UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION
(Exact name of registrant as specified in its charter)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes |X|   No |_|

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes |X|   No |_|        

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.

Common Stock, $1 Par Value, 34,035,635 shares as of November 3, 2003.

PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except par value)

The accompanying notes are an integral part of these statements.

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
(Unaudited)

The accompanying notes are an integral part of these statements.

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
(Unaudited)

The accompanying notes are an integral part of these statements.

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Note 1 — Summary of Significant Accounting Policies

Nature of Operations. Southwest Gas Corporation (the Company) is comprised of two segments: natural gas operations (Southwest or the natural gas operations segment) and construction services. Southwest purchases, transports, and distributes natural gas to customers in portions of Arizona, Nevada, and California. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas sales are seasonal, peaking during the winter months. Variability in weather from normal temperatures can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Northern Pipeline Construction Co. (Northern or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor which provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

Basis of Presentation. The consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. The preparation of the consolidated financial statements 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 revenue and expenses during the reporting period. Actual results could differ from those estimates. In the opinion of management, all adjustments, consisting of normal recurring items and estimates necessary for a fair presentation of the results for the interim periods, have been made. It is suggested that these consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the 2002 Annual Report to Shareholders, which is incorporated by reference into the 2002 Form 10-K, and the first and second quarter 2003 Form 10-Qs.

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.

Intercompany Transactions. The construction services segment recognizes revenues generated from contracts with Southwest (see Note 2 below). Accounts receivable for these services were $6.1 million at September 30, 2003 and $6 million at December 31, 2002. The accounts receivable balance, revenues, and associated profits are included in the consolidated financial statements of the Company and were not eliminated during consolidation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is 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 on January 1, 2003. The adoption did not have a material impact on the financial position or results of operations of the Company.

In accordance with approved regulatory practices, Southwest accrues for future removal costs associated with utility plant retirements as a component of depreciation expense. At September 30, 2003, an estimated $294 million of accumulated removal costs were included in accumulated depreciation.

Stock-Based Compensation. The Company has two stock-based compensation plans, which are described more fully in Note 9 — Employee Benefits in the 2002 Annual Report to Shareholders. These plans are accounted for in accordance with Accounting Principles Board (APB) Opinion No. 25 “Accounting for Stock Issued to Employees” and related interpretations. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation –

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Transition and Disclosure – an Amendment of FASB Statement No. 123,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The Company has no current plans to adopt the fair value recognition provision of SFAS No. 123, “Accounting for Stock-Based Compensation.” The Company adopted the disclosure requirements of SFAS No. 148 effective December 2002. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123 to its stock-based employee compensation (thousands of dollars, except per share amounts):

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 3 below for additional information.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which is effective for contracts entered into or modified after June 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. The Company does not currently utilize stand-alone derivative instruments for speculative purposes or for hedging and does not have foreign currency exposure. None of the Company’s long-term financial instruments or other contracts are derivatives, or contain embedded derivatives with significant mark-to-market value. 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.

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Note 2 – Segment Information

The following tables list revenues from external customers, intersegment revenues, and segment net income (thousands of dollars):

Note 3 – Southwest Gas Capital II

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 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 September 30, 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

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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. The 9.125% Preferred Securities were originally issued in October 1995 by Southwest Gas Capital I, a consolidated wholly owned subsidiary of the Company.

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. This 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.

The effective date for variable interest entities in existence before February 1, 2003 was delayed until the end of the first interim or annual period ending after December 15, 2003, thus the consolidation of Southwest Gas Capital I is not currently affected by FIN 46.

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The Company is principally engaged in the business of purchasing, transporting, and distributing natural gas. 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.

Southwest purchases, transports, and distributes natural gas to approximately 1,491,000 residential, commercial, industrial, and other customers, of which 55 percent are located in Arizona, 36 percent are in Nevada, and 9 percent are in California. During the twelve months ended September 30, 2003, Southwest earned 56 percent of operating margin 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 general patterns are expected to continue.

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

Capital Resources and Liquidity

The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.

Southwest continues to experience significant customer growth. Financing this growth has required large amounts of capital to pay for new transmission and distribution plant, to keep up with consumer demand. During the twelve-month period ended September 30, 2003, capital expenditures for the natural gas operations segment were $236 million. Approximately 72 percent of these 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 $164 million of the required capital resources pertaining to these construction expenditures. The remainder was provided from external financing activities.

Asset Purchase

In October 2003, the Company completed the purchase of Black Mountain Gas Company (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. The acquisition was financed using existing credit facilities. BMG has approximately 8,600 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 as it does not intend to remain in the propane business. BMG operations will be integrated into the Central Arizona Division of Southwest.

2003 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 increases 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 reduce federal income taxes by approximately $65 million over the two-year period ending December 31, 2004.

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Southwest estimates construction expenditures during the three-year period ending December 31, 2005 will be approximately $675 million. Of this amount, $240 million are expected to be incurred in 2003. During the three-year period, cash flow from operating activities (net of dividends) is estimated to fund approximately 70-75 percent of the gas operations total construction expenditures, including the impacts of the 2002 and 2003 Acts. The Company expects to raise $55 million to $60 million from its Dividend Reinvestment and Stock Purchase Plan (DRSPP). The remaining cash requirements are expected to be provided by other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

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 IDRB due 2032. At September 30, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.61%. The $30 million 7.30% 1992 Series A, fixed-rate IDRB due 2027 was refinanced with a $30 million 5.45% 2003 Series C fixed-rate IDRB. 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).

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 June 2003, the Company filed on Form S-3 a registration statement for an incremental $100 million of various securities with the 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 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 3 – Southwest Gas Capital II.

Liquidity

Liquidity refers to the ability of an enterprise to generate adequate amounts of cash to meet its cash requirements. Several general factors that could significantly affect capital resources and liquidity in future years include inflation, growth in the economy, changes in income tax laws, changes in the ratemaking policies of regulatory commissions, interest rates, the level of natural gas prices, and the level of Company earnings.

The rate schedules in all of the service territories of Southwest contain purchased gas adjustment (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

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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 September 30, 2003, the combined balances in PGA accounts totaled an over-collection of $22 million. At December 31, 2002, the combined balances in PGA accounts totaled an over-collection of $27 million. See PGA Filings for more information.

The price of natural gas has increased compared to the prior year. The primary reasons for the price increase are a national demand for natural gas and a perceived tightened supply of gas for the upcoming winter. Southwest customers have benefited from the fixed prices associated with term contracts in place during 2003. However, these contracts are generally of short duration (less than one year) and cover about half of Southwest’s supply needs. Under an ongoing price volatility mitigation program, new contracts to replace those that are expiring have been purchased to ensure stable prices. However, these supplies are at higher prices compared to the previous year’s fixed-price purchases. Remaining needs will be covered with the purchase of natural gas on the spot market and are subject to market fluctuations. Market priced contracts to supply gas needs beyond the base fixed-price contracts negotiated for the upcoming winter months will generally have higher priced terms than the prior year. 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. As a result, the PGA account balances may shift from an over-collected to an under-collected status.

Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances. Southwest has a $250 million credit facility consisting of a $125 million three-year facility and a $125 million 364-day facility. Of the total $250 million facility, $150 million is designated as short-term debt which the Company believes is adequate to meet anticipated needs. All $150 million was available at September 30, 2003. Effective May 2003, the Company renewed the $125 million 364-day facility for an additional year with no significant changes in rates or terms.

Results of Consolidated Operations

See separate discussion at Results of Natural Gas Operations.

Construction services contribution to net income and earnings per share for the three, nine, and twelve months ended September 30, 2003 decreased when compared to the same periods ended September 30, 2002. The unfavorable settlement of a $1.3 million insurance claim during the third quarter of 2003 was the primary reason for the declines in each period.

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The following table sets forth the ratios of earnings to fixed charges for the Company (because of the seasonal nature of the Company’s business, these ratios are computed on a twelve-month basis):

Earnings are defined as the sum of pretax income plus fixed charges. Fixed charges consist of all interest expense including capitalized interest, one-third of rent expense (which approximates the interest component of such expense), preferred securities distributions, and amortized debt costs.

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Results of Natural Gas Operations

Quarterly Analysis

Contribution from natural gas operations decreased $487,000 in the third quarter of 2003 compared to the same period a year ago. The decrease was principally the result of lower operating margin and increased operating costs, partially offset by improved other (income) expense.

Operating margin decreased $1.7 million, or two percent, in the third quarter of 2003 compared to the third quarter of 2002. Customer growth contributed $2 million of incremental margin during the period. However, this was offset by a number of factors including variations in accrued utility revenues, gas procurement, transportation, and gas storage services. Margin from these services can vary from period to period. During the last twelve months Southwest has added nearly 64,000 customers, an increase of four percent.

Operations and maintenance expense increased less than one percent between quarters. The impacts of general cost increases and costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth were mitigated by cost-curbing measures implemented during the past year. Over the longer term, operations and maintenance expenses are expected to trend upward (corresponding to the customer growth rate and inflation).

Depreciation expense and general taxes increased $1.7 million, or four percent, as a result of construction activities. Average gas plant in service increased $237 million, or nine percent, as compared to the third quarter of 2002. The increase reflects ongoing capital expenditures for the upgrading of existing operating facilities and the expansion of the system to accommodate continued customer growth.

Other (income) expense improved $3.6 million between periods primarily due to non-recurring costs recognized in 2002. In the third quarter of 2002, costs associated with merger litigation and a regulatory disallowance in California totaled $2.1 million. In addition, returns from long-term investments improved between quarters.

Net financing costs increased $224,000, or one percent, between periods. Costs associated with incremental financings were partially offset by lower interest rates on variable-rate and refinanced debt and preferred securities.

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Nine-Month Analysis

Contribution from natural gas operations declined $1.6 million in the first nine months of 2003 compared to the same period a year ago. The decrease was principally the result of lower operating margin and increased operating expenses, substantially offset by the change in other (income) expense.

Operating margin decreased $11.2 million, or three percent, compared to the same period a year ago. Differences in heating demand caused by weather variations between periods resulted in a $17.5 million margin decrease as warmer-than-normal temperatures were experienced during both periods. Customer growth net of conservation, energy efficiencies, and other factors, partially offset the weather variance.

Operations and maintenance expense was virtually unchanged from the same period a year ago. 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. Operations and maintenance expenses overall are expected to trend higher over the longer term.

Depreciation expense and general taxes increased $5.4 million, or five percent, as a result of construction activities. Average gas plant in service increased $227 million, or nine percent, as compared to the first nine months of 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.

Other (income) expense improved $13.2 million between periods as the prior period included several non-recurring income and expense items. These included approximately $21.3 million in costs associated with settlements of merger-related litigation, merger litigation costs, and a regulatory disallowance in California. Partially offsetting these charges was a one-time pretax gain of $8.9 million on the sale of undeveloped property recorded in the first quarter of 2002.

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Twelve-Month Analysis

Contribution to consolidated net income increased $5.2 million in the current twelve-month period compared to the same period a year ago. The improvement was the result of an increase in other (income) expense which was partially offset by a decrease in operating margin and higher operating costs.

Operating margin decreased $5.5 million between periods. Differences in heating demand caused by weather variations between periods resulted in a $22 million margin decrease as warmer-than-normal temperatures were experienced during both periods. During the current twelve-month period, operating margin was negatively impacted by $35 million, and in the prior period, the negative impact was $13 million. Customer growth, partially offset by conservation, energy efficiencies, and other factors, contributed a net $15 million in incremental margin. Rate relief granted during the fourth quarter of 2001 added $1.5 million of margin.

Operations and maintenance expense increased $2.9 million, or one percent. 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. Operations and maintenance expenses overall are expected to trend higher over the longer term.

Depreciation expense and general taxes increased $9 million, or six percent, as a result of additional plant in service. Average gas plant in service for the current twelve-month period increased $226 million, or nine percent, compared to the corresponding period a year ago. This was attributable to the upgrade of existing operating facilities and the expansion of the system to accommodate new customers.

Other (income) expense improved $24.3 million between periods. The timing of merger-related litigation settlements, merger litigation costs, and the associated insurance recoveries in the fourth quarter of 2002 resulted in $14.6 million of income in the current period and $18.9 million of costs in the prior period. Prior-period results also included $11.9 million in gains on the sale of property and other assets recognized during the fourth quarter of 2001 and first quarter of 2002. In addition, a California regulatory disallowance recorded during the second and third quarters of 2002 totaled $2.7 million.

Net financing costs increased less than one percent between periods as the impacts of incremental borrowings to finance construction expenditures were offset by lower interest rates on variable-rate and refinanced debt and preferred securities.

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Income tax expense in the current period includes $2.7 million of income tax benefits, recognized in the fourth quarter of 2002, associated with state taxes and other items. The prior twelve-month period included $2.5 million of income tax benefits, recognized in the fourth quarter of 2001, associated with the favorable resolution of state income tax issues.

Rates and Regulatory Proceedings

California General Rate Cases. In February 2002, Southwest filed general rate applications with the California Public Utilities Commission (CPUC) for its northern and southern California jurisdictions. The applications sought annual increases over a five-year rate case cycle with a cumulative total of $6.3 million in northern California and $17.2 million in southern California.

In July 2002, the Office of Ratepayer Advocates (ORA) filed testimony in the rate case recommending significant reductions to the rate increases sought by Southwest. The ORA did concur with the majority of the Southwest rate design proposals including a margin tracking mechanism to mitigate weather-related and other usage variations. At the hearing that was held in August 2002, Southwest modified its proposal from a five-year to a three-year rate case cycle and accordingly reduced its cumulative request to $4.8 million in northern California and $10.7 million in southern California. For 2003, the amounts requested were $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 record 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 on the general rate case, which if approved as drafted would increase rates by about 70 percent of the 2003 amount filed for and provide for attrition increases beginning in 2004. The Company is still analyzing the draft decision which includes a brief comment period for all parties before a final CPUC decision is made. A final decision is expected by the first quarter of 2004. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.

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. 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. As of September 30, 2003, Southwest had the following PGA balances outstanding:

In June 2003, Southwest filed its annual PGA with the Public Utilities Commission of Nevada (PUCN). Southwest is recommending a change to a monthly PGA mechanism, rather than annual, to reduce volatility in rate changes. Southwest is proposing a 12-month rolling average of actual gas costs to set rates each month. If the monthly PGA is approved by the PUCN, it is anticipated that rates would increase 12.2 percent for customers in southern Nevada and decrease 13.1 percent in northern Nevada. If the monthly proposal is rejected and the current annual PGA method is retained, it is anticipated that rates would increase 12.2 percent in southern Nevada and decrease 10.2 percent in northern Nevada. A decision is expected in the fourth quarter of 2003.

Other Filings

Since November 1999, the Federal Energy Regulatory Commission (FERC) has been examining capacity allocation issues on the El Paso Natural Gas Company (El Paso) system in several proceedings. This examination resulted in a series of

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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 obtains 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. Management believes adequate capacity exists to meet the requirements of its customers for this coming heating season.

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. Additional costs may be incurred to acquire capacity in the future as a result of the FERC order. It is anticipated that any additional costs will be collected from customers through the PGA mechanism.

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. 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. This 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.

The effective date for variable interest entities in existence before February 1, 2003 was delayed until the end of the first interim or annual period ending after December 15, 2003, thus the consolidation of Southwest Gas Capital I is not currently affected by FIN 46.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which is 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. The Company does not currently utilize stand-alone derivative instruments for speculative purposes or for hedging and does not have foreign currency exposure. None of the Company’s long-term financial instruments or other contracts are derivatives, or contain embedded derivatives with significant mark-to-market value. 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.

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Forward-Looking Statements

This report contains statements which constitute “forward-looking statements” within the meaning of the Securities Litigation Reform Act of 1995 (Reform Act). All such forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act. A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, natural gas prices, the effects of regulation/deregulation, the timing and amount of rate relief, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, acquisitions, and competition. For additional information on the risks associated with the Company’s business, see Item 1. Business-Company Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

See Item 7A. Quantitative and Qualitative Disclosures about Market Risk in the Company’s 2002 Annual Report on Form 10-K filed with the SEC. No material changes have occurred related to the Company’s disclosures about market risk.

The Company has established disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms.

Based on the most recent evaluation, as of September 30, 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 third quarter that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.

PART II — OTHER INFORMATION

The Company has been 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 will have a material adverse impact on the Company’s financial position or results of operations.

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Pursuant to the requirements 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.

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