March 1, 2004

DOCUMENTS INCORPORATED BY REFERENCE


Description		Part Into Which Incorporated

Annual Report to Shareholders for the Year Ended December 31, 2003		Parts I, II, and IV
2004 Proxy Statement		Part III

TABLE OF CONTENTS

PART I


		PAGE
Item 1.	BUSINESS	1

	Natural Gas Operations	1

	General Description	1

	Rates and Regulation	2

	Demand for Natural Gas	3

	Natural Gas Supply	3

	Competition	4

	Environmental Matters	5

	Employees	5

	Construction Services	5

	Company Risk Factors	6

Item 2.	PROPERTIES	8

Item 3.	LEGAL PROCEEDINGS	10

Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	10

	PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	10

Item 6.	SELECTED FINANCIAL DATA	10

Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	10

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	10

Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	10

Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	11

Item 9A.	CONTROLS AND PROCEDURES	11

	PART III

Item 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	12

Item 11.	EXECUTIVE COMPENSATION	13

Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	13

Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	14

Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	14

	PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K	15

	List of Exhibits	16

SIGNATURES		20

PART I

Item 1. BUSINESS

Southwest Gas Corporation (the “Company”) was 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. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

Financial information concerning the Company’s business segments is included in Note 11 of the Notes to Consolidated Financial Statements which is included in the 2003 Annual Report to Shareholders and is incorporated herein by reference.

The Company maintains a website (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 website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”).

NATURAL GAS OPERATIONS

General Description

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”). NPL is not regulated by the state utilities commissions in any of its operating areas.

As of December 31, 2003, Southwest purchased, transported, and distributed natural gas to 1,531,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. There were 67,000 customers added to the system during 2003 (and an additional 9,000 in central Arizona associated with the acquisition of Black Mountain Gas Company (“BMG”) in October 2003).

The table below lists the percentage of operating margin (operating revenues less net cost of gas) by major customer class for the years indicated:


	Distribution		Transportation
For the Year Ended	Residential and Small Commercial	Other Sales Customers	Transportation
December 31, 2003	84%	6%	10%
December 31, 2002	83%	7%	10%
December 31, 2001	82%	8%	10%

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.

Transportation of customer-secured gas to end-users accounted for 54 percent of total system throughput in 2003. Although the volumes were significant, these customers provide a much smaller proportionate share of operating margin. Customers who utilized this service transported 134 million dekatherms in 2003, 133 million dekatherms in 2002, and 127 million dekatherms in 2001.

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 and Regulation

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 that are intended to allow 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. Southwest may make additional requests to adjust rates, 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 2003 Annual Report to Shareholders.

The table below lists the docketed general rate filings last initiated and the status of such filing within each ratemaking area:


Ratemaking Area	Type of Filing	Month Filed	Month Final Rates Effective
Arizona	General rate case	May 2000	November 2001
California:
Northern and Southern	General rate case	February 2002	Pending
Nevada:
Northern and Southern	General rate case	March 2004	Pending
FERC:
Paiute	General rate case	July 1996	January 1997

Demand for Natural Gas

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 significant backlog on its orders for gas service.

Natural Gas Supply

Southwest is responsible for acquiring (purchasing) and arranging delivery of (transporting) natural gas to its system for all sales customers.

The primary objective of Southwest with respect to acquiring 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 2003, Southwest acquired gas supplies from 48 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 a separate natural gas supply portfolio 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 five years, as the weighted average delivered cost of natural gas has ranged from a low of 28 cents per therm in 1999 to a high of 55 cents per therm in 2001. During 2003, Southwest paid an average of 46 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 portfolios, Southwest uses the fixed-price arrangements noted above, but does not currently utilize other stand-alone derivative financial instruments. In the future stand-alone derivatives may be used to hedge against possible price increases. However, any such change would be undertaken with the knowledge of Southwest’s various regulatory commissions.

Storage capability can influence the average annual price of gas, as storage allows a company to purchase natural gas in larger quantities during the off-peak season and store it for use in high demand periods when prices may be greater. Southwest currently has no storage availability in its Arizona or southern Nevada rate jurisdictions. Limited storage capabilities exist in southern and northern California and northern Nevada. A contract with Southern California Gas Company is intended for delivery only within Southwest’s southern California rate jurisdiction. In addition, a contract with Paiute for its LNG facility in northern Nevada and northern California allows for peaking capability only. Gas is purchased for injection during the off-peak period for use in the high demand months, but is again limited in its impact on the overall price. The LNG plant is currently leased from a third party, and the contract expires in July 2005. While

negotiations continue between the owner of the plant and Paiute to allow for the purchase of the facility, preparations are being made to provide alternatives to the leased facility to be in service by July 2005.

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, Southern California Gas Company and Paiute. Supply and pipeline capacity availability on both short- and long-term bases is continually monitored by 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 its service territories. As the need arises to acquire additional capacity on one of the interstate pipeline transmission systems, primarily due to customer growth, Southwest will continue to consider available options to obtain that 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. Historically, Southwest received transportation service from El Paso to its Arizona service territories under a full requirements contract. Under full requirements service, El Paso was obligated to transport all of a customer’s gas requirements each day, and the customer was 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 have been full requirements customers, while El Paso has transported gas for its customers in California and Nevada subject to a specific maximum daily quantity, or contract demand limitation.

Since November 1999, the Federal Energy Regulatory Commission has been examining capacity allocation issues on the El Paso system in several proceedings. This examination resulted in a series of orders by the FERC in which all of the major full requirements transportation service agreements on the El Paso system, including the agreement by which Southwest obtained the transportation of gas supplies to its Arizona service areas, were converted to contract demand-type service agreements, with fixed maximum service limits, effective September 2003. At that time, all of the transportation capacity on the system was allocated among the shippers. In order to help ensure that the converting full requirements shippers would have adequate capacity to meet their needs, El Paso was authorized to expand the capacity on its system by adding compression.

The FERC is continuing to examine issues related to the implementation of the full requirements conversion. Petitions for judicial review of the FERC’s orders mandating the conversion have been filed.

Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. Southwest has had adequate capacity for its customers’ needs during the 2003/2004 heating season to date and management believes adequate capacity exists for the remainder of the heating season. Additional costs may be incurred to acquire capacity in the future as a result of the FERC order. However, it is anticipated that any additional costs would be collected from customers principally through the PGA mechanism.

Competition

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.

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. Southwest attempts 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.

Environmental Matters

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 can help energy users to comply with stricter environmental standards.

Employees

At December 31, 2003, the natural gas operations segment had 2,550 regular full-time equivalent employees, of which 507 full-time equivalent non-exempt employees in central Arizona were 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.

CONSTRUCTION SERVICES

Northern Pipeline Construction Co. is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL 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.

NPL business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with NPL 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 2003, approximately 94 percent of revenue was earned under unit-price contracts. As of December 31, 2003 no significant backlog existed with respect to outstanding construction contracts.

Materials used by NPL in its pipeline construction activities are typically specified, purchased, and supplied by NPL’s customers. Construction contracts also contain provisions which make customers generally liable for remediating environmental hazards encountered during the construction process. Such hazards might include digging in an area that was contaminated prior to construction, finding endangered animals, digging in historically significant sites, etc.

Otherwise, NPL’s operations have minimal environmental impact (dust control, normal waste disposal, handling harmful materials, etc.).

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. NPL currently operates in approximately 17 major markets nationwide. Its customers are the primary LDCs in those markets. During 2003, NPL served 41 major customers, with Southwest accounting for approximately 30 percent of their revenues. With the exception of one other customer that accounted for approximately 12 percent of revenue, no other customer had a relatively significant contribution to NPL revenues.

Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2003, NPL had 1,822 regular full-time equivalent employees. Employment peaked in May 2003 when there were 2,040 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.

NPL is not directly affected by regulations promulgated by the ACC, PUCN, CPUC or FERC in its construction services. NPL is an unregulated construction subsidiary of Southwest Gas Corporation. However, because NPL performs work for the regulated natural gas segment of the Company, its construction costs are subject indirectly to “prudency reviews” just as any other capital work that is performed by third parties or directly by Southwest. However, such “prudency reviews” would not bring NPL under the regulatory jurisdiction of any of the commissions noted above.

COMPANY RISK FACTORS

Although the Company is not able to predict all factors that may affect future results, described below are some of the risk factors identified by the Company that may have a negative impact on our future financial performance or affect whether we achieve the goals or expectations expressed or implied in any forward-looking statements contained herein. 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 our earnings, may be reduced 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 2004, 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 disallowance of purchased gas costs may reduce 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, transportation capacity cost increases, 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 our strategies in managing price risk.

Governmental policies and regulatory actions can reduce our earnings.

Governmental policies and regulatory actions, including those of the ACC, the CPUC, the FERC, and the PUCN relating 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 reduce our earnings. Risks and uncertainties relating to delays in obtaining regulatory approvals, conditions imposed in regulatory approvals, or determinations in regulatory investigations can also impact financial performance.

We are unable to predict what types of conditions might be imposed on Southwest or what types of determinations might be made in pending or future regulatory proceedings or investigations. We nevertheless believe that it is not uncommon for conditions to be imposed in regulatory proceedings, for Southwest to agree to conditions as part of a settlement of a regulatory proceeding, or for determinations to be made in regulatory investigations that will reduce our earnings and liquidity. For example, we may request recovery of a particular operating expense in a general rate case filing that a regulator disallows.

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 2003, we added 67,000 customers, a five percent growth rate. Another 9,000 customers were added in October 2003 with the BMG acquisition. Over the past ten years, customer growth has averaged five percent per year. This growth has required large amounts of capital to finance the investment in new transmission and distribution plant. In 2003, our natural gas construction expenditures totaled $228 million. Approximately 72 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.

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 funded this shortfall through the issuance of additional debt and equity securities, and expect to continue to do so. However, 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 more difficult because of significant customer growth. 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 a 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, it will be more difficult for us to earn our currently authorized rate of return.

A significant reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

We cannot be certain that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so

warrant. Any downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. A downgrade could require additional support in the form of letters of credit or cash or other collateral and otherwise adversely affect our business, financial condition and results of operations.

Item 2. 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, 2003 was $3.1 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 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.

Information on properties of NPL can be found on page 6 of this Form 10-K under Construction Services.

LOGO

Item 3. LEGAL PROCEEDINGS

The Company is named as a 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 individually or in the aggregate will have a material adverse impact on the Company’s financial position or results of operations.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The principal markets on which the common stock of the Company is traded are the New York Stock Exchange and the Pacific Exchange. At March 1, 2004, there were 23,259 holders of record of common stock, and the market price of the common stock was $23.45. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2003 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

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 2003. The dividend of 20.5 cents per share has been paid quarterly since September 1994.

Item 6. SELECTED FINANCIAL DATA

Information required by this item is included in the 2003 Annual Report to Shareholders and is incorporated herein by reference.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information required by this item is included in the 2003 Annual Report to Shareholders and is incorporated herein by reference.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information required by this item is included in the 2003 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 and is incorporated herein by reference. Other risk information is included under the heading “Company Risk Factors” in Item 1. Business of this report.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements of Southwest Gas Corporation and Notes thereto, together with the reports of PricewaterhouseCoopers LLP, Independent Auditors, and Arthur Andersen LLP, Independent Public Accountants, are included in the 2003 Annual Report to Shareholders and are incorporated herein by reference.

Item 9. 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 the year ended 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.

During the years ended December 31, 2000 and 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 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 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. 333-98995 and 333-106419) and Form S-8 Registration Statements (Nos. 333-31223, 333-106762 and 333-111034) of the report of Arthur Andersen on the 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.

Item 9A. 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. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and benefits of controls must be considered relative to their costs. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Based on the most recent evaluation, as of December 31, 2003, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.

There have been no changes in the Company’s internal controls over financial reporting during the fourth quarter that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.

PART III

Item 10. 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 2004 Proxy Statement, 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 Position Held
Michael O. Maffie	56	Chief Executive Officer	2003-Present
		President and Chief Executive Officer	1999-2003
Jeffrey W. Shaw	45	President	2003-Present
		Senior Vice President/Gas Resources and Pricing	2002-2003
		Senior Vice President/Finance and Treasurer	2000-2002
		Vice President/Treasurer	1999-2000
George C. Biehl	56	Executive Vice President/Chief Financial Officer and
		Corporate Secretary	2000-Present
		Senior Vice President/Chief Financial Officer and
		Corporate Secretary	1999-2000
James P. Kane	57	Executive Vice President/Operations	2000-Present
		Senior Vice President/Operations	1999-2000
Edward S. Zub	55	Executive Vice President/Consumer Resources and
		Energy Services	2000-Present
		Senior Vice President/Regulation and Product Pricing	1999-2000
James F. Lowman	57	Senior Vice President/Central Arizona Division	1999-Present
Thomas R. Sheets	53	Senior Vice President/Legal Affairs and General Counsel	2000-Present
		Vice President/General Counsel	1999-2000
Dudley J. Sondeno	51	Senior Vice President/Chief Knowledge and
		Technology Officer	1999-Present
Roy R. Centrella	46	Vice President/Controller and Chief Accounting Officer	2002-Present
		Controller	2001-2002
		Assistant Controller	1999-2001
Kenneth J. Kenny	41	Treasurer	2003-Present
		Assistant Treasurer/Director Financial Services	2000-2003
		Senior Manager/Treasury	1999-2000

(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 2004 Proxy Statement, 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.

(h) Audit Committee Financial Expert. Information with respect to the financial expert of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive 2004 Proxy Statement, which by this reference is incorporated herein.

(i) Identification of the Audit Committee. Information with respect to the composition of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive 2004 Proxy Statement, which by this reference is incorporated herein.

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, 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 Exchange Act of 1934, as amended, which includes assisting in the preparation of forms for filing. For 2003, all reports were timely filed.

Code of Business Conduct and Ethics. The Company has adopted a code of business conduct and ethics for its employees, including its chief executive officer, chief financial officer, chief accounting officer, and non-employee directors. A code of ethics is defined as written standards that are reasonably designed to deter wrongdoing and to promote: 1) honest and ethical conduct; 2) full, fair, accurate, timely, and understandable disclosure in reports and documents that a registrant files; 3) compliance with applicable governmental laws, rules, and regulations; 4) the prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and 5) accountability for adherence to the code. The Company’s Code of Business Conduct & Ethics can be viewed on the Company’s website (www.swgas.com). If any substantive amendments to the Code of Business Conduct & Ethics are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct & Ethics, to the Company’s chief executive officer, chief financial officer and chief accounting officer, the Company will disclose the nature of such amendment or waiver on the Company’s website, www.swgas.com.


Item 11.		EXECUTIVE COMPENSATION

Information with respect to executive compensation is set forth under the heading “Executive Compensation and Benefits” in the definitive 2004 Proxy Statement, which by this reference is incorporated herein.

Item 12.

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 Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive 2004 Proxy Statement, 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 Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive 2004 Proxy Statement, which by this reference is incorporated herein.

(d) Securities Authorized for Issuance Under Equity Compensation Plans.

At December 31, 2003, the Company had two stock-based compensation 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 to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance
(Thousands of shares)
Equity compensation plans approved by security holders	1,502	$	21.83	1,016
Equity compensation plans not approved by security holders	—		—	—

Total	1,502	$	21.83	1,016

Pursuant to the terms of the management incentive 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 to be issued upon vesting of performance shares	Weighted-average grant date fair value of award		Number of securities remaining available for future issuance
(Thousands of shares)
Equity compensation plans approved by security holders	381	$	21.41	—
Equity compensation plans not approved by security holders	—		—	—

Total	381	$	21.41	—

Additional information regarding the two equity compensation plans is included in Note 9 of the Notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information with respect to accounting fees and services associated with PricewaterhouseCoopers LLP is set forth under the heading “Selection of Independent Accountants” in the definitive 2004 Proxy Statement, which by this reference is incorporated herein.

PART IV

Item 15. 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 Auditors) required to be reported herein are incorporated by reference to the information reported in the 2003 Annual Report to Shareholders under the following captions:


Consolidated Balance Sheets		37
Consolidated Statements of Income		39
Consolidated Statements of Cash Flows		40
Consolidated Statements of Stockholders’ Equity		41
Notes to Consolidated Financial Statements		42
Report of Independent Auditors		62
Report of Independent Public Accountants		63

(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.

On February 17, 2004, the Company furnished summary financial information for the quarter and year ended December 31, 2003 pursuant to Item 12 of Form 8-K.

LIST OF EXHIBITS


Exhibit Number		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 September 30, 2003.

4.01		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.

4.02		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.

4.03		Form of Deposit Agreement. Incorporated herein by reference to the Registration Statement on Form S-3, No. 33-55621.

4.04		Form of Depositary Receipt (attached as Exhibit A to Deposit Agreement included as Exhibit 4.03 hereto). Incorporated herein by reference to the Registration Statement on Form S-3, No. 33-55621.

4.05		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.

4.06		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.

4.07		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.

4.08		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.

4.09		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.

4.10		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.

4.11		Certificate of Trust of Southwest Gas Capital II. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.12		Certificate of Trust of Southwest Gas Capital III. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.13		Certificate of Trust of Southwest Gas Capital IV. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.14		Trust Agreement of Southwest Gas Capital III. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.15		Trust Agreement of Southwest Gas Capital IV. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.16		Form of Common Stock certificate. Incorporated herein by reference to the report on Form 8-K dated July 22, 2003.

4.17		Form of Preferred Trust Security. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.18		Form of Indenture with respect to the 7.70% Junior Subordinated Debentures. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.19		Form of 7.70% Junior Subordinated Debenture. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.20		Form of Amended and Restated Trust Agreement of Southwest Gas Capital II. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.21		Form of Guarantee Agreement with respect to the Preferred Trust Securities. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.22		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 as of December 1, 1993. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1993.

10.03		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.



10.04		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.

10.05	*	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.

10.06	*	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.

10.07		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.

10.08	*	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.

10.09	*	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.

10.10	*	Southwest Gas Corporation Management Incentive Plan, amended and restated January 1, 2002. Incorporated herein by reference to the Proxy Statement dated April 2, 2002.

10.11	*	Southwest Gas Corporation 2002 Stock Incentive Plan. Incorporated herein by reference to the Proxy Statement dated April 2, 2002.

10.12		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.

10.13	*	Southwest Gas Corporation Executive Deferral Plan, amended and restated as of November 19, 2002. Incorporated herein by reference to the Report on Form 10-K for the year ended December 31, 2002.

10.14	*	Southwest Gas Corporation Directors Deferral Plan, amended and restated as of November 19, 2002. Incorporated herein by reference to the Report on Form 10-K for the year ended December 31, 2002.

10.15		Lease Supplement (attached as a supplement to Exhibit 10.01) as of December 12, 2002. Incorporated herein by reference to the Report on Form 10-K for the year ended December 31, 2002.

10.16		Financing agreement dated as of March 1, 2003 by and between Clark County, Nevada and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2003A, Series 2003B, Series 2003C, Series 2003D and Series 2003E. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 2003.

12.01		Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.

13.01		Portions of 2003 Annual Report incorporated by reference to the Form 10-K.



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.

31.01		Section 302 Certifications.

32.01		Section 906 Certifications.

*	Compensation Plans

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	SOUTHWEST GAS CORPORATION

Date: March 11, 2004	By	/s/ MICHAEL O. MAFFIE

		Michael O. Maffie Chief Executive Officer

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.


Signature	Title	Date

/s/ GEORGE C. BIEHL (George C. Biehl)	Director, Executive Vice President, Chief Financial Officer, and Corporate Secretary	March 11, 2004

/s/ MANUEL J. CORTEZ (Manuel J. Cortez)	Director	March 11, 2004

/s/ MARK M. FELDMAN (Mark M. Feldman)	Director	March 11, 2004

/s/ DAVID H. GUNNING (David H. Gunning)	Director	March 11, 2004

/s/ THOMAS Y. HARTLEY (Thomas Y. Hartley)	Chairman of the Board of Directors	March 11, 2004

/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	March 11, 2004

/s/ MICHAEL B. JAGER (Michael B. Jager)	Director	March 11, 2004

/s/ LEONARD R. JUDD (Leonard R. Judd)	Director	March 11, 2004

/s/ JAMES J. KROPID (James J. Kropid)	Director	March 11, 2004

/s/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director and Chief Executive Officer	March 11, 2004

/s/ CAROLYN M. SPARKS (Carolyn M. Sparks)	Director	March 11, 2004

/s/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	March 11, 2004

/s/ ROY R. CENTRELLA Roy R. Centrella	Vice President, Controller, and Chief Accounting Officer	March 11, 2004

EXHIBIT INDEX


Exhibit Number		Description of Document

12.01		Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.

13.01		Portions of 2003 Annual Report to Shareholders incorporated by reference to Form 10-K.

21.01		List of Subsidiaries of Southwest Gas Corporation.

23.01		Consent of PricewaterhouseCoopers LLP, Independent Accountants.

31.01		Section 302 Certifications.

32.01		Section 906 Certifications.

Computation of Ratios of Earnings to Fixed Charges

EXHIBIT 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)


	For the Year Ended December 31,
	2003		2002		2001		2000		1999
Continuing operations
1. Fixed charges:
A) Interest expense	$	78,724	$	79,586	$	80,139	$	70,659	$	63,110
B) Amortization		2,752		2,278		1,886		1,564		1,366
C) Interest portion of rentals		6,665		8,846		9,346		8,572		8,217
D) Preferred securities distributions		4,015		5,475		5,475		5,475		5,475

Total fixed charges	$	92,156	$	96,185	$	96,846	$	86,270	$	78,168

2. Earnings (as defined):
E) Pretax income from continuing operations	$	55,384	$	65,382	$	56,741	$	51,939	$	60,955
Fixed Charges (1. above)		92,156		96,185		96,846		86,270		78,168

Total earnings as defined	$	147,540	$	161,567	$	153,587	$	138,209	$	139,123

3. Ratio of earnings to fixed charges		1.60		1.68		1.59		1.60		1.78

Portions of 2003 Annual Report to Shareholders

EXHIBIT 13.01

southwest gas 2003 annual report

PAGE 21

consolidated selected financial statistics


(thousands of dollars, except per share amounts)
YEAR ENDED DECEMBER 31,	2003			2002			2001			2000			1999

Operating revenues	$	1,231,004		$	1,320,909		$	1,396,688		$	1,034,087		$	936,866
Operating expenses		1,095,899			1,174,410			1,262,705			905,457			805,654

Operating income	$	135,105		$	146,499		$	133,983		$	128,630		$	131,212

Net income	$	38,502		$	43,965		$	37,156		$	38,311		$	39,310

Total assets at year end	$	2,608,106		$	2,432,928		$	2,369,612		$	2,232,337		$	1,923,442


CAPITALIZATION AT YEAR END
Common equity	$	630,467		$	596,167		$	561,200		$	533,467		$	505,425
Mandatorily redeemable preferred trust securities		—			60,000			60,000			60,000			60,000
Subordinated debentures		100,000			—			—			—			—
Long-term debt		1,121,164			1,092,148			796,351			896,417			859,291

	$	1,851,631		$	1,748,315		$	1,417,551		$	1,489,884		$	1,424,716


COMMON STOCK DATA
Return on average common equity		6.3	%		7.5	%		6.8	%		7.4	%		8.0	%
Earnings per share	$	1.14		$	1.33		$	1.16		$	1.22		$	1.28
Diluted earnings per share	$	1.13		$	1.32		$	1.15		$	1.21		$	1.27
Dividends paid per share	$	0.82		$	0.82		$	0.82		$	0.82		$	0.82
Payout ratio		72	%		62	%		71	%		67	%		64	%
Book value per share at year end	$	18.42		$	17.91		$	17.27		$	16.82		$	16.31
Market value per share at year end	$	22.45		$	23.45		$	22.35		$	21.88		$	23.00
Market value per share to book value per share		122	%		131	%		129	%		130	%		141	%
Common shares outstanding at year end (000)		34,232			33,289			32,493			31,710			30,985
Number of common shareholders at year end		22,616			22,119			23,243			24,092			22,989
Ratio of earnings to fixed charges		1.60			1.68			1.59			1.60			1.78

southwest gas 2003 annual report

PAGE 22

natural gas operations


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003			2002			2001			2000			1999

Sales	$	984,966		$	1,069,917		$	1,149,918		$	816,358		$	740,900
Transportation		49,387			45,983			43,184			54,353			50,255

Operating revenue		1,034,353			1,115,900			1,193,102			870,711			791,155
Net cost of gas sold		482,503			563,379			677,547			394,711			330,031

Operating margin		551,850			552,521			515,555			476,000			461,124

EXPENSES
Operations and maintenance		266,862			264,188			253,026			231,175			221,258
Depreciation and amortization		120,791			115,175			104,498			94,689			88,254
Taxes other than income taxes		35,910			34,565			32,780			29,819			27,610

Operating income	$	128,287		$	138,593		$	125,251		$	120,317		$	124,002

Contribution to consolidated net income	$	34,211		$	39,228		$	32,626		$	33,908		$	35,473

Total assets at year end	$	2,528,332		$	2,345,407		$	2,289,111		$	2,154,641		$	1,855,114

Net gas plant at year end	$	2,175,736		$	2,034,459		$	1,825,571		$	1,686,082		$	1,581,102

Construction expenditures and property additions	$	228,288		$	263,576		$	248,352		$	205,161		$	207,773


CASH FLOW, NET
From operating activities	$	187,122		$	281,329		$	103,848		$	109,872		$	165,220
From investing activities		(249,300	)		(243,373	)		(246,462	)		(203,325	)		(207,024	)
From financing activities		60,815			(49,187	)		154,727			95,481			40,674

Net change in cash	$	(1,363	)	$	(11,231	)	$	12,113		$	2,028		$	(1,130	)


(thousands of therms)
TOTAL THROUGHPUT
Residential		593,048			588,215			589,943			571,378			554,507
Small commercial		279,154			280,271			279,965			272,673			266,030
Large commercial		100,422			121,500			107,583			63,908			62,566
Industrial/Other		157,305			224,055			283,772			199,715			154,306
Transportation		1,336,901			1,325,149			1,268,203			1,482,700			1,186,859

Total throughput		2,466,830			2,539,190			2,529,466			2,590,374			2,224,268

Weighted average cost of gas purchased ($/therm)	$	0.46		$	0.38		$	0.55		$	0.42		$	0.28
Customers at year end		1,531,000			1,455,000			1,397,000			1,337,000			1,274,000
Employees at year end		2,550			2,546			2,507			2,491			2,482
Degree days – actual		1,772			1,912			1,963			1,938			1,928
Degree days – ten-year average		1,931			1,963			1,970			1,991			2,031

southwest gas 2003 annual report

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management’s discussion and analysis of

financial condition and results of operations

EXECUTIVE SUMMARY

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.

consolidated results of operations


(thousands of dollars, except per share amounts)
YEAR ENDED DECEMBER 31,	2003		2002		2001


CONTRIBUTION TO NET INCOME
Natural gas operations	$	34,211	$	39,228	$	32,626
Construction services		4,291		4,737		4,530

Net income	$	38,502	$	43,965	$	37,156


EARNINGS PER SHARE
Natural gas operations	$	1.01	$	1.19	$	1.02
Construction services		0.13		0.14		0.14

Consolidated	$	1.14	$	1.33	$	1.16

See separate discussions at Results of Natural Gas Operations and Results of Construction Services. Average shares outstanding increased by 807,000 between 2003 and 2002, and 831,000 between 2002 and 2001, primarily resulting from continuing issuances under the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”).

As reflected in the table above, the natural gas operations segment accounted for an average of 89 percent of consolidated net income over the past three years. As such, management’s main focus is on that segment.

Southwest’s operating revenues are recognized from the distribution and transportation of natural gas (and related services) billed to customers. An estimate of the amount of natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized in revenues.

Margin is the measure of utility revenues less the net cost of gas sold. Management uses margin as a main benchmark in comparing operating results from period to period. The three principal factors affecting utility margin are general rate relief, weather, and customer growth.

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management’s discussion and analysis of

financial condition and results of operations

Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. (See the section on Rates and Regulatory Proceedings for additional information). Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest.

Weather is a significant driver of natural gas volumes used by residential and small commercial customers and is the main reason for volatility in margin. Space heating-related volumes are the primary component of billings for these customer classes and are concentrated in the months of November to April for the majority of the Company’s customers. Variances in temperatures from normal levels, especially during these months, have a significant impact on the margin and associated net income of the Company.

Customer growth, excluding acquisitions, has averaged five percent annually over the past 10 years and over four percent annually during the past three years. Incremental margin has accompanied this customer growth, but the costs associated with creating and maintaining the infrastructure needed to accommodate these customers also have been significant. The timing of including these costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings.

Management has attempted to mitigate the regulatory lag by being judicious in its staffing levels through the effective use of technology. During the past decade while adding nearly 600,000 customers, Southwest only increased staffing levels by 232. During this same period, Southwest’s customer to employee ratio has climbed from 402/1 to 600/1, one of the best in the industry. It has accomplished this without sacrificing service quality. Examples of technological improvements over the last few years include electronic order routing, an electronic mapping system and, most recently, a work management system.

The results of the natural gas operations segment and the overall results of the Company are heavily dependent upon the three components noted previously (general rate relief, weather, and customer growth). Significant changes in these components (primarily weather) have contributed to somewhat volatile earnings. Management continues to work with its regulatory commissions in designing rate structures that provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors.

As of December 31, 2003, Southwest had 1,531,000 residential, commercial, industrial, and other natural gas customers, of which 851,000 customers were located in Arizona, 542,000 in Nevada, and 138,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2003, Southwest added 67,000 customers (excluding 9,000 associated with the acquisition of Black Mountain Gas Company (“BMG”) in October 2003), a five percent increase, of which 30,000 customers were added in Arizona, 31,000 in Nevada, and 6,000 in California. These additions are largely attributed to population growth in the service areas. Based on current commitments from builders, customer growth is expected to be between four and five percent in 2004. During 2003, 56 percent of operating margin was earned in Arizona, 36 percent in Nevada, and 8 percent in California. During this same period, Southwest earned 84 percent of operating margin from residential and small commercial customers, 6 percent from other sales customers, and 10 percent from transportation customers. These patterns are expected to continue.

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management’s discussion and analysis of

financial condition and results of operations

RESULTS OF NATURAL GAS OPERATIONS


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003		2002		2001

Gas operating revenues	$	1,034,353	$	1,115,900	$	1,193,102
Net cost of gas sold		482,503		563,379		677,547

Operating margin		551,850		552,521		515,555
Operations and maintenance expense		266,862		264,188		253,026
Depreciation and amortization		120,791		115,175		104,498
Taxes other than income taxes		35,910		34,565		32,780

Operating income		128,287		138,593		125,251
Other income (expense)		2,955		3,108		7,694
Net interest deductions		76,251		78,505		78,746
Net interest deductions on subordinated debentures		2,680		—		—
Preferred securities distributions		4,180		5,475		5,475

Income before income taxes		48,131		57,721		48,724
Income tax expense		13,920		18,493		16,098

Contribution to consolidated net income	$	34,211	$	39,228	$	32,626

2003 vs. 2002

Contribution from natural gas operations declined $5 million in 2003 compared to 2002. The decrease was principally the result of lower operating margin and increased operating expenses, partially offset by decreased financing costs.

Operating margin decreased $671,000 in 2003 as compared to 2002. Approximately 67,000 customers were added during the last 12 months, a growth rate of five percent. Another 9,000 customers were added in October 2003 with the acquisition of Black Mountain Gas Company. New customers contributed $16 million in incremental margin. Differences in heating demand caused by weather variations between years resulted in a $13 million margin decrease as warmer-than-normal temperatures were experienced during both years. During 2003, operating margin was negatively impacted $32 million by the weather, while in 2002 the negative impact was $19 million. Conservation, energy efficiency and other factors accounted for the remainder of the decline.

Operations and maintenance expense increased $2.7 million, or one percent, compared to 2002. The impacts of general cost increases and costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth were offset by cost-curbing management initiatives begun in the fourth quarter of 2002. Going forward, operations and maintenance expenses overall are expected to trend upward corresponding to the customer growth rate and inflation. The costs of additional regulation, social programs, medical costs and pensions are some of the primary factors responsible for this trend.

Depreciation expense and general taxes increased $7 million, or five percent, as a result of construction activities. Average gas plant in service increased $231 million, or nine percent, as compared to 2002. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.

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management’s discussion and analysis of

financial condition and results of operations

Other income (expense) decreased $153,000 between years. The prior year included income of $2.2 million related to several non-recurring items. Interest income (primarily on purchased gas adjustment (“PGA”) balances) declined $1.6 million between years. Improvements in returns on long-term investments substantially offset the negative factors.

Net financing costs declined $869,000 between years primarily due to lower interest rates on variable-rate debt and interest savings generated from the refinancing of industrial development revenue bonds and preferred securities instruments in 2003. Interest costs are expected to trend upward in 2004 as the Company finances the infrastructure associated with customer growth.

During 2003, Southwest recognized $2 million of income tax benefits associated with plant-related items. In 2002, Southwest recognized $2.7 million of income tax benefits associated with state taxes, plant, and non-plant related items.

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 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 2002, 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 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 2002 balance included: an $8.9 million gain on the sale of undeveloped property, $4 million of net merger-related litigation costs, 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.

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management’s discussion and analysis of

financial condition and results of operations

RATES AND REGULATORY PROCEEDINGS

Arizona General Rate Case. In May 2000, Southwest last filed a general rate application with the Arizona Corporation Commission (“ACC”) for its Arizona rate jurisdiction. The ACC authorized a general rate increase of $21.6 million effective November 2001. Management has not determined the timing of filing its next general rate case in Arizona.

Nevada General Rate Cases. In March 2004, Southwest filed general rate applications with the Public Utilities Commission of Nevada (“PUCN”), which included annual increases of $8.6 million for northern Nevada and $18.9 million in southern Nevada. A PUCN decision is expected in the third quarter of 2004.

In July 2001, Southwest filed general rate applications with the PUCN for its southern Nevada and northern Nevada rate jurisdictions. The PUCN authorized general rate increases of $13.5 million in southern Nevada and $5.9 million in northern Nevada effective December 2001.

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. The last general rate increases received in California were January 1998 in northern California and January 1995 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 concurred 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 $2.6 million in northern California and $5.7 million in southern California. The final general rate case decision, originally anticipated to have an effective date of January 2003, was delayed due to the reassignment of the Administrative Law Judge (“ALJ”) assigned to the case. As a result of this delay, Southwest filed a motion during the first quarter of 2003 requesting authorization to establish a memorandum account to track the related revenue shortfall between the existing and proposed rates in the general rate case filing. This motion was approved, effective May 2003. In October 2003, the ALJ rendered a draft decision (“proposed decision” or “PD”) on the general rate case. The PD was modified in February 2004. If approved as modified, the PD would increase rates by about 60 percent of the 2003 amount filed for and provide for attrition increases beginning in 2004. Southwest filed comments largely in support of the PD. In January 2004, an alternate decision (“AD”) from one of the commissioners was received, reducing the rate increase in southern California as proposed in the PD by $2 million, with no significant change to northern California. In addition, the AD proposed a disallowance of $12.2 million in gas costs. Southwest filed comments vehemently opposed to the AD. The general rate case is on the agenda for mid-March; however, management can not determine which, if any, of the proposed or alternate decisions will be approved.

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. The timing of Paiute’s next general rate case filing has not been determined.

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management’s discussion and analysis of

financial condition and results of operations

PGA FILINGS

The rate schedules in all of the service territories contain PGA clauses, which permit adjustments to rates as the cost of purchased gas changes. 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. PGA changes impact cash flows but have no direct impact on profit margin. Southwest had the following outstanding PGA balances receivable/(payable) at the end of its two most recent fiscal years (millions of dollars):


	2003			2002

Arizona		$ (5.8	)		$ (24.0	)
Northern Nevada		1.7			8.3
Southern Nevada		5.1			(21.9	)
California		8.2			10.9

	$	9.2		$	(26.7	)

Nevada PGA Filings. In June 2003, Southwest made its annual PGA filing with the PUCN. Southwest requested a change to a monthly PGA mechanism, rather than annual, to reduce volatility in rate changes. Effective in December 2003, the PUCN approved an increase of $25.5 million, or 12.3 percent, for customers in southern Nevada and a decrease of $8.6 million, or 10.2 percent, in northern Nevada. The monthly adjustment mechanism proposed in the annual filing was not adopted. As a result of increases in gas costs experienced since the annual filing in June 2003 (in addition to projected continued increases), an out-of-cycle filing was made in December 2003. This filing requested increases of $59.8 million, or 25.5 percent, in southern Nevada and $16.7 million, or 22.1 percent, in northern Nevada. In January 2004, the PUCN approved the elimination of a credit surcharge, resulting in an interim increase of 5.5 percent in southern Nevada and 4.8 percent in northern Nevada beginning in February 2004. A final decision on the PGA filing is expected in the second quarter of 2004.

OTHER FILINGS

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management’s discussion and analysis of

financial condition and results of operations

Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. Southwest has had adequate capacity for its customers needs during the 2003/2004 heating season to date and management believes adequate capacity exists for the remainder of the heating season. Additional costs may be incurred to acquire capacity in the future as a result of the FERC order. However, it is anticipated that any additional costs will be collected from customers through the PGA mechanism.

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, 2003, total gas plant increased from $2.4 billion to $3 billion, or at an annual rate of nine percent. Customer growth was the primary reason for the plant increase as Southwest added 194,000 net new customers (including BMG) during the three-year period.

During 2003, capital expenditures for the natural gas operations segment were $228 million. Approximately 72 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. Cash flows from operating activities of Southwest (net of dividends) provided $159 million of the required capital resources pertaining to total construction expenditures in 2003. The remainder was provided from external financing activities.

asset purchases

In October 2003, the Company completed the purchase of BMG, a gas utility serving portions of Carefree, North Scottsdale, North Phoenix, Cave Creek, and Page, Arizona. The Company paid approximately $24 million for BMG. BMG has approximately 9,000 natural gas customers in a rapidly growing area north of Phoenix and about 2,500 propane customers. The Company plans to sell the propane operations.

2003 financing activity

In March 2003, the Company issued several series of Clark County, Nevada Industrial Development Revenue Bonds (“IDRBs”) totaling $165 million, due 2038. Of this total, variable-rate IDRBs ($50 million 2003 Series A and $50 million 2003 Series B) were used to refinance the $100 million 7.50% 1992 Series B, fixed-rate IDRBs due 2032. At December 31, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.66%. The $30 million 7.30% 1992 Series A, fixed-rate IDRBs due 2027 was refinanced with $30 million 5.45% 2003 Series C fixed-rate IDRBs. An incremental $35 million ($20 million 3.35% 2003 Series D and $15 million 5.80% Series E fixed-rate IDRBs) was used to finance construction expenditures in southern Nevada during the first and second quarters of 2003. The Series C and Series E were set with an initial interest rate period of 10 years, while the Series D has an initial interest rate period of 18 months. After the initial interest rate periods, the Series C, D, and E interest rates will be reset at then prevailing market rates for periods not to exceed the maturity date of March 1, 2038.

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management’s discussion and analysis of

financial condition and results of operations

The 2003 Series A and Series B IDRBs described above are supported by two letters of credit totaling $101.7 million, which expire in March 2006. These IDRBs are set at weekly rates and the letters of credit support the payment of principal or a portion of the purchase price corresponding to the principal of the IDRBs while in the weekly rate mode.

In June 2003, the Company filed a registration statement on Form S-3 for an incremental $100 million of various securities with the Securities and Exchange Commission (“SEC”) and to revise $200 million of securities previously registered to provide additional flexibility in the types of securities available for issuance. After the issuance of the preferred securities described in the following paragraph, the Company has a total of $200 million in securities registered with the SEC which are available for future financing needs.

In August 2003, Southwest Gas Capital II, a wholly owned subsidiary and financing trust, issued $100 million of 7.70% Preferred Trust Securities. A portion of the net proceeds from the issuance of the Preferred Trust Securities was used to complete the redemption of the 9.125% Trust Originated Preferred Securities effective September 2003 at a redemption price of $25 per Preferred Security, totaling $60 million plus accrued interest of $1.3 million. For more information, including the accounting treatment, see Note 5 – Preferred Securities.

In October 2003, a $55.3 million letter of credit, which supports the City of Big Bear $50 million tax-exempt Series A IDRBs, due 2028, was renewed for a three-year period expiring in October 2006.

In July 2003, the Company registered 1.5 million shares of common stock with the SEC for issuance under the Southwest Gas Corporation 2002 Stock Incentive Plan. In December 2003, the Company registered 600,000 shares of common stock with the SEC for issuance under the Southwest Gas Corporation Employees’ Investment Plan.

2004 construction expenditures and financing

In March 2002, the Job Creation and Worker Assistance Act of 2002 (“2002 Act”) was signed into law. The 2002 Act provided a three-year, 30 percent bonus depreciation deduction for businesses. The Jobs and Growth Tax Relief Reconciliation Act of 2003 (“2003 Act”), signed into law in May 2003, provides for enhanced and extended bonus tax depreciation. The 2003 Act increased the bonus depreciation rate to 50 percent for qualifying property placed in service after May 2003 and, generally, before January 2005. Southwest estimates the 2002 and 2003 Acts bonus depreciation deductions will defer the payment of $35 million of federal income taxes during 2004.

Southwest estimates construction expenditures during the three-year period ending December 31, 2006 will be approximately $690 million. Of this amount, $233 million are expected to be incurred in 2004. During the three-year period, cash flow from operating activities including the impacts of the Acts (net of dividends) is estimated to fund approximately 80 percent of the gas operations’ total construction expenditures. The Company expects to raise $50 million to $55 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.

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management’s discussion and analysis of

financial condition and results of operations

off balance sheet arrangements

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.

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. The Company does not currently utilize other 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 that are marked to market, or contain embedded derivatives with significant mark-to-market value.

contractual obligations

Obligations under long-term debt, gas purchase obligations and non-cancelable operating leases at December 31, 2003 were as follows:

CONTRACTUAL OBLIGATIONS


(millions of dollars)	PAYMENTS DUE BY PERIOD

	TOTAL		2004		2005-2006		2007-2008		THEREAFTER

Short-term debt (Note 7)	$	52	$	52	$	—	$	—	$	—
Subordinated debentures to Southwest Gas Capital II (Note 5)		103		—		—		—		103
Long-term debt (Note 6)		1,121		6		204		43		868
Operating leases (Note 2)		47		8		10		8		21
Gas purchase obligations (a)		218		170		48		—		—
Pipeline capacity (b)		551		69		137		132		213
Other commitments		8		4		4		—		—

Total	$	2,100	$	309	$	403	$	183	$	1,205

(a) Includes fixed price and variable rate gas purchase contracts covering approximately 99 million dekatherms. Fixed price contracts range in price from $3.70 to $5.84 per dekatherm. Variable price contracts reflect minimum contractual obligations.

(b) Southwest has pipeline capacity contracts for firm transportation service, both on a short- and long-term basis, with several companies (primarily El Paso Natural Gas Company and Kern River Gas Transmission Company) for all of its service territories. Southwest also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise. Costs associated with these pipeline capacity contracts are a component of the cost of gas sold and are recovered from customers primarily through the PGA mechanism.

Estimated pension funding for 2004 is $14 million.

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management’s discussion and analysis of

financial condition and results of operations

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, variability of natural gas prices, and the level of Company earnings.

Since the winter of 2000-2001, the price of natural gas has varied widely. Southwest customers have benefited from the fixed prices associated with term contracts in place during 2003. These contracts are generally of short duration (less than one year) and cover about half of Southwest’s supply needs. Southwest enters into new contracts annually to replace those that are expiring to help mitigate price volatility. Remaining needs will be covered with the purchase of natural gas on the spot market and are subject to market fluctuations. Over the next few years, continued strong growth in natural gas demand and limited supply increases indicate prices for natural gas will remain volatile. Southwest continues to pursue all available sources to maintain the balance between a low cost and reliable supply of natural gas for its customers. All incremental costs are expected to be included in the PGA mechanism for recovery from customers in each rate jurisdiction.

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, 2003, the combined balances in PGA accounts totaled an under-collection of $9.2 million versus an over-collection of $27 million at December 31, 2002. See PGA Filings for more information on recent regulatory 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 $98 million available at December 31, 2003), which the Company believes is adequate to meet anticipated needs.

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 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).

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).

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management’s discussion and analysis of

financial condition and results of operations

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 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.

RESULTS OF CONSTRUCTION SERVICES


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003		2002		2001

Construction revenues	$	196,651	$	205,009	$	203,586
Cost of construction		184,290		191,561		189,429

Gross profit		12,361		13,448		14,157
General and administrative expenses		5,543		5,542		5,026

Operating income		6,818		7,906		9,131
Other income (expense)		1,290		1,221		871
Interest expense		855		1,466		1,985

Income before income taxes		7,253		7,661		8,017
Income tax expense		2,962		2,924		3,487

Contribution to consolidated net income	$	4,291	$	4,737	$	4,530

2003 vs. 2002

The 2003 contribution to consolidated net income from construction services decreased $446,000 from the prior year. The decrease was primarily due to a decline in construction revenues and an insurance settlement, partially offset by lower interest expense.

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management’s discussion and analysis of

financial condition and results of operations

Revenues decreased $8.4 million due to a reduced workload in some operating areas, the completion of certain projects, and the non-renewal of two long-term contracts. Cost of construction includes a one-time $1.3 million charge for an unfavorable insurance settlement. Interest expense declined $611,000 as a result of the refinancing of long-term debt to take advantage of lower interest rates.

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. Other income in 2001 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.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In January 2003, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities. FIN 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. Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, was created by the Company to issue preferred trust securities for the benefit of the Company. (See Note 5 of the Notes to Consolidated Financial Statements for additional information.) Trust II, the issuer of the preferred trust securities, meets the definition of a variable interest entity.

Although the Company owns 100 percent of the common voting securities of Trust II, under current interpretation of FIN 46, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. The adoption of FIN 46 results in the Company reflecting a liability to Trust II, which under the prior accounting treatment would have been eliminated in consolidation, instead of to the holders of the preferred trust securities. As a result, payments and amortizations associated with the liability are classified on the consolidated statements of income as Net interest deductions on subordinated debentures.

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.

n	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

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management’s discussion and analysis of

financial condition and results of operations

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 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.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003.

In accordance with approved regulatory practices, the depreciation expense for Southwest includes a component to recover removal costs associated with utility plant retirements. In accordance with the SEC’s position on presentation of these amounts, management has reclassified $68 million and $55 million, as of December 31, 2003 and 2002, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs (in the liabilities section of the balance sheet).

Under utility accounting, all plant is assumed to be fully depreciated upon retirement. However, retirements often occur earlier than the average service life of the plant group. Accumulated depreciation has a historical mix of credits (depreciation amounts designed to recover plant investment and net removal costs) and debits (charges for retirements and actual costs of removal). The actual amount of net removal costs recorded as credits has never been tracked by the Company. The estimate of the calculated cost of removal embedded in accumulated depreciation employed various assumptions including average service lives and historical depreciation rates. Variations in the assumptions utilized would result in a range of accumulated removal costs that would vary significantly from the amount estimated above.

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 statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

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management’s discussion and analysis of

financial condition and results of operations

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, changes in natural gas prices, our ability to recover costs through our PGA mechanism, 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, changes in construction expenditures and financing, changes in operations and maintenance expenses, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition and our ability to raise capital in external financings or through our DRSPP. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing, operations and maintenance expenses will continue in future periods. 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, 2003.

All forward-looking statements in this annual report are made as of the date hereof, based on information available to the Company as of the date hereof, and the Company assumes no obligation to update or revise any of its forward-looking statements even if experience or future changes show that the indicated results or events will not be realized. We caution you not to unduly rely on any forward-looking statement(s).

COMMON STOCK PRICE AND DIVIDEND INFORMATION


	2003				2002				DIVIDENDS PAID

	HIGH		LOW		HIGH		LOW		2003		2002

First quarter	$	23.64	$	19.30	$	25.35	$	21.80	$	0.205	$	0.205
Second quarter		22.45		19.74		24.99		22.60		0.205		0.205
Third quarter		23.49		20.14		24.75		18.10		0.205		0.205
Fourth quarter		23.48		22.04		23.63		19.82		0.205		0.205

									$	0.820	$	0.820

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southwest gas corporation

consolidated balance sheets


(thousands of dollars, except par value)
DECEMBER 31,	2003			2002

ASSETS

UTILITY PLANT:
Gas plant	$	3,035,969		$	2,779,960
Less: accumulated depreciation		(896,309	)		(814,908	)
Acquisition adjustments, net		2,533			2,714
Construction work in progress		33,543			66,693

Net utility plant (Note 2)		2,175,736			2,034,459

Other property and investments		87,443			87,391


CURRENT ASSETS:
Cash and cash equivalents		17,183			19,392
Accounts receivable, net of allowances (Note 3)		126,783			130,695
Accrued utility revenue		66,700			65,073
Deferred income taxes (Note 10)		6,914			3,084
Deferred purchased gas costs (Note 4)		9,151			—
Prepaids and other current assets (Note 4)		54,356			43,524

Total current assets		281,087			261,768

Deferred charges and other assets (Note 4)		63,840			49,310

Total assets	$	2,608,106		$	2,432,928

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southwest gas corporation

consolidated balance sheets


(thousands of dollars, except par value)
DECEMBER 31,	2003		2002

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
Common stock, $1 par (authorized – 45,000,000 shares; issued and outstanding – 34,232,098 and 33,289,015 shares)	$	35,862	$	34,919
Additional paid-in capital		510,521		487,788
Retained earnings		84,084		73,460

Total equity		630,467		596,167
Mandatorily redeemable preferred trust securities (Note 5)		—		60,000
Subordinated debentures due to Southwest Gas Capital II (Note 5)		100,000		—
Long-term debt, less current maturities (Note 6)		1,121,164		1,092,148

Total capitalization		1,851,631		1,748,315

Commitments and contingencies (Note 8)

CURRENT LIABILITIES:
Current maturities of long-term debt (Note 6)		6,435		8,705
Short-term debt (Note 7)		52,000		53,000
Accounts payable		110,114		88,309
Customer deposits		44,290		34,313
Income taxes payable, net		—		10,969
Accrued general taxes		32,466		28,400
Accrued interest		19,665		21,137
Deferred purchased gas costs (Note 4)		—		26,718
Other current liabilities		45,442		41,630

Total current liabilities		310,412		313,181


DEFERRED INCOME TAXES AND OTHER CREDITS:
Deferred income taxes and investment tax credits (Note 10)		277,332		229,358
Taxes payable		6,661		—
Accumulated removal costs (Note 4)		68,000		55,000
Other deferred credits (Note 4)		94,070		87,074

Total deferred income taxes and other credits		446,063		371,432

Total capitalization and liabilities	$	2,608,106	$	2,432,928

The accompanying notes are an integral part of these statements.

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southwest gas corporation

consolidated statements of income


(in thousands, except per share amounts)
YEAR ENDED DECEMBER 31,	2003			2002			2001

OPERATING REVENUES:
Gas operating revenues	$	1,034,353		$	1,115,900		$	1,193,102
Construction revenues		196,651			205,009			203,586

Total operating revenues		1,231,004			1,320,909			1,396,688


OPERATING EXPENSES:
Net cost of gas sold		482,503			563,379			677,547
Operations and maintenance		266,862			264,188			253,026
Depreciation and amortization		136,439			130,210			118,448
Taxes other than income taxes		35,910			34,565			32,780
Construction expenses		174,185			182,068			180,904

Total operating expenses		1,095,899			1,174,410			1,262,705

Operating income		135,105			146,499			133,983


OTHER INCOME AND (EXPENSES):
Net interest deductions		(77,106	)		(79,971	)		(80,731	)
Net interest deductions on subordinated debentures (Note 5)		(2,680	)		—			—
Preferred securities distributions (Note 5)		(4,180	)		(5,475	)		(5,475	)
Other income (deductions)		4,245			4,329			8,964

Total other income and (expenses)		(79,721	)		(81,117	)		(77,242	)

Income before income taxes		55,384			65,382			56,741
Income tax expense (Note 10)		16,882			21,417			19,585

Net income	$	38,502		$	43,965		$	37,156

Basic earnings per share (Note 12)	$	1.14		$	1.33		$	1.16

Diluted earnings per share (Note 12)	$	1.13		$	1.32		$	1.15

Average number of common shares outstanding		33,760			32,953			32,122
Average shares outstanding (assuming dilution)		34,041			33,233			32,398

The accompanying notes are an integral part of these statements.

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southwest gas corporation

consolidated statements of cash flows


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003			2002			2001


CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	38,502		$	43,965		$	37,156

ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization		136,439			130,210			118,448
Deferred income taxes		44,144			(15,684	)		(11,175	)

CHANGES IN CURRENT ASSETS AND LIABILITIES:
Accounts receivable, net of allowances		4,416			24,687			(19,773	)
Accrued utility revenue		(1,627	)		(1,300	)		(5,900	)
Deferred purchased gas costs		(35,981	)		110,219			8,563
Accounts payable		21,586			(20,858	)		(85,512	)
Accrued taxes		(386	)		33,997			18,766
Other current assets and liabilities		1,692			4,763			34,051
Other		(1,009	)		(11,525	)		28,128

Net cash provided by operating activities		207,776			298,474			122,752


CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(240,671	)		(282,851	)		(265,580	)
Other (Note 14)		(18,215	)		23,985			4,318

Net cash used in investing activities		(258,886	)		(258,866	)		(261,262	)


CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		21,290			18,174			17,061
Dividends paid		(27,685	)		(27,009	)		(26,323	)
Issuance of subordinated debentures, net		96,312			—			—
Issuance of long-term debt, net		159,997			206,161			213,026
Retirement of long-term debt, net		(140,013	)		(210,028	)		(14,723	)
Retirement of preferred securities		(60,000	)		—			—
Change in short-term debt		(1,000	)		(40,000	)		(38,000	)

Net cash provided by (used in) financing activities		48,901			(52,702	)		151,041

Change in cash and cash equivalents		(2,209	)		(13,094	)		12,531
Cash at beginning of period		19,392			32,486			19,955

Cash at end of period	$	17,183		$	19,392		$	32,486


SUPPLEMENTAL INFORMATION:
Interest paid, net of amounts capitalized	$	78,561		$	76,867		$	74,032

Income taxes paid (received), net	$	(26,733	)	$	1,797		$	13,186

The accompanying notes are an integral part of these statements.

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southwest gas corporation

consolidated statements of stockholders’ equity


(in thousands, except per share amounts)
	COMMON STOCK
	SHARES		AMOUNT		ADDITIONAL PAID-IN CAPITAL		RETAINED EARNINGS			TOTAL


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
Common stock issuances	943			943		20,347					21,290
Net income								38,502			38,502
Other						2,386					2,386
Dividends declared Common: $0.82 per share								(27,878	)		(27,878	)


DECEMBER 31, 2003	34,232	*	$	35,862	$	510,521	$	84,084		$	630,467

* At December 31, 2003, 882,000 common shares were registered and available for issuance under provisions of the Employee Investment Plan and the Dividend Reinvestment and Stock Purchase Plan. In addition, 2.5 million common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 9).

The accompanying notes are an integral part of these statements.

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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. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that 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, except for Southwest Gas Capital II (see Note 5). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL 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 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.

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notes to consolidated financial statements

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 NPL 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.

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003.

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 compensate for salvage value, removal costs and retirements, 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 the year 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 $2.6 million in 2003, $3.1 million in 2002, and $2.5 million in 2001 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.

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notes to consolidated financial statements

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.


(in thousands)
	2003	2002	2001

Average basic shares	33,760	32,953	32,122

EFFECT OF DILUTIVE SECURITIES:
Stock options	73	94	122
Performance shares	208	186	154

Average diluted shares	34,041	33,233	32,398

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”).

Reclassifications. Certain reclassifications have been made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation.

Recently Issued Accounting Pronouncements. In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. See Note 5 – Preferred Securities for additional information.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which was effective for contracts entered into or modified after September 30, 2003 with exceptions for certain types of securities. SFAS No. 149 clarifies the definition and characteristics of a derivative and amends other existing pronouncements for consistency. Southwest has fixed-price gas purchase contracts, which are considered normal purchases occurring in the ordinary course of business. The Company does not currently utilize stand-alone derivative instruments for speculative purposes and does not have foreign currency exposure. None of the Company’s long term financial instruments or other contracts are derivatives that are marked to market, or contain embedded derivatives with significant mark-to-market value. The adoption of the standard did not have a material impact on the financial position or results of operations of the Company.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” which is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 addresses the accounting for certain financial instruments with characteristics of both liabilities and equity that, under previous guidance, issuers could account for as equity. SFAS No. 150 requires those instruments be classified as liabilities in statements of financial position. The adoption of the standard did not have a material impact on the financial position or results of operations of the Company.

southwest gas 2003 annual report

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notes to consolidated financial statements

Stock-Based Compensation. At December 31, 2003, 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. 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 “Accounting for Stock-Based Compensation” to its stock-based employee compensation:


(thousands of dollars, except per share amounts)
	2003			2002			2001

Net income, as reported	$	38,502		$	43,965		$	37,156
Add: Stock-based employee compensation expense included in reported net income, net of related tax benefits		2,438			1,783			1,879
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax benefits		(2,920	)		(2,024	)		(2,222	)

Pro forma net income	$	38,020		$	43,724		$	36,813


EARNINGS PER SHARE:
Basic – as reported	$	1.14		$	1.33		$	1.16
Basic – pro forma		1.13			1.33			1.15

Diluted – as reported		1.13			1.32			1.15
Diluted – pro forma		1.12			1.32			1.14

NOTE 2

utility plant

Net utility plant as of December 31, 2003 and 2002 was as follows:


(thousands of dollars)
DECEMBER 31,	2003			2002

GAS PLANT:
Storage	$	4,158		$	4,213
Transmission		215,907			196,997
Distribution		2,496,708			2,293,655
General		197,693			198,093
Other		121,503			87,002

		3,035,969			2,779,960
Less: accumulated depreciation		(896,309	)		(814,908	)
Acquisition adjustments, net		2,533			2,714
Construction work in progress		33,543			66,693

Net utility plant	$	2,175,736		$	2,034,459

Depreciation and amortization expense on gas plant was $118 million in 2003, $113 million in 2002, and $102 million in 2001.

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notes to consolidated financial statements

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 rental payments for the LNG facilities are $3.3 million for 2004 and $1.7 million in 2005, when the lease expires in June. The rental payments for the corporate headquarters office complex are $2 million in each of the years 2004 through 2008 and $18.3 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.4 million in 2004, $1.5 million for each of the years 2005 through 2008, and $1 million in 2009 when the lease expires. 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 $20 million in 2003, $26.5 million in 2002, and $28 million in 2001. These amounts include NPL lease expenses of approximately $9.6 million in 2003, $12.3 million in 2002, and $12.6 million in 2001 for various short-term leases of equipment and temporary office sites.

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, 2003:


(thousands of dollars)
YEAR ENDING DECEMBER 31,

2004	$	8,408
2005		5,991
2006		4,130
2007		3,967
2008		3,997
Thereafter		20,543

Total minimum lease payments	$	47,036

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notes to consolidated financial statements

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, 2003, the gas utility customer accounts receivable balance was $102 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, 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
Additions charged to expense		2,523
Accounts written off, less recoveries		(2,102	)

Balance, December 31, 2003	$	2,246

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.

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notes to consolidated financial statements

The following table represents existing regulatory assets and liabilities:


(thousands of dollars)
DECEMBER 31,	2003			2002

REGULATORY ASSETS:
Deferred purchased gas costs	$	9,151		$	—
Accrued purchased gas costs *		8,800			—
SFAS No. 109 – income taxes, net		3,700			5,035
Unamortized premium on reacquired debt		18,560			12,614
Other		28,095			27,873

		68,306			45,522

REGULATORY LIABILITIES:
Deferred purchased gas costs		—			(26,718	)
Accumulated removal costs		(68,000	)		(55,000	)
Other		(425	)		(422	)

Net regulatory assets (liabilities)	$	(119	)	$	(36,618	)

* Included in Prepaids and other current assets on the Consolidated Balance Sheet.

Other regulatory assets include deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as amounts associated with accrued absence time and accrued post-retirement benefits other than pensions.

NOTE 5

preferred securities

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 Company issued to the Trust $61.8 million principal amount of its 9.125% Subordinated Deferrable Interest Notes, due 2025.

In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the distribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures are redeemable at the option of the Company after August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest. In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which

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notes to consolidated financial statements

Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust 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 Trust Securities. As of December 31, 2003, 4.1 million Preferred Trust Securities were outstanding.

The Company has the right to defer payments of interest on the Subordinated Debentures 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 to Preferred Trust Securities holders 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 7.70% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Debentures. 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 Debentures; 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 on the Subordinated Debentures.

A portion of the net proceeds from the issuance of the Preferred Trust Securities was used to complete the redemption of the 9.125% Trust Originated Preferred Securities effective September 2003 at a redemption price of $25 per Preferred Security, totaling $60 million plus accrued interest of $1.3 million.

In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities. FIN 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. Trust II, the issuer of the preferred trust securities, meets the definition of a variable interest entity.

Although the Company owns 100 percent of the common voting securities of Trust II, under current interpretation of FIN 46, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. The adoption of FIN 46 results in the Company reflecting a liability to Trust II (which under the prior accounting treatment would have been eliminated in consolidation) instead of to the holders of the preferred trust securities. As a result, payments and amortizations associated with the liability are classified on the consolidated statements of income as Net interest deductions on subordinated debentures. The $103.1 million Subordinated Debentures are shown on the balance sheet of the Company net of the $3.1 million Common Securities as Subordinated debentures due to Southwest Gas Capital II.

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notes to consolidated financial statements

NOTE 6

long-term debt


(thousands of dollars)
	2003					2002

DECEMBER 31,	CARRYING AMOUNT			MARKET VALUE		CARRYING AMOUNT			MARKET VALUE


DEBENTURES:
7½% Series, due 2006	$	75,000		$	83,149	$	75,000		$	81,889
Notes, 8.375%, due 2011		200,000			241,155		200,000			226,128
Notes, 7.625%, due 2012		200,000			232,198		200,000			218,166
8% Series, due 2026		75,000			88,240		75,000			79,017
Medium-term notes, 7.75% series, due 2005		25,000			27,198		25,000			27,342
Medium-term notes, 6.89% series, due 2007		17,500			19,443		17,500			18,781
Medium-term notes, 6.27% series, due 2008		25,000			27,219		25,000			25,946
Medium-term notes, 7.59% series, due 2017		25,000			29,217		25,000			26,711
Medium-term notes, 7.78% series, due 2022		25,000			29,076		25,000			25,725
Medium-term notes, 7.92% series, due 2027		25,000			29,220		25,000			26,134
Medium-term notes, 6.76% series, due 2027		7,500			7,725		7,500			6,870
Unamortized discount		(5,957	)		—		(6,534	)		—

		694,043					693,466

Revolving credit facility and commercial paper		100,000			100,000		100,000			100,000


INDUSTRIAL DEVELOPMENT REVENUE BONDS:
VARIABLE-RATE BONDS:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		—			—
2003 Series B, due 2038		50,000			50,000		—			—

FIXED-RATE BONDS:
7.30% 1992 Series A, due 2027		—			—		30,000			30,600
7.50% 1992 Series B, due 2032		—			—		100,000			102,000
6.50% 1993 Series A, due 2033		75,000			76,500		75,000			75,000
6.10% 1999 Series A, due 2038		12,410			12,596		12,410			13,744
5.95% 1999 Series C, due 2038		14,320			15,811		14,320			15,322
5.55% 1999 Series D, due 2038		8,270			9,014		8,270			8,332
5.45% 2003 Series C, due 2038		30,000			32,826		—			—
3.35% 2003 Series D, due 2038		20,000			20,000		—			—
5.80% 2003 Series E, due 2038		15,000			16,809		—			—
Unamortized discount		(1,986	)		—		(3,169	)		—

		323,014					286,831

Other		10,542			—		20,556			—

		1,127,599					1,100,853
Less: current maturities		(6,435	)				(8,705	)

Long-term debt, less current maturities	$	1,121,164				$	1,092,148

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PAGE 51

notes to consolidated financial statements

In May 2002, the Company replaced a $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, 2003, $50 million was outstanding on the commercial paper program.

In March 2003, the Company issued several series of Clark County, Nevada Industrial Development Revenue Bonds (“IDRBs”) totaling $165 million, due 2038. Of this total, variable-rate IDRBs ($50 million 2003 Series A and $50 million 2003 Series B) were used to refinance the $100 million 7.50% 1992 Series B, fixed-rate IDRBs due 2032. At December 31, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.66%. The $30 million 7.30% 1992 Series A, fixed-rate IDRBs due 2027 was refinanced with a $30 million 5.45% 2003 Series C fixed-rate IDRBs. An incremental $35 million ($20 million 3.35% 2003 Series D and $15 million 5.80% Series E fixed-rate IDRBs) was used to finance construction expenditures in southern Nevada during the first and second quarters of 2003. The Series C and Series E were set with an initial interest rate period of 10 years, while the Series D has an initial interest rate period of 18 months. After the initial interest rate periods, the Series C, D, and E interest rates will be reset at then prevailing market rates for periods not to exceed the maturity date of March 1, 2038.

The 2003 Series A and Series B IDRBs are supported by two letters of credit totaling $101.7 million, which expire in March 2006. These IDRBs are set at weekly rates and the letters of credit support the payment of principal or a portion of the purchase price corresponding to the principal of the IDRBs (while in the weekly rate mode).

The Company’s Revolving Credit Facilities contain financial covenants including a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $450 million (adjusted for sales of securities after May 31, 2002). In October 2003, a $55.3 million letter of credit, which supports the City of Big Bear $50 million tax-exempt Series A IDRBs, due 2028, was renewed for a three-year period expiring in October 2006. This letter of credit has a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $450 million (adjusted for sales of equity securities after July 1, 2003). If the Company were not in compliance with these covenants, an event of default would occur, which if not cured could cause the amounts outstanding to become due and payable. This would also trigger cross-default provisions in substantially all other outstanding indebtedness of the Company. At December 31, 2003, the Company was in compliance with the applicable covenants.

The interest rate on the tax-exempt variable-rate IDRBs averaged 2.73 percent in 2003 and 2.82 percent in 2002. 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, 2003 and 2002, 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.

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notes to consolidated financial statements

Estimated maturities of long-term debt for the next five years are $6.4 million, $128.1 million, $76 million, $17.5 million, and $25 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.

NOTE 7

short-term debt

As discussed in Note 6, Southwest has a $250 million credit facility consisting of a $125 million three-year facility and a $125 million 364-day facility. Effective May 2003, the Company renewed the $125 million 364-day facility for an additional year with no significant changes in rates or terms. Short-term borrowings were $52 million and $53 million at December 31, 2003 and 2002, respectively. The weighted-average interest rates on these borrowings were 2.04 percent at December 31, 2003 and 2.35 percent at December 31, 2002.

NOTE 8

commitments and contingencies

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. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.

Legal and Regulatory Proceedings. The Company is a 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.

southwest gas 2003 annual report

PAGE 53

notes to consolidated financial statements

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.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” expanding financial statement disclosure requirements for defined benefit plans. The following disclosures reflect the new requirements. In addition to expanded annual disclosures, various elements of pension and other postretirement benefit costs are required to be reported on a quarterly basis.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) was signed into law. The Medicare Act includes a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans which have a benefit at least actuarially equivalent to that included in the Medicare Act. 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. A prescription drug benefit is provided for the approximately 100 pre-1989 retirees. The Company is electing to defer recognizing the effects of the Medicare Act until authoritative guidance on the accounting for the federal subsidy is issued. The following disclosures of APBO and net periodic benefit cost do not reflect the effects of the Medicare Act. When authoritative guidance is issued, previously reported information may change.

Investment objectives and strategies for the retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors of the Company. They are designed to preserve capital, maintain minimum liquidity required for retirement plan operations and effectively manage pension assets.

A target portfolio of investments in the retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Rate of return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. The current percentage ranges of the target portfolio are:


Type of Investment		Percentage Range

Equity securities		55 to 67
Debt securities		32 to 38
Other		1 to 7

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 8.95% to 8.75% for 2004. The lower rate of return reflects anticipated investment returns on a long-term basis considering asset mix, projected and historical investment returns. This change, coupled with a 25 basis point reduction in the discount rate, will result in a $2.3 million increase in pension expense for 2004.

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notes to consolidated financial statements

The following tables set forth the retirement plan and PBOP funded status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.


(thousands of dollars)
	QUALIFIED RETIREMENT PLAN						PBOP
	2003			2002			2003			2002


CHANGE IN BENEFIT OBLIGATIONS
Benefit obligation for service rendered to date at beginning of year (PBO/APBO)	$	319,404		$	288,046		$	31,307		$	28,204
Service cost		12,267			11,585			675			595
Interest cost		21,243			20,568			2,095			1,992
Actuarial loss (gain)		25,580			7,905			1,850			1,966
Benefits paid		(9,400	)		(8,700	)		(1,560	)		(1,450	)

Benefit obligation at end of year (PBO/APBO)	$	369,094		$	319,404		$	34,367		$	31,307


CHANGE IN PLAN ASSETS
Market value of plan assets at beginning of year	$	242,159		$	274,103		$	12,912		$	12,402
Actual return on plan assets		49,464			(28,344	)		1,477			(647	)
Employer contributions		11,213			5,100			1,465			1,157
Benefits paid		(9,400	)		(8,700	)		—			—

Market value of plan assets at end of year	$	293,436		$	242,159		$	15,854		$	12,912

Funded status	$	(75,658	)	$	(77,245	)	$	(18,513	)	$	(18,395	)
Unrecognized net actuarial loss (gain)		56,649			52,936			6,741			6,760
Unrecognized transition obligation (2004/2012)		—			795			7,802			8,669
Unrecognized prior service cost		9			66			—			—

Prepaid (accrued) benefit cost	$	(19,000	)	$	(23,448	)	$	(3,970	)	$	(2,966	)


WEIGHTED-AVERAGE ASSUMPTIONS (BENEFIT OBLIGATION)
Discount rate		6.50	%		6.75	%		6.50	%		6.75	%
Rate of compensation increase		4.25	%		4.25	%		4.25	%		4.25	%

ASSET ALLOCATION
Equity securities		64	%		55	%		35	%		28	%
Debt securities		30	%		39	%		16	%		20	%
Other		6	%		6	%		49	%		52	%

Total		100	%		100	%		100	%		100	%

southwest gas 2003 annual report

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notes to consolidated financial statements

The measurement date used to determine pension and other postretirement benefit measurements was December 31, 2003. Estimated funding for the plans above during 2004 is approximately $14 million. The accumulated benefit obligation for the retirement plan was $289 million and $249 million at December 31, 2003 and 2002, respectively.

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.

components of net periodic benefit cost:


(thousands of dollars)
	QUALIFIED RETIREMENT PLAN									PBOP

	2003			2002			2001			2003			2002			2001

Service cost	$	12,267		$	11,585		$	11,057		$	675		$	595		$	591
Interest cost		21,243			20,568			18,805			2,095			1,992			1,856
Expected return on plan assets		(27,217	)		(27,178	)		(25,383	)		(1,205	)		(1,184	)		(1,073	)
Amortization of prior service costs		57			57			57			—			—			—
Amortization of unrecognized
transition obligation		795			837			837			867			867			867
Amortization of net (gain) loss		—			(207	)		(568	)		257			—			—

Net periodic benefit cost	$	7,145		$	5,662		$	4,805		$	2,689		$	2,270		$	2,241


WEIGHTED-AVERAGE ASSUMPTIONS (NET BENEFIT COST)
Discount rate		6.75	%		7.25	%		7.25	%		6.75	%		7.25	%		7.25	%
Expected return on plan assets		8.95	%		9.25	%		9.25	%		8.95	%		9.25	%		9.25	%
Rate of compensation increase		4.25	%		4.75	%		4.75	%		4.25	%		4.75	%		4.75	%

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 $2.7 million in 2003, $3 million in 2002, and $2.9 million in 2001. The accumulated benefit obligation of the plan was $24 million at December 31, 2003.

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 $3.3 million in 2003, $3.1 million in 2002, and $3 million in 2001. NPL 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.

southwest gas 2003 annual report

PAGE 56

notes to consolidated financial statements

At December 31, 2003, 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 $4.1 million in 2003, $3 million in 2002, and $3.1 million in 2001.

Under one 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:


	2003	2002	2001

Dividend yield	3.94%	3.64%	3.60%
Risk-free interest rate range	1.06 to 2.17%	1.70 to 2.63%	2.17 to 3.82%
Expected volatility range	16 to 25%	23 to 31%	22 to 27%
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)
	2003				2002				2001
	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	1,260		$	21.66	1,123		$	20.79	990		$	18.94
Granted during the year	348			21.05	320			21.97	317			23.23
Exercised during the year	(106	)		17.18	(183	)		16.95	(184	)		15.07
Forfeited during the year	—			—	—			—	—			—
Expired during the year	—			—	—			—	—			—

Outstanding at year end	1,502		$	21.83	1,260		$	21.66	1,123		$	20.79

Exercisable at year end	868		$	21.96	677		$	21.46	597		$	21.00

The weighted-average grant-date fair value of options granted was $1.90 for 2003, $2.69 for 2002, and $2.81 for 2001. The following table summarizes information about stock options outstanding at December 31, 2003:


(thousands of options)
	OPTIONS OUTSTANDING				OPTIONS EXERCISABLE
RANGE OF EXERCISE PRICE	NUMBER OUTSTANDING	WEIGHTED- AVERAGE REMAINING CONTRACTUAL LIFE	WEIGHTED- AVERAGE EXERCISE PRICE		NUMBER EXERCISABLE	WEIGHTED- AVERAGE EXERCISE PRICE

$15.00 to $19.13	285	5.1 Years	$	17.64	285	$	17.64
$20.49 to $24.50	1,099	8.1 Years	$	22.16	465	$	22.84
$28.75 to $28.94	118	5.5 Years	$	28.91	118	$	28.91

southwest gas 2003 annual report

PAGE 57

notes to consolidated financial statements

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 performance 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,	2003			2002			2001

Nonvested performance shares at beginning of year		345			314			237
Performance shares granted		147			122			142
Performance shares forfeited		—			—			—
Shares vested and issued		(111	)		(91	)		(65	)

Nonvested performance shares at end of year		381			345			314

Average grant date fair value of award	$	22.21		$	22.35		$	19.91

NOTE 10

income taxes

Income tax expense (benefit) consists of the following:


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003			2002			2001

CURRENT:
Federal	$	(24,176	)	$	5,546		$	27,750
State		(4,421	)		3,462			2,078

		(28,597	)		9,008			29,828

DEFERRED:
Federal		41,474			14,819			(9,902	)
State		4,005			(2,410	)		(341	)

		45,479			12,409			(10,243	)

Total income tax expense	$	16,882		$	21,417		$	19,585

Deferred income tax expense (benefit) consists of the following significant components:


(thousands of dollars)
YEAR ENDED DECEMBER 31,	2003			2002			2001

DEFERRED FEDERAL AND STATE:
Property-related items	$	46,808		$	44,491		$	19,560
Purchased gas cost adjustments		1,030			(29,087	)		(26,975	)
Employee benefits		(1,767	)		(5,113	)		(2,121	)
All other deferred		276			2,986			161

Total deferred federal and state		46,347			13,277			(9,375	)
Deferred ITC, net		(868	)		(868	)		(868	)

Total deferred income tax expense	$	45,479		$	12,409		$	(10,243	)

southwest gas 2003 annual report

PAGE 58

notes to consolidated financial statements

The consolidated effective income tax rate for the period ended December 31, 2003 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,	2003		2002		2001

Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Net state tax liability	2.4		1.0		3.2
Property-related items	1.3		—		1.5
Effect of closed tax years and resolved issues	(3.6	)	—		(4.4	)
Tax credits	(1.6	)	(1.3	)	(1.5	)
Corporate owned life insurance	(2.3	)	—		(0.5	)
All other differences	(0.7	)	(1.9	)	1.2

Consolidated effective income tax rate	30.5	%	32.8	%	34.5	%

Deferred tax assets and liabilities consist of the following:


(thousands of dollars)
DECEMBER 31,	2003			2002

DEFERRED TAX ASSETS:
Deferred income taxes for future amortization of ITC	$	8,037		$	8,574
Employee benefits		27,416			25,650
Alternative minimum tax		36,681			23,874
Net operating losses & credits		24,200			—
Other		6,076			4,195
Valuation allowance		—			—

		102,410			62,293


DEFERRED TAX LIABILITIES:
Property-related items, including accelerated depreciation		331,770			247,954
Regulatory balancing accounts		5,379			4,349
Property-related items previously flowed through		11,737			13,609
Unamortized ITC		12,933			13,801
Debt-related costs		5,777			4,378
Other		5,232			4,476

		372,828			288,567

Net deferred tax liabilities	$	270,418		$	226,274

Current	$	(6,914	)	$	(3,084	)
Noncurrent		277,332			229,358

Net deferred tax liabilities	$	270,418		$	226,274

At December 31, 2003, the Company has a federal net operating loss carryforward of $64.7 million which expires in 2022 to 2023 and a federal general business credit carryforward of $1.4 million which expires in 2011 to 2022. The Company also has an Arizona net operating loss carryforward of $33.1 million which expires in 2005 to 2007 and an Arizona tax credit carryforward of $826,000 which expires in 2004 to 2007.

southwest gas 2003 annual report

PAGE 59

notes to consolidated financial statements

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. NPL accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2003 and 2002, consolidated accounts receivable included $5.8 million and $6 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, 2003 is as follows:


(thousands of dollars)
2003	GAS OPERATIONS		CONSTRUCTION SERVICES		ADJUSTMENTS	TOTAL

Revenues from unaffiliated customers	$	1,034,353	$	137,717		$	1,172,070
Intersegment sales		—		58,934			58,934

Total	$	1,034,353	$	196,651		$	1,231,004

Interest expense	$	78,931	$	855		$	79,786

Depreciation and amortization	$	120,791	$	15,648		$	136,439

Income tax expense	$	13,920	$	2,962		$	16,882

Segment income	$	34,211	$	4,291		$	38,502

Segment assets	$	2,528,332	$	79,774		$	2,608,106

Capital expenditures	$	228,288	$	12,383		$	240,671


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	$	2,345,407	$	87,521		$	2,432,928

Capital expenditures	$	263,576	$	19,275		$	282,851

southwest gas 2003 annual report

PAGE 60

notes to consolidated financial statements


(thousands of dollars)
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

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.

NOTE 12

quarterly financial data (unaudited)


(thousands of dollars, except per share amounts)
	QUARTER ENDED
	MARCH 31		JUNE 30			SEPTEMBER 30			DECEMBER 31

2003
Operating revenues	$	403,285	$	255,852		$	220,162		$	351,705
Operating income (loss)		62,314		11,789			(8,285	)		69,287
Net income (loss)		25,539		(4,104	)		(17,407	)		34,474
Basic earnings (loss) per common share*		0.76		(0.12	)		(0.51	)		1.01
Diluted earnings (loss) per common share*		0.76		(0.12	)		(0.51	)		1.00

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

* 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.

southwest gas 2003 annual report

PAGE 61

notes to consolidated financial statements

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.

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 of 2002.

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.

NOTE 14

acquisition of black mountain gas company

In October 2003, the Company acquired all of the outstanding stock of Black Mountain Gas Company.

The assets acquired and the liabilities assumed at the acquisition date were as follows:


(thousands of dollars)
Gas plant	$	23,974
Less: accumulated depreciation		(5,992	)

Net utility plant		17,982
Other property and investments		1,500
Accounts receivable, net of allowances		504
Prepaids and other current assets		163
Deferred charges and other assets (includes goodwill of $5,445)		5,610

Total assets acquired		25,759

Accounts payable		219
Customer deposits		55
Deferred purchased gas costs		112
Accrued general taxes		144
Other deferred credits		1,229

Total liabilities assumed		1,759

Cash acquisition price	$	24,000

southwest gas 2003 annual report

PAGE 62

report of independent auditors

To the Shareholders of

Southwest Gas Corporation:

In our opinion, the accompanying consolidated balance sheets 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, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 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 audits 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 audits provide a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2001 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.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement obligations as of January 1, 2003, financial instruments with characteristics of both debt and equity and certain variable interest entities as of July 1, 2003.

PricewaterhouseCoopers LLP

Los Angeles, California

March 11, 2004

southwest gas 2003 annual report

PAGE 63

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.

List of Subsidiaries of Southwest Gas Corporation

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2003


SUBSIDIARY NAME		STATE OF INCORPORATION OR ORGANIZATION TYPE
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 II, III, IV		Delaware
Utility Financial Corp.		Nevada
Black Mountain Gas Company		Minnesota

Consent of PricewaterhouseCoopers LLP

Exhibit 23.01

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File Nos. 333-98995 and 333-106419) and Form S-8 (File Nos. 333-31223, 333-111034, and 333-106762) of Southwest Gas Corporation of our report dated March 11, 2004 relating to the financial statements which are incorporated by reference in this Form 10-K.

PricewaterhouseCoopers LLP

Los Angeles, California

March 11, 2004

Section 302 Certifications

EXHIBIT 31.01

Certification on Form 10-K

I, Michael O. Maffie, certify that:

1.	I have reviewed this annual report on Form 10-K of Southwest Gas Corporation;

2.	Based on my knowledge, this 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 report;

3.	Based on my knowledge, the financial statements, and other financial information included in this 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 report;

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-15(e) and 15d-15(e)) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;

(b)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: March 11, 2004

						/s/ MICHAEL O. MAFFIE
						Michael O. Maffie Chief Executive Officer Southwest Gas Corporation

Certification on Form 10-K

I, George C. Biehl, certify that:

1.	I have reviewed this annual report on Form 10-K of Southwest Gas Corporation;

2.	Based on my knowledge, this 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 report;

3.	Based on my knowledge, the financial statements, and other financial information included in this 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 report;

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-15(e) and 15d-15(e)) for the registrant and have:

(a)

(b)

(c)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: March 11, 2004

						/s/ GEORGE C. BIEHL
						George C. Biehl Executive Vice President, Chief Financial Officer and Corporate Secretary Southwest Gas Corporation

Section 906 Certifications

EXHIBIT 32.01

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2003 as filed with the Securities and Exchange Commission (the “Report”), I, Michael O. Maffie, the Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)

the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.


Dated: March 11, 2004

						/s/ MICHAEL O. MAFFIE
						Michael O. Maffie Chief Executive Officer

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2003 as filed with the Securities and Exchange Commission (the “Report”), I, George C. Biehl, Executive Vice President, Chief Financial Officer and Corporate Secretary of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)

the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.


Dated: March 11, 2004

						/s/ GEORGE C. BIEHL
						George C. Biehl Executive Vice President, Chief Financial Officer and Corporate Secretary

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