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 June 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, 33,832,120 shares as of August 1, 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 quarter 2003 Form 10-Q.

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 million at June 30, 2003 and 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 June 30, 2003, an estimated $274 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 – 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

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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 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 is not expected to 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 is not expected to 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):

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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 1,477,000 residential, commercial, industrial, and other customers, of which 56 percent are located in Arizona, 35 percent are in Nevada, and 9 percent are in California. During the twelve months ended June 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 83 percent of operating margin from residential and small commercial customers, 6 percent from other sales customers, and 11 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 June 30, 2003, capital expenditures for the natural gas operations segment were $244 million. Approximately 69 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 $156 million of the required capital resources pertaining to these construction expenditures. The remainder was provided from external financing activities.

Asset Purchase

In June 2002, the Company announced an agreement to purchase Black Mountain Gas Company (BMG), a gas utility serving Cave Creek and Page, Arizona. BMG has approximately 7,300 natural gas customers in a rapidly growing area north of Phoenix, Arizona. In July 2003, the Company received regulatory approval from the Arizona Corporation Commission (ACC) for the acquisition. SEC approval is also needed to consummate the purchase, and is expected to be received in the third quarter of 2003. The acquisition will be financed using existing credit facilities.

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 next two years (2003-2004).

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

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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 June 30, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.51%. 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.

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. Therefore, the Company has a total of $300 million in securities registered with the SEC which are available for future financing needs. The registration statement also includes financing subsidiaries which could be used to issue preferred securities. In addition to raising new capital, the Company may utilize the registered securities to economically refinance outstanding facilities. This includes the potential redemption of $60 million of preferred securities.

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 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 June 30, 2003, the combined balances in PGA accounts totaled an over-collection of $34 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 during the past several months. The primary reasons for the price increases are low storage inventories resulting from a particularly cold winter in the midwest and eastern United States, and a predicted shortage of gas for filling storage for the upcoming winter. Southwest customers have benefited from the fixed prices associated with existing term contracts during the first half of 2003. However, these contracts are generally of short duration (less than one year) and cover about half of Southwest’s supply needs. Remaining needs are covered with the purchase of natural gas on the spot market. Southwest anticipates the term contracts being negotiated for the upcoming winter months will have higher priced terms than the prior year. Southwest

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continues to pursue all available sources to maintain the balance of 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 June 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, six, and twelve months ended June 30, 2003 increased modestly when compared to the same periods ended June 30, 2002. Improved margins on bid jobs and a favorable mix of work in several operating areas contributed to the increases.

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 increased $16.1 million in the second quarter of 2003 compared to the same period a year ago. The prior-year period included a net pretax $14.5 million ($9 million after tax) merger litigation settlement which was included in other (income) expense. The remaining improvement was principally the result of higher operating margin and a decrease in net interest deductions, partially offset by a modest increase in operating costs.

Operating margin increased $5.5 million, or five percent, in the second quarter of 2003 compared to the second quarter of 2002. Customer growth throughout Southwest’s service territories, partially offset by the impact of conservation and energy efficient appliances, added a net $3 million. Differences in heating demand caused by weather variations between periods accounted for the remainder of the margin increase as warmer-than-normal temperatures experienced in April of 2002 returned to more normal levels in 2003. During the last 12 months, Southwest added nearly 60,000 customers, an increase of four percent.

Operations and maintenance expense decreased $600,000, or one percent. The impact 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-saving management initiatives. 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 $2 million, or five percent, as a result of construction activities. Average gas plant in service increased $228 million, or nine percent, as compared to the second quarter 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 $19.6 million between periods primarily due to costs recognized in 2002. In the second quarter of 2002, merger litigation costs, net merger-related litigation settlements, and an accrual for a regulatory disallowance in California totaled approximately $19 million.

Net interest deductions decreased $1.3 million, or six percent, between periods primarily due to lower interest rates. In late March 2003, the Company refinanced $130 million of debt to take advantage of the low interest rate environment as more fully discussed under 2003 Construction Expenditures and Financing.

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Six-Month Analysis

Contribution from natural gas operations declined $1.1 million in the first six 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 $9.5 million, or three percent, compared to the same period a year ago. Record-setting warm temperatures experienced during the first quarter of 2003, partially offset by a return to more normal weather in April, resulted in a $17.5 million margin decrease. However, continuing customer growth contributed $8 million of incremental operating margin.

Operations and maintenance expense was virtually unchanged from the same period a year ago. The impact 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-saving 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 $3.8 million, or five percent, as a result of construction activities. Average gas plant in service increased $224 million, or nine percent, as compared to the first six 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 $9.6 million between periods. During the prior period, the Company recorded approximately $19.1 million in costs associated with settlements of merger-related litigation, merger litigation costs, and a regulatory disallowance in California. However, this was partially offset by a one-time pretax gain of $8.9 million on the sale of undeveloped property recorded in the first quarter of 2002. Interest income, primarily earned on deferred PGA balances, decreased by $1.1 million between periods.

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Twelve-Month Analysis

Contribution to consolidated net income increased $5.8 million in the current twelve-month period compared to the same period a year ago. The change in other (income) expense and growth in operating margin were partially offset by higher operating costs.

Operating margin increased $3.5 million between periods. Customer growth contributed an incremental $17.5 million and rate relief granted during the fourth quarter of 2001 added $8 million. 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.

Operations and maintenance expense increased $5.2 million, or two percent, reflecting general increases in labor and maintenance costs and incremental operating expenses associated with servicing additional customers, partially offset by cost-cutting measures initiated by management during the fourth quarter of 2002.

Depreciation expense and general taxes increased $11.1 million, or eight percent, as a result of additional plant in service. Average gas plant in service for the current twelve-month period increased $221 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 $17.8 million between periods. The timing of merger-related litigation settlements, merger litigation costs and the associated insurance recoveries created a net improvement between periods of $32.4 million. The recognition of $11.9 million in gains on the sale of property and other assets during the fourth quarter of 2001 and the first quarter of 2002 partially offset the merger-related change noted above. Interest income, primarily earned on deferred PGA balances, decreased $3.1 million between periods. Excluding the amounts associated with regulatory disallowances, merger-related issues, and asset sales, other income, net would have been approximately $300,000 in the current twelve-month period and $3.2 million in the prior period.

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.

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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 requesting 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. A decision on the general rate case is expected during the second half of 2003. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.

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 June 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, rates would increase 9.4 percent for customers in southern Nevada and decrease 12.2 percent in northern Nevada. If the monthly proposal is rejected and the current annual PGA method is retained, Southwest has requested that rates increase 12.6 percent in southern Nevada and decrease 7.3 percent in northern Nevada.

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. During that time, the demand for natural gas on the El Paso system has risen primarily due to increased electric power generation fuel needs and market area growth. As a result, shippers have been receiving reductions in the quantities of gas that they have been nominating for transportation each day. Many of the contract demand shippers have argued that the growth in the full requirements shippers’ volumes, coupled with El Paso’s failure to expand its system, have impaired their ability to receive all of the service to which they are entitled.

In May 2002, the FERC issued an order requiring that full requirements service be terminated as of November 2002. The order stated that full requirements transportation service agreements were to be converted to contract demand-type service agreements, and full requirements customers, such as Southwest, were to have an opportunity to negotiate an allocation of the system capacity determined

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by El Paso to be in excess of the capacity needed to fully serve the contract demand shippers. If the customers failed to agree upon an allocation, then the FERC would establish an allocation methodology for the customers. Following the order, various parties including Southwest submitted comments to the FERC seeking clarification or petitioning for rehearing.

In September 2002, the FERC issued an order on clarification of the May 2002 order. Among other things, the FERC determined that the full requirements customers had not agreed upon an allocation of capacity and, therefore, the FERC established a methodology to allocate capacity among the full requirements customers. In addition, the FERC postponed the conversion of full requirements service agreements to contract demand-type service agreements until May 2003, which was further deferred to September 2003 as a result of other El Paso proceedings.

In July 2003, the FERC issued an order denying rehearing on most of the issues addressed in its May 2002 and September 2002 orders. The FERC affirmed El Paso’s proposed allocation of capacity in compliance with the earlier orders, as well as the September 2003 conversion date. Various parties, including Southwest, are evaluating the latest order and are expected to pursue further rehearing or judicial review of the FERC’s orders.

Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. However, the delay of the effective date of the order allowed Southwest to maintain its full requirements contract status during the winter of 2002-2003 to serve its Arizona customers. 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, principally through the PGA mechanism.

Recently Issued Accounting Pronouncements

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 is not expected to 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 is not expected to have a material impact on the financial position or results of operations of the Company.

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, 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.

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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 June 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 during the second 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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The Annual Meeting of Shareholders was held on May 8, 2003 with the holders of approximately 30 million of the Company’s common shares represented in person or by proxy. Matters voted upon and the results of the voting were as follows:

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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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