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

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

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.

2

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.

3

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

The accompanying notes are an integral part of these statements.

4

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 2001 Annual Report to Shareholders, which is incorporated by reference into the 2001 Form 10-K, and the first and second quarter 2002 Form 10-Qs.

Intercompany Transactions. The construction services segment recognizes revenues generated from contracts with Southwest (see Note 2 below). Accounts receivable for these services were $10 million at September 30, 2002 and $4.3 million at December 31, 2001. 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.”

Note 2 – Segment Information

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

5

Note 3 – Merger-related Litigation Settlements

Litigation in Arizona 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) has been resolved. For additional background information, see Item 3 “Legal Proceedings” in the 2001 Form 10-K filed by the Company with the SEC.

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, or $0.28 per share, charge and was reflected in the second quarter 2002 financial statements. Prior to 2002, the impact to Company financial results for merger litigation costs was not significant as most defense costs were reimbursed by insurance. In 2002, the Company exhausted its first layer of insurance coverage and began filing claims with a different insurance provider for reimbursement under its second layer of coverage. The Company and the insurance provider are in dispute over the type of coverage and whether it applies to the Southern Union settlement or related litigation defense costs. Because of this dispute, the Company did not recognize any benefit for potential insurance recoveries related to the Southern Union settlement in the second quarter. Management cannot predict the amount, if any, of insurance cost reimbursement the Company may receive.

6

ITEM 2.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
                 OF OPERATIONS

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 1,427,000 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 September 30, 2002, Southwest earned 57 percent of operating margin in Arizona, 35 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, 8 percent from other sales customers, and 9 percent from transportation customers. The percentage of transportation margin when compared to previous years is lower, reflecting a temporary shift by a number of large commercial and industrial customers from transportation service to sales service. Many of these customers are converting back to transportation service.

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, 2002, capital expenditures for the natural gas operations segment were $254 million. Approximately 68 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 $246 million of the required capital resources pertaining to these construction expenditures. The remainder was provided from external financing activities. Such cash flows were favorably impacted by changes in the purchased gas adjustment (PGA) recovery rates resulting in the collection of previously deferred purchased gas costs from customers and general rate relief.

In June 2002, the Company announced an agreement to purchase Black Mountain Gas Company (BMG), a gas utility serving Cave Creek and Page, Arizona. BMG has approximately 7,300 natural gas customers in a rapidly growing area north of Phoenix, Arizona. Regulatory approvals by the Arizona Corporation Commission (ACC) and the SEC are needed to consummate the purchase, which is expected to be completed in early 2003. The acquisition will be financed using existing credit facilities.

In March 2002, the Job Creation and Worker Assistance Act of 2002 (Act) was signed into law. This Act provides a three-year, 30 percent “bonus” tax depreciation deduction for businesses. Southwest estimates the bonus depreciation deduction will reduce federal income taxes paid by approximately $40 million to $50 million over the years 2002 through 2004.

Southwest estimates construction expenditures during the three-year period ending December 31, 2004 will be approximately $675 million. Of this amount, $225 million to $250 million is expected to be incurred in 2002. During the three-year period, cash flow from operating activities (net of dividends) is estimated to fund approximately 80 percent of the gas operations total construction expenditures,

7

including the impacts of the Act. The remaining cash requirements are expected to be provided by 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 May 2002, the Company issued $200 million in Senior Unsecured Notes, due 2012, bearing interest at 7.625%. The net proceeds from the sale of the Senior Unsecured Notes were used to redeem the $100 million 9 ¾% Debentures, Series F, in June 2002, and to reduce outstanding revolving credit loans.

In May 2002, the Company replaced the existing $350 million revolving credit facility that expired in June 2002 with a $125 million three-year facility and a $125 million 364-day facility. Of the total $250 million facility, $100 million will be designated as long-term debt. Interest rates for the new facility are calculated at either LIBOR plus or minus a competitive margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate.

In October 2002, the Company entered into a $50 million commercial paper facility. Any issuance under the commercial paper facility would be supported by the Company’s current revolving credit facility and therefore, does not represent new borrowing capacity. Interest rates for the new facility are calculated at the then current commercial paper rate.

The rate schedules in all of the service territories contain PGA clauses, which permit adjustments to rates as the cost of purchased gas changes. 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, 2001, the combined balances in PGA accounts totaled an under-collection of $84 million. At September 30, 2002, the combined balances reflected an over-collection of $29 million. Southwest utilizes short-term borrowings to finance PGA under-collected balances. Southwest has short-term borrowing capacity of $150 million, which is considered adequate to meet anticipated needs. See PGA Filings for the status of current PGA filings.

In January 2002, the Company sold all of its interests in undeveloped property located in northern Arizona. The property was originally acquired as a potential site for underground natural gas storage during the gas supply shortages of the 1970s, but was never developed. Proceeds from the sale were $20 million, of which $15 million was received in January and $5 million in September 2002. The sale resulted in a one-time pretax gain of $8.9 million, which was recognized in the first quarter of 2002.

Results of Consolidated Operations

See separate discussion at Results of Natural Gas Operations.

8

Construction services earnings per share for the three and nine months ended September 30, 2002 were relatively unchanged when compared to the same periods ended September 30, 2001. The increase in earnings per share during the twelve-month period was due to favorable weather conditions as compared to the same period in 2001.

The following table sets forth the ratios of earnings to fixed charges for the Company:

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.

Results of Natural Gas Operations

Quarterly Analysis

Contribution from natural gas operations improved $139,000 in the third quarter of 2002 compared to the same period a year ago. Increased operating margin was mostly offset by higher operating expenses and an unfavorable change in other income (expense).

Operating margin increased $7.3 million, or eight percent, in the third quarter of 2002 compared to the same period in 2001 resulting primarily from general rate relief and customer growth. General rate relief granted in Arizona (annualized at $21.6 million) and Nevada (annualized at $19.4 million) effective in the fourth quarter of 2001 was the primary driver of the quarterly increase. Additionally, the Company added 56,000 customers during the past twelve months, a growth rate of four percent.

Operations and maintenance expense increased $2.5 million, or four percent, reflecting general cost increases and incremental costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth.

9

Depreciation expense and general taxes increased $3.7 million, or 11 percent, as a result of construction activities. Average gas plant in service increased $212 million, or nine percent, as compared to the third quarter of 2001. 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) declined $2.8 million between periods. The current period includes a $1.4 million reduction in interest income primarily earned on the deferred PGA account balances and a $1.2 million charge associated with the final settlement of a regulatory issue in California (see California Order Instituting Investigation).

Net interest deductions declined $346,000 between periods. Strong cash flows throughout the year from the recovery of previously deferred purchased gas costs and general rate relief mitigated the need to externally finance construction expenditures.

Nine-Month Analysis

Contribution from natural gas operations declined $168,000 in the first nine months of 2002 compared to the same period a year ago. The decrease was principally the result of the merger litigation settlements and increased operating expenses, substantially offset by higher operating margin.

Operating margin increased $31 million, or nine percent compared to the same period a year ago. The increase was the result of general rate relief and customer growth, partially offset by the impacts of weather between periods. Rate relief added $31 million of operating margin. Customer growth contributed $11 million of incremental operating margin. Differences in heating demand caused by weather variations between periods resulted in an $11 million margin decrease. Near record warm temperatures during April 2002 negatively impacted current period margin while the prior period benefited from temperatures which were on average five percent colder than normal.

Operations and maintenance expense increased $8.5 million, or five percent, reflecting general increases in labor and maintenance costs, along with other operating expenses incurred to provide service to a steadily growing customer base.

Depreciation expense and general taxes increased $8.9 million, or nine percent, as a result of construction activities. Average gas plant in service increased $202 million, or eight percent, as compared to the first nine months of 2001. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.

10

During the second quarter of 2002, the Company recorded a net $14.5 million nonrecurring pretax charge related to the settlements of merger-related litigation. See Merger-related Litigation Settlements for additional information.

Other income (expense) declined $1.2 million between periods. The current period includes a $4.4 million reduction in interest income primarily earned on the deferred PGA account balances, $2.7 million of charges associated with the settlement of a regulatory issue in California (see California Order Instituting Investigation), and a $2.2 million increase in merger litigation costs, partially offset by a one-time pretax gain of $8.9 million on the sale of undeveloped property.

Twelve-Month Analysis

Contribution to consolidated net income decreased $2.4 million in the current twelve-month period compared to the same period a year ago. The impact of the merger litigation settlements, coupled with higher operating costs, was partially offset by growth in operating margin and improvement in other income (expense).

Operating margin increased $28 million between periods. Customer growth, coupled with increased margin from electric generation and industrial customers during the fourth quarter of 2001, contributed $17 million in incremental margin, while rate relief added $37 million. Differences in heating demand caused by weather variations between periods resulted in a $26 million margin decrease. Warmer-than-normal temperatures experienced during the fourth quarter of 2001 and second quarter of 2002 negatively impacted margin by $13 million. Prior-period margin was $13 million higher than expected due to temperatures that were ten percent colder than normal.

Operations and maintenance expense increased $13.2 million, or five percent, reflecting general increases in labor and maintenance costs, higher uncollectible expenses, and incremental operating expenses associated with providing service to a steadily growing customer base.

Depreciation expense and general taxes increased $12.1 million, or nine percent, as a result of additional plant in service. Average gas plant in service for the current twelve-month period increased $199 million, or eight 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.

During the second quarter of 2002, the Company recorded a net $14.5 million nonrecurring pretax charge related to the settlements of merger-related litigation. See Merger-related Litigation Settlements for additional information.

11

Other income (expense) improved $2.8 million between periods. The current period includes a one-time pretax gain of $8.9 million for the sale of undeveloped property and a $3 million nonrecurring pretax gain on the sale of certain assets recognized in the fourth quarter of 2001. These gains were partially offset by a $4.2 million decrease in interest income primarily earned on deferred PGA account balances, $2.7 million of charges associated with the settlement of a regulatory issue in California (see California Order Instituting Investigation) and a $2.5 million increase in merger litigation costs.

Income tax expense in the current period includes $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

Nevada General Rate Cases. In July 2001, Southwest filed general rate applications with the Public Utilities Commission of Nevada (PUCN) seeking approval to increase revenues by $21.7 million per year in its southern Nevada rate jurisdiction and $7.7 million in its northern Nevada rate jurisdiction. In November 2001, Southwest received approval from the PUCN to increase rates by $13.5 million, or five percent, annually in southern Nevada and $5.9 million, or five percent, annually in northern Nevada effective December 2001. In January 2002, the PUCN settled several open issues in the case regarding rate design. Changes included increasing the residential basic service charge by $2.00 per month in both jurisdictions, which should improve revenue stability in Nevada. The changes were effective February 2002 and did not impact the amount of rate relief granted.

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

In July 2002, the Office of Ratepayer Advocates (ORA) filed testimony in the rate case recommending significant reductions to the rate increases sought by Southwest. The ORA did concur with the majority of the Southwest rate design proposals including a margin tracking mechanism to mitigate weather-related and other usage variations. At the hearing that was held in August 2002, Southwest modified its proposal from a five year to a three year rate case cycle and accordingly reduced its cumulative request to $4.8 million in northern California and $10.7 million in southern California. For 2003, the amounts requested were reduced to $2.6 million in northern California and $5.9 million in southern California. A decision is expected by year-end, with rates to become effective in the first quarter of 2003. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.

Arizona Capacity Issues. Southwest is dependent upon the El Paso Natural Gas Company (El Paso) pipeline system for the transportation of gas to virtually all of its Arizona service territories. Southwest receives transportation service from El Paso to its Arizona service territories under a full requirements contract. Under full requirements service, El Paso is obligated to transport all of a customer’s gas requirements each day, and the customer is obligated to have El Paso, and only El Paso, transport its requirements. Virtually all of El Paso’s customers in Arizona, New Mexico and Texas are full requirements customers, while El Paso transports gas for its customers in California and Nevada subject to a specific maximum daily quantity, or contract demand limitation.

Since November 1999, the Federal Energy Regulatory Commission (FERC) has been examining capacity allocation issues on the El Paso system in several proceedings. During that time, the demand for natural gas on the El Paso system has risen, primarily due to increased electric power generation fuel needs and market area growth. As a result, shippers have been increasingly receiving reductions in the quantities of gas that they have been nominating for transportation each day. Many of the contract demand shippers have argued that the growth in the full requirements shippers’ volumes, coupled with El Paso’s failure to expand its system, have impaired their ability to receive all of the service to which they are entitled.

12

In May 2002, the FERC issued an order requiring that full requirements service be terminated as of November 2002. The order stated that full requirements transportation service agreements were to be converted to contract demand-type service agreements, and full requirements customers were to have an opportunity to negotiate an allocation of the system capacity determined by El Paso to be in excess of the capacity needed to fully serve the contract demand shippers. If the customers failed to agree upon an allocation, then the FERC would establish an allocation methodology for the customers. Following the order, various parties including Southwest submitted comments to the FERC seeking clarification or petitioning for rehearing.

In September 2002, the FERC issued an order 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 be used to allocate capacity among the full requirements customers. In addition, the FERC postponed the conversion of full requirements service agreements to contract demand-type service agreements until May 2003. Because the proceeding is still ongoing, further modifications to previous orders as well as additional rulings are expected.

Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. However, by delaying the effective date of the order, Arizona will have sufficient capacity this winter. Thereafter, management also expects that sufficient capacity will be available to Southwest, but additional costs may be incurred to acquire such capacity. It is anticipated that any additional costs will be collected from customers, principally through the PGA mechanism.

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.

Arizona PGA Filings. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. In January 2002, Southwest filed an advice letter with the ACC to eliminate a temporary rate adjustment surcharge, which was otherwise set to expire at the end of the second quarter of 2002. This action was taken in recognition of moderating gas costs and projections of PGA balancing account activity. The filing was approved effective February 2002 and reduces revenues by $31.9 million annually.

In October 2002, Southwest submitted a PGA filing to the ACC to reduce rates based on an over-collected PGA balance at August 2002 of $18.8 million. The ACC approved the rate reduction as filed with new rates effective November 2002.

Nevada PGA Filings. In December 2001, Southwest submitted an out-of-cycle PGA filing to the PUCN for a $29.2 million decrease for southern Nevada customers. In January 2002, an additional decrease of $13.9 million was requested. The total of the two filings, $43.1 million, was agreed to in a settlement among all parties and approved by the PUCN effective February 2002. The filings were made in advance of the scheduled annual date to allow customers to receive the benefit of decreases experienced in natural gas costs. In June 2002, Southwest filed its annual PGA, which requested no change in effective rates for either the southern or northern Nevada rate jurisdiction. However, subsequent to the filing, natural gas prices declined further, and in October 2002, through an all-party stipulation, Southwest agreed to decreases in PGA rates. The PUCN approved annual decreases of $13.5 million, or 14 percent, in northern Nevada and $8.7 million, or 4 percent, in southern Nevada. The new rates became effective in November 2002.

California Order Instituting Investigation (OII). In July 2001, the CPUC ordered an investigation into the reasonableness of Southwest natural gas procurement practices and costs from June 1999 through May 2001, and related measures taken to minimize gas costs beyond May 2001. During the third quarter of 2001, Southwest filed a detailed report and testimony with the CPUC on these matters for both its northern and southern California service territories. The OII resulted from complaints by southern California customers about the size of

13

monthly PGA rate increases that were necessary due to the unusually high cost of natural gas during the winter of 2000-2001. In regards to the southern California jurisdiction, the ORA and County of San Bernardino recommended disallowances of $7.3 million and $11.7 million, respectively. No issues were raised related to the northern California rate jurisdiction. The proposed disallowances were based solely on decisions by Southwest not to purchase additional gas for storage during the winter of 2000-2001. Hearings were held in January 2002. Southwest defended its decisions related to storage, based on testimony which demonstrated that injecting additional volumes of natural gas into storage during the 2000 injection season (April through September) could not be economically justified based on market conditions and price forecasts that existed at the time decisions were made.

During May 2002, the Administrative Law Judge issued a proposed decision and the Presiding Commissioner issued an alternate decision (AD) related to this matter. The proposed decision recommended that Southwest be disallowed $3.2 million, while the AD recommended a $5.8 million disallowance. The $3.2 million proposed decision contained calculation errors which, when corrected, reduced the proposed decision to $2.7 million. Both draft decisions concluded that Southwest should have had a higher gas storage inventory level than it had going into the winter of 2000-2001.

During July 2002, a second AD was drafted by another Commissioner, recommending a disallowance of nearly $1.5 million. An estimated $1.5 million liability was recognized in the Company’s second quarter 2002 financial statements based on management’s belief that a disallowance would be ordered. In August 2002, the CPUC issued a final order which disallowed $2.7 million of gas costs. Based on the CPUC decision, an additional $1.2 million liability was recognized in the Company’s third quarter 2002 financial statements. The CPUC ordered the $2.7 million be returned to customers through bill credits beginning in November 2002, based on each customer’s usage during the five month period from November 2000 through March 2001.

Merger-related Litigation Settlements

Litigation in Arizona 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) has been resolved. For additional background information, see Item 3 “Legal Proceedings” in the 2001 Form 10-K filed by the Company with the SEC.

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, or $0.28 per share, charge and was reflected in the second quarter 2002 financial statements. Prior to 2002, the impact to Company financial results for merger litigation costs was not significant as most defense costs were reimbursed by insurance. In 2002, the Company exhausted its first layer of insurance coverage and began filing claims with a different insurance provider for reimbursement under its second layer of coverage. The Company and the insurance provider are in dispute over the type of coverage and whether it applies to the Southern Union settlement or related litigation defense costs. Because of this dispute, the Company did not recognize any benefit for potential insurance recoveries related to the Southern Union settlement in the second quarter. Management cannot predict the amount, if any, of insurance cost reimbursement the Company may receive.

Recently Issued Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The asset retirement obligations included within the scope of SFAS No. 143 are those that are unavoidable as a result of the acquisition, construction, development, or normal operation of long-lived assets. The standard requires that a legal obligation associated with the retirement of tangible long-lived assets be recognized as a liability when incurred. When a liability for an asset retirement obligation is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Entities are also required to recognize period-to-period changes for the liability related to asset retirement obligations resulting from the passage of time

14

and/or revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. Upon initial application of SFAS No. 143, entities are required to recognize the following items in the statement of financial position: a liability for any existing asset retirement obligations adjusted for cumulative accretion to the date of adoption of SFAS No. 143, an asset retirement cost capitalized as an increase to the carrying amount of the associated long-lived asset, and accumulated depreciation for the capitalized cost. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002, with early adoption encouraged. Management has not yet quantified the effects of the new standard on the financial position or results of operations of the Company.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements.” The rescission of SFAS Nos. 4 and 64 is effective for fiscal years beginning after May 15, 2002. All other provisions of SFAS No. 145 are effective for transactions entered into, or financial statements issued, after May 15, 2002. The effective portions of the standard were adopted without impact during the second quarter of 2002 and management believes the remaining portions of the new standard will have no material effect on the financial position or results of operations of the Company.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability be recognized at fair value for a cost associated with an exit or disposal activity when the liability is incurred. Exit or disposal activities include a sale or termination of a line of business, the closure of business activities in a particular location, the relocation of business activities from one location to another, changes in management structure, and a fundamental reorganization that affects the nature and focus of operations. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. Management believes the new standard will have no material effect 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in the Company’s 2001 Form 10-K filed with the SEC. No material changes have occurred related to the Company’s disclosures about market risk.

ITEM 4. CONTROLS AND PROCEDURES

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

Based on the most recent evaluation, which was completed within 90 days of the filing of this Form 10-Q, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are operating effectively.

15

In addition, there were no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date of management’s most recent evaluation.

PART II — OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Merger-related Litigation Settlements

Litigation in Arizona related to the now terminated acquisition of the Company by ONEOK and the rejection of competing offers from Southern Union has been resolved. For additional background information, see Item 3 “Legal Proceedings” in the 2001 Form 10-K filed by the Company with the SEC.

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, or $0.28 per share, charge and was reflected in the second quarter 2002 financial statements.

ITEM 2-5.  None.

ITEM 6.     EXHIBITS AND REPORTS ON FORM 8-K

16

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.

17

Certification on Form 10-Q

I, Michael O. Maffie, certify that:

I have reviewed this quarterly report on Form 10-Q of Southwest Gas Corporation;

Based on my knowledge, this quarterly 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 quarterly report;

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

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

18

Certification on Form 10-Q

I, George C. Biehl, certify that:

I have reviewed this quarterly report on Form 10-Q of Southwest Gas Corporation;

Based on my knowledge, this quarterly 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 quarterly report;

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

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

19