Southwest Gas 10-Q 2004 Q2 Quarterly report

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, 2004

Commission File Number 1-7850

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

California
(State or other jurisdiction of
incorporation or organization)


5241 Spring Mountain Road
Post Office Box 98510
Las Vegas, Nevada
(Address of principal executive offices)
88-0085720
(I.R.S. Employer
Identification No.)


89193-8510
(Zip Code)

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

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, 35,293,916 shares as of August 2, 2004.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	JUNE 30, 2004			DECEMBER 31, 2003
ASSETS		(Unaudited)
Utility plant:
Gas plant	$	3,142,805		$	3,035,969
Less: accumulated depreciation		(941,670	)		(896,309	)
Acquisition adjustments, net		2,443			2,533
Construction work in progress		29,814			33,543
Net utility plant		2,233,392			2,175,736
Other property and investments		93,016			87,443
Current assets:
Cash and cash equivalents		10,800			17,183
Accounts receivable, net of allowances		95,532			126,783
Accrued utility revenue		30,300			66,700
Deferred income taxes		--			6,914
Deferred purchased gas costs		51,268			9,151
Prepaids and other current assets		52,420			54,356
Total current assets		240,320			281,087
Deferred charges and other assets		63,252			63,840
Total assets	$	2,629,980		$	2,608,106
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 45,000,000 shares; issued
and outstanding - 35,151,420 and 34,232,098 shares)	$	36,781		$	35,862
Additional paid-in capital		527,949			510,521
Retained earnings		102,401			84,084
Total equity		667,131			630,467
Subordinated debentures due to Southwest Gas Capital II		100,000			100,000
Long-term debt, less current maturities		1,125,767			1,121,164
Total capitalization		1,892,898			1,851,631
Current liabilities:
Current maturities of long-term debt		6,977			6,435
Short-term debt		54,000			52,000
Accounts payable		63,882			110,114
Customer deposits		46,968			44,290
Accrued general taxes		32,860			32,466
Accrued interest		19,321			19,665
Deferred income taxes		2,892			--
Other current liabilities		45,476			45,442
Total current liabilities		272,376			310,412
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		285,592			277,332
Taxes payable		6,895			6,661
Accumulated removal costs		77,000			68,000
Other deferred credits		95,219			94,070
Total deferred income taxes and other credits		464,706			446,063
Total capitalization and liabilities	$	2,629,980		$	2,608,106

        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)

	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,						TWELVE MONTHS ENDED JUNE 30,
	2004			2003			2004			2003			2004			2003
Operating revenues:
Gas operating revenues	$	226,756		$	205,382		$	660,540		$	565,365		$	1,129,528		$	1,013,635
Construction revenues		51,941			50,470			91,557			93,772			194,436			205,787
Total operating revenues		278,697			255,852			752,097			659,137			1,323,964			1,219,422
Operating expenses:
Net cost of gas sold		111,114			93,038			347,712			286,510			543,705			470,604
Operations and maintenance		70,687			64,433			140,668			130,490			277,040			264,343
Depreciation and amortization		36,058			33,526			72,142			66,838			141,743			134,011
Taxes other than income taxes		9,589			9,155			19,498			18,455			36,953			35,211
Construction expenses		45,295			43,911			80,321			82,741			171,765			182,012
Total operating expenses		272,743			244,063			660,341			585,034			1,171,206			1,086,181
Operating income		5,954			11,789			91,756			74,103			152,758			133,241
Other income and (expenses):
Net interest deductions		(18,799	)		(19,537	)		(37,543	)		(39,774	)		(74,875	)		(79,819	)
Net interest deductions on subordinated debentures		(1,931	)		--			(3,861	)		--			(6,541	)		--
Preferred securities distributions		--			(1,369	)		--			(2,738	)		(1,442	)		(5,475	)
Other income (deductions)		1,032			1,614			1,176			1,597			3,824			13,981
Total other income and (expenses)		(19,698	)		(19,292	)		(40,228	)		(40,915	)		(79,034	)		(71,313	)
Income (loss) before income taxes		(13,744	)		(7,503	)		51,528			33,188			73,724			61,928
Income tax expense (benefit)		(5,382	)		(3,399	)		18,846			11,753			23,975			18,814
Net income (loss)	$	(8,362	)	$	(4,104	)	$	32,682		$	21,435		$	49,749		$	43,114
Basic earnings (loss) per share	$	(0.24	)	$	(0.12	)	$	0.95		$	0.64		$	1.45		$	1.29
Diluted earnings (loss) per share	$	(0.24	)	$	(0.12	)	$	0.94		$	0.63		$	1.44		$	1.28
Dividends paid per share	$	0.205		$	0.205		$	0.41		$	0.41		$	0.82		$	0.82
Average number of common shares outstanding		34,741			33,665			34,576			33,552			34,269			33,346
Average shares outstanding (assuming dilution)		--			--			34,825			33,789			34,556			33,612

        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)

	SIX MONTHS ENDED JUNE 30,						TWELVE MONTHS ENDED JUNE 30,
	2004			2003			2004			2003
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	32,682		$	21,435		$	49,749		$	43,114
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization		72,142			66,838			141,743			134,011
Deferred income taxes		18,066			9,311			52,899			18,290
Changes in current assets and liabilities:
Accounts receivable, net of allowances		31,251			44,343			(8,676	)		9,407
Accrued utility revenue		36,400			36,173			(1,400	)		(926	)
Deferred purchased gas costs		(42,117	)		7,219			(85,317	)		14,158
Accounts payable		(46,232	)		(36,250	)		11,604			(863	)
Accrued taxes		628			1,426			(1,184	)		2,020
Other current assets and liabilities		4,001			9,504			(3,811	)		(2,628	)
Other		(777	)		(6,828	)		5,042			(12,108	)
Net cash provided by operating activities		106,044			153,171			160,649			204,475
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(126,227	)		(100,893	)		(266,005	)		(260,974	)
Other		2,823			3,307			(18,699	)		14,775
Net cash used in investing activities		(123,404	)		(97,586	)		(284,704	)		(246,199	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		18,347			9,245			30,392			17,265
Dividends paid		(14,176	)		(13,759	)		(28,102	)		(27,346	)
Issuance of subordinated debentures, net		--			--			96,312			--
Issuance of long-term debt, net		8,000			164,513			3,484			167,151
Retirement of long-term debt, net		(3,194	)		(134,419	)		(8,788	)		(139,008	)
Retirement of preferred securities		--			--			(60,000	)		--
Temporary changes in long-term debt		--			(37,000	)		37,000			30,000
Change in short-term debt		2,000			(53,000	)		54,000			(1,500	)
Net cash provided by (used in) financing activities		10,977			(64,420	)		124,298			46,562
Change in cash and cash equivalents		(6,383	)		(8,835	)		243			4,838
Cash at beginning of period		17,183			19,392			10,557			5,719
Cash at end of period	$	10,800		$	10,557		$	10,800		$	10,557
Supplemental information:
Interest paid, net of amounts capitalized	$	40,317		$	40,281		$	78,597		$	79,773
Income taxes paid (received), net		118			(1,071	)		(25,544	)		(705	)

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

Basis of Presentation. The 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 (the “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 2003 Annual Report to Shareholders, which is incorporated by reference into the 2003 Form 10-K and the first quarter 2004 Form 10-Q.

Intercompany Transactions. NPL recognizes revenues generated from contracts with Southwest (seeNote 2 below). Accounts receivable for these services were $6.9 million at June 30, 2004 and $5.8 million at December 31, 2003. 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.”

5

Stock-Based Compensation. The Company has two stock-based compensation plans, which are described more fully inNote 9 — Employee Benefitsinthe 2003 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. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123 “Accounting for Stock-Based Compensation” to its stock-based employee compensation (thousands of dollars, except per share amounts):

	Period Ended June 30,
	Three Months						Six Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Net income (loss), as reported	$	(8,362	)	$	(4,104	)	$	32,682		$	21,435		$	49,749		$	43,114
Add:
Stock-based employee
compensation expense included
in reported net income (loss),
net of related tax benefits		499			428			888			912			2,414			1,803
Deduct:
Total stock-based employee
compensation expense
determined under fair value
based method for all awards,
net of related tax benefits		(699	)		(553	)		(1,206	)		(1,162	)		(2,964	)		(2,188	)
Pro forma net income (loss)	$	(8,562	)	$	(4,229	)	$	32,364		$	21,185		$	49,199		$	42,729
Earnings (loss) per share:
Basic - as reported	$	(0.24	)	$	(0.12	)	$	0.95		$	0.64		$	1.45		$	1.29
Basic - pro forma		(0.25	)		(0.13	)		0.94			0.63			1.44			1.28
Diluted - as reported		(0.24	)		(0.12	)		0.94			0.63			1.44			1.28
Diluted - pro forma		(0.25	)		(0.13	)		0.93			0.63			1.42			1.27

Components of Net Periodic Benefit Cost. Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. Southwest also provides postretirement benefits other than pensions (“PBOP”) to its qualified retirees for health care, dental, and life insurance benefits.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) was signed into law. The Medicare Act includes a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans which have a benefit at least actuarially equivalent to that included in the Medicare Act. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. A prescription drug benefit is provided for the approximately 100 pre-1989 retirees. The Company elected to defer recognizing the effects of the Medicare Act until authoritative guidance on the accounting for the federal subsidy was issued. Recently, authoritative accounting guidance was issued and an actuary determined the Company’s prescription drug benefit is not actuarially equivalent to that included in the Medicare Act. Therefore, neither plan assets nor Company operating results will be affected.

6

In December 2003, the Financial Accounting Standards Board issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” requiring interim financial statement disclosure for defined benefit plans. The following disclosures reflect the new requirements for interim reporting (thousands of dollars):

Components of Net Periodic Benefit Cost

	Qualified Retirement Plan
	Period Ended June 30,
	Three Months						Six Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Service cost	$	3,447		$	3,067		$	6,895		$	6,134		$	13,028		$	11,927
Interest cost		5,915			5,312			11,830			10,622			22,451			20,906
Expected return on plan assets		(7,017	)		(6,805	)		(14,034	)		(13,609	)		(27,642	)		(27,198	)
Amortization of prior service costs		14			14			27			28			56			56
Amortization of unrecognized
transition obligation		--			199			--			398			397			817
Amortization of net (gain) loss		--			--			--			--			--			(104	)
Net periodic benefit cost	$	2,359		$	1,787		$	4,718		$	3,573		$	8,290		$	6,404

	PBOP
	Period Ended June 30,
	Three Months						Six Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Service cost	$	180		$	170		$	361		$	338		$	698		$	636
Interest cost		546			524			1,091			1,048			2,138			2,044
Expected return on plan assets		(357	)		(302	)		(714	)		(603	)		(1,316	)		(1,195	)
Amortization of prior service costs		--			--			--			--			--			--
Amortization of unrecognized
transition obligation		217			217			434			434			867			867
Amortization of net (gain) loss		53			64			106			128			235			128
Net periodic benefit cost	$	639		$	673		$	1,278		$	1,345		$	2,622		$	2,480

7

Note 2 – Segment Information

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

	Natural Gas Operations			Construction Services		Total
Three months ended June 30, 2004
Revenues from external customers	$	226,756		$	36,630	$	263,386
Intersegment revenues		--			15,311		15,311
Total	$	226,756		$	51,941	$	278,697
Segment net income	$	(10,610	)	$	2,248	$	(8,362	)
Three months ended June 30, 2003
Revenues from external customers	$	205,382		$	36,057	$	241,439
Intersegment revenues		--			14,413		14,413
Total	$	205,382		$	50,470	$	255,852
Segment net income	$	(5,755	)	$	1,651	$	(4,104	)

	Natural Gas Operations		Construction Services		Total
Six months ended June 30, 2004
Revenues from external customers	$	660,540	$	63,022	$	723,562
Intersegment revenues		--		28,535		28,535
Total	$	660,540	$	91,557	$	752,097
Segment net income	$	29,946	$	2,736	$	32,682
Six months ended June 30, 2003
Revenues from external customers	$	565,365	$	64,492	$	629,857
Intersegment revenues		--		29,280		29,280
Total	$	565,365	$	93,772	$	659,137
Segment net income	$	19,581	$	1,854	$	21,435

	Natural Gas Operations		Construction Services		Total
Twelve months ended June 30, 2004
Revenues from external customers	$	1,129,528	$	136,247	$	1,265,775
Intersegment revenues		--		58,189		58,189
Total	$	1,129,528	$	194,436	$	1,323,964
Segment net income	$	44,576	$	5,173	$	49,749
Twelve months ended June 30, 2003
Revenues from external customers	$	1,013,635	$	136,758	$	1,150,393
Intersegment revenues		--		69,029		69,029
Total	$	1,013,635	$	205,787	$	1,219,422
Segment net income	$	38,152	$	4,962	$	43,114

8

Note 3 – Long-Term Debt

Effective May 2004, the Company obtained a new $250 million three-year credit facility of which $150 million is for working capital purposes (and related outstanding amounts will be designated as short-term debt). Interest rates for the new facility are calculated at either the London Interbank Offering Rate (“LIBOR”) plus an applicable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. The new facility replaces the former $250 million credit facility consisting of a $125 million three-year facility and a $125 million 364-day facility.

Note 4 – Subsequent Events

In July 2004, the Company announced an agreement with Avista Corporation (“Avista”) to purchase Avista’s natural gas distribution properties in South Lake Tahoe, California. Avista serves approximately 18,000 customers. The cash purchase price for the properties is $15 million, subject to closing adjustments. The agreement is also subject to customary closing conditions and regulatory review, including approval by the California Public Utilities Commission (“CPUC”). Once approvals have been received, the properties will be integrated into the northern Nevada operations of Southwest, which include contiguous gas properties in the Lake Tahoe Basin. It is anticipated that Southwest will assume the rates in effect at the time of closing the purchase.

In July 2004, the Company issued $65 million in Clark County, Nevada Industrial Development Revenue Bonds (“IDRBs”) Series 2004A, due 2034. The net proceeds from the 5.25% tax-exempt bonds will be used to finance construction expenditures in southern Nevada.

9

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

Executive Summary

The following discussion of Southwest Gas Corporation and subsidiaries includes information related to regulated natural gas transmission and distribution activities and non-regulated activities.

The Company is comprised of two business segments: natural gas operations and construction services. Southwest (“natural gas operations”) is engaged in the business of purchasing, transporting, and distributing natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor and transporter of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

Southwest purchases, transports, and distributes natural gas to approximately 1,560,000 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 June 30, 2004, Southwest earned 54 percent of operating margin in Arizona, 35 percent in Nevada, and 11 percent in California. During this same period, Southwest earned 86 percent of operating margin from residential and small commercial customers, 5 percent from other sales customers, and 9 percent from transportation customers. These general patterns are expected to continue.

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

Results of Consolidated Operations

	Period Ended June 30,
	Three Months						Six Months				Twelve Months
	2004			2003			2004		2003		2004		2003
Contribution to net income (loss)
(Thousands of dollars)
Natural gas operations	$	(10,610	)	$	(5,755	)	$	29,946	$	19,581	$	44,576	$	38,152
Construction services		2,248			1,651			2,736		1,854		5,173		4,962
Net income (loss)	$	(8,362	)	$	(4,104	)	$	32,682	$	21,435	$	49,749	$	43,114
Basic earnings (loss) per share
Natural gas operations	$	(0.30	)	$	(0.17	)	$	0.87	$	0.58	$	1.30	$	1.14
Construction services		0.06			0.05			0.08		0.06		0.15		0.15
Consolidated	$	(0.24	)	$	(0.12	)	$	0.95	$	0.64	$	1.45	$	1.29

See separate discussions atResults of Natural Gas Operationsand Results of Construction Services.

As reflected in the table above, the natural gas operations segment accounted for an average of 89 percent of twelve-month-to-date consolidated net income over the past two years. Accordingly, management’s main focus of discussion in this document is on that segment.

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

10

Hearings were held in July for the March 2004 general rate applications with the Public Utilities Commission of Nevada (“PUCN”), which included a request for a total annual increase of $27.5 million for Southwest’s southern and northern Nevada service territories. A decision by the PUCN is expected in the third quarter of 2004. (See the section onRates and Regulatory Proceedings for additional information).

In May 2004, the PUCN approved a request by the Company to increase rates charged to recover purchased gas costs (“PGA rates”) in Nevada. The increase totaled $55.4 million on an annual basis effective June 2004. PGA rates affect cash flows, but not operating margin.

Weather is a significant driver of natural gas volumes used by residential and small commercial customers and is the main reason for volatility in margin. Space heating-related volumes are the primary component of billings for these customer classes and are concentrated in the months of November to April for the majority of the Company’s customers. Variances in temperatures from normal levels, especially during these months, have a significant impact on the margin and associated net income of the Company. Second quarter 2004 weather was warmer than normal as were temperatures in the second quarter of 2003. The impact on margin was a decrease of $2 million between periods.

Customer growth, excluding acquisitions, has averaged five percent annually over the past 10 years and over four percent annually during the past three years and continues to be strong. Southwest served 83,000 more customers (including 9,000 from an acquisition) than in the second quarter of 2003. Incremental margin has accompanied this customer growth, but the costs associated with creating and maintaining the infrastructure needed to accommodate these customers also are increasing. The timing of including these costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Management has attempted to mitigate the regulatory lag by being judicious in its staffing levels through the effective use of technology. Cost-curbing measures were set in place by management during 2002 and 2003. However, growth, coupled with external factors, is causing operating expenses to trend upward corresponding to the customer growth rate and inflation. Operations and maintenance expense for the second quarter and the first six months of 2004 reflects this trend. The cost of additional regulation, mandated social programs, medical costs, and pensions are some of the primary factors responsible for this trend.

Customer growth requires significant capital outlays for new transmission and distribution plant. Necessary financing of continued construction occurred during the second quarter. In April, the Company entered into a sales agency financing agreement with BNY Capital Markets, Inc. (“BNYCMI”). Up to an aggregate $60 million of common stock may be issued in at-the-market offerings from time to time with BNYCMI acting as agent. As of June 30, 2004, the Company had issued approximately 313,000 shares with proceeds of $7.3 million through this facility. (See the section on2004 Construction Expenditures and Financing for additional information).

11

Results of Natural Gas Operations

Quarterly Analysis

	Three Months Ended June 30,
	2004			2003
	(Thousands of dollars)
Gas operating revenues	$	226,756		$	205,382
Net cost of gas sold		111,114			93,038
Operating margin		115,642			112,344
Operations and maintenance expense		70,687			64,433
Depreciation and amortization		32,266			29,532
Taxes other than income taxes		9,589			9,155
Operating income		3,100			9,224
Other income		81			1,119
Net interest deductions		18,681			19,263
Net interest deductions on subordinated debentures		1,931			--
Preferred securities distributions		--			1,369
Income (loss) before income taxes		(17,431	)		(10,289	)
Income tax expense (benefit)		(6,821	)		(4,534	)
Contribution to consolidated net income (loss)	$	(10,610	)	$	(5,755	)

Contribution from natural gas operations decreased $4.9 million in the second quarter of 2004 compared to the same period a year ago. The decline was principally the result of increased operating costs partially offset by higher operating margin.

Operating margin increased approximately $3 million, or three percent, in the second quarter of 2004 compared to the second quarter of 2003. Customer growth contributed an incremental $3 million in operating margin during the quarter. Rate relief in California added $2 million in margin, while differences in heating demand caused by weather variations between periods accounted for a $2 million decrease, as both periods were warmer than normal. During the last twelve months, the Company added a record 74,000 customers, an increase of five percent. Another 9,000 customers were added in October 2003 with the acquisition of Black Mountain Gas Company (“BMG”).

Operations and maintenance expense increased $6.3 million, or ten percent, primarily due to the impact of general cost increases and costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth. Additional factors include BMG-related operating costs, and higher employee-related and regulatory costs.

Depreciation expense and general taxes increased $3.2 million, or eight percent, as a result of construction activities. Average gas plant in service increased $252 million, or nine percent, as compared to the second quarter of 2003. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities, the expansion of the system to accommodate continued customer growth and the cost to acquire the BMG system.

Despite an increase in outstanding debt, net financing costs were virtually unchanged between periods due to interest savings generated from debt and preferred securities instrument refinancings and a reduction in interest costs associated with the purchased gas adjustment (“PGA”) account balance.

Other income declined approximately $1 million due to lower returns on long-term investments in the second quarter of 2004.

12

Six-Month Analysis

	Six Months Ended June 30,
	2004		2003
	(Thousands of dollars)
Gas operating revenues	$	660,540	$	565,365
Net cost of gas sold		347,712		286,510
Operating margin		312,828		278,855
Operations and maintenance expense		140,668		130,490
Depreciation and amortization		64,552		58,855
Taxes other than income taxes		19,498		18,455
Operating income		88,110		71,055
Other income		61		851
Net interest deductions		37,308		39,212
Net interest deductions on subordinated debentures		3,861		--
Preferred securities distributions		--		2,738
Income before income taxes		47,002		29,956
Income tax expense		17,056		10,375
Contribution to consolidated net income	$	29,946	$	19,581

Contribution from natural gas operations increased $10.4 million in the first six months of 2004 compared to the same period a year ago. The improvement was principally the result of higher operating margin partially offset by increased operating costs.

Operating margin increased approximately $34 million, or 12 percent, in the first six months of 2004 compared to the first six months of 2003. Differences in heating demand caused by weather variations between periods resulted in a $16 million margin increase as warmer-than-normal temperatures were experienced during both periods. During the current period, operating margin was negatively impacted by $9 million, while the negative impact in the prior period was $25 million. Rate relief in California added $9 million in margin and customer growth contributed an incremental $9 million.

Operations and maintenance expense increased $10.2 million, or eight percent, principally due to the impact of general cost increases and costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth. Additional factors include BMG-related operating costs, and higher employee-related and regulatory costs.

Depreciation expense and general taxes increased $6.7 million, or nine percent, as a result of construction activities. Average gas plant in service increased $254 million, or nine percent, as compared to the first six months of 2003. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities, the expansion of the system to accommodate continued customer growth and the BMG system acquisition cost.

Net financing costs decreased $781,000, or two percent, between periods primarily due to interest savings generated from the refinancing of IDRBs and preferred securities instruments and a reduction in PGA-related interest.

13

Twelve-Month Analysis

	Twelve Months Ended June 30,
	2004		2003
	(Thousands of dollars)
Gas operating revenues	$	1,129,528	$	1,013,635
Net cost of gas sold		543,705		470,604
Operating margin		585,823		543,031
Operations and maintenance expense		277,040		264,343
Depreciation and amortization		126,488		118,290
Taxes other than income taxes		36,953		35,211
Operating income		145,342		125,187
Other income		2,165		12,701
Net interest deductions		74,347		78,549
Net interest deductions on subordinated debentures		6,541		--
Preferred securities distributions		1,442		5,475
Income before income taxes		65,177		53,864
Income tax expense		20,601		15,712
Contribution to consolidated net income	$	44,576	$	38,152

Contribution to consolidated net income increased $6.4 million in the current twelve-month period compared to the same period a year ago. The improvement in contribution was primarily caused by higher operating margin, partially offset by increased operating costs and a decline in other income.

Operating margin increased $43 million, or eight percent, between periods. Differences in heating demand caused by weather variations between periods resulted in a $20 million margin increase as warmer-than-normal temperatures were experienced during both periods. During the current period, operating margin was negatively impacted by $15 million, while in the prior period the negative impact was $35 million. Customer growth contributed an incremental $17 million and California rate relief added $9 million. Conservation, energy efficiency, and other factors partially offset these improvements.

Operations and maintenance expense increased $12.7 million, or five percent, reflecting general increases in labor and maintenance costs and incremental operating expenses associated with providing service to a steadily growing customer base, partially offset by cost-curbing measures in place during 2003. Going forward, operations and maintenance expenses are expected to trend upward corresponding to the customer growth rate and inflation. The cost of additional regulation, mandated social programs, medical costs, and pensions are some of the primary factors responsible for this trend.

Depreciation expense and general taxes increased $9.9 million, or six percent, as a result of additional plant in service. Average gas plant in service for the current twelve-month period increased $247 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 continued customer growth.

Other income declined $10.5 million between periods. The prior period reflects income of $13.6 million associated with the timing of merger-related insurance recoveries, net of costs. The current period includes a $2.3 million improvement in returns on long-term investments.

Net financing costs decreased $1.7 million, or two percent, primarily due to interest savings generated from the refinancing of IDRBs and preferred securities instruments.

14

Income tax expense in the current period includes $2 million of income tax benefits, recognized in the fourth quarter of 2003, associated with plant-related items. The prior period included $2.7 million of income tax benefits, recognized in the fourth quarter of 2002, associated with state taxes, plant, and non-plant related items.

Results of Construction Services

Construction services contribution to net income for the three and six months ended June 30, 2004 increased $597,000 and $882,000, respectively, when compared to the same periods ended June 30, 2003. The improvement resulted from favorable weather conditions in several operating areas in the first quarter and an increase in the number of jobs (including profitable bid work) obtained during the second quarter. Contribution to net income for the twelve months ended June 30, 2004 was relatively unchanged when compared to the prior twelve-month period. For additional information seeResults of Consolidated Operations.

Rates and Regulatory Proceedings

California General Rate Cases.In March 2004, the CPUC rendered a decision on the general rate cases filed by Southwest in February 2002 for its southern and northern California jurisdictions. The CPUC approved annualized rate increases of $3.6 million in southern California and $3.1 million in northern California, effective May 2003, plus attrition amounts as a result of inflation and safety-related activities beginning in 2004. The CPUC decision also includes attrition allowances through 2006. There were no gas cost disallowances in the CPUC decision.

To mitigate margin volatility due to weather and other usage variations, the CPUC authorized a margin tracker that allows Southwest to record under or over-collected margin in a balancing account for recovery or refund to customers in a subsequent period. The margin recorded in the balancing account is based on the difference between earned and authorized levels.

New billing rates were put in place in mid-April 2004. Through the end of the second quarter, a total of $9.1 million in incremental operating margin has been realized. Southwest was previously authorized by the CPUC to establish a memorandum account to track the impact of the delayed rate relief decision from May 2003 through the effective date of the general rate case. Approximately $3.3 million of the rate relief recorded during 2004 reflects the activity in the memorandum account during 2003.

Nevada General Rate Cases. In March 2004, Southwest filed general rate applications with the PUCN, which included requests for annual increases of $8.6 million for northern Nevada and $18.9 million in southern Nevada. Southwest has requested increased and seasonally adjusted basic service charges to recover fixed costs and a margin-balancing account that would, if approved, mitigate margin volatility due to weather and other usage variations. Hearings were held in July with the PUCN staff and the Bureau of Consumer Protection recommending that the total increase Southwest originally requested be reduced by one-third to two-thirds. The proposed reductions from filed amounts primarily relate to differences in returns on common equity, capital structure and depreciation rates. In addition, the parties did not generally support the usage volatility mitigation proposals. A PUCN decision is expected in the third quarter of 2004. Southwest’s last general rate increase occurred in 2001.

PGA Filings

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

15

As of June 30, 2004 and December 31, 2003, Southwest had the following outstanding PGA balances receivable/(payable) (millions of dollars):

	June 30, 2004		December 31, 2003
Arizona	$	4.0	$	(5.8	)
Northern Nevada		5.1		1.7
Southern Nevada		34.7		5.1
California		7.5		8.2
	$	51.3	$	9.2

Nevada PGA Filings. As a result of increases in gas costs experienced since the last annual PGA filing in June 2003 (in addition to projected continued increases), an out-of-cycle PGA filing was made in December 2003. In May 2004, the PUCN approved a $43.3 million annualized increase in southern Nevada and a $12.1 million increase in northern Nevada. The new rates became effective June 2004.

In June 2004, Southwest made its annual PGA filing with the PUCN. If the PGA filing is approved by the PUCN, rates would increase $16.3 million for customers in southern Nevada and $2.6 million for customers in northern Nevada. Southwest has requested that the rates be effective December 2004. A PUCN decision is expected in the fourth quarter of 2004.

Other Filings

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

The FERC is continuing to examine issues related to the implementation of the full requirements conversion. Parties, including Southwest, have filed petitions for judicial review of the FERC’s orders mandating the conversion.

Management believes that it is difficult to predict the ultimate outcome of the appellate proceedings or the impact of the FERC action on Southwest. Southwest had adequate capacity for its customers’ needs during the 2003/2004 heating season and management believes adequate capacity exists for the 2004/2005 heating season. Additional costs may be incurred to acquire capacity in the future as a result of the FERC order. However, it is anticipated that any additional costs will be collected from customers through the PGA mechanism.

Capital Resources and Liquidity

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

Southwest continues to experience significant customer growth. This growth has required significant capital outlays for new transmission and distribution plant, to keep up with consumer demand. During the twelve-month period ended June 30, 2004, capital expenditures for the natural gas operations segment were $246 million. Approximately 71 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 $114 million of the required capital resources pertaining to these construction expenditures. The remainder was provided from external financing activities. Operating cash flows in the most recent

16

twelve months were negatively impacted by natural gas prices as PGA balances have changed from an over-collection of $34 million at June 30, 2003 to an under-collection of $51.3 million at June 30, 2004. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances.

2004 Construction Expenditures and Financing

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

Southwest estimates construction expenditures during the three-year period ending December 31, 2006 will be approximately $690 million. Of this amount, $233 million are expected to be incurred in 2004. During the three-year period, cash flow from operating activities including the impacts of the Acts (net of dividends) is estimated to fund approximately 80 percent of the gas operations total construction expenditures. The Company expects to raise $50 million to $55 million from its Dividend Reinvestment and Stock Purchase Plan (“DRSPP”). The remaining cash requirements are expected to be provided by other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

In April 2004, the Company entered into a sales agency financing agreement with BNYCMI. Of the $200 million in securities available under the Company’s shelf registration statement, the Company filed a prospectus supplement in May designating an aggregate $60 million as common stock to be issued in at-the-market offerings from time to time with BNYCMI acting as agent. As of June 30, 2004, the Company had issued approximately 313,000 shares (at an average price of $23.23 per share) resulting in proceeds of $7.3 million through this facility.

In July 2004, the Company issued $65 million in Clark County, Nevada IDRBs Series 2004A, due 2034. The net proceeds from the 5.25% tax-exempt bonds will be used to finance construction and improvement of pipeline systems and facilities located in southern Nevada.

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

The rate schedules in all of the service territories of Southwest contain PGA clauses which permit adjustments to rates as the cost of purchased gas changes. The PGA mechanism allows Southwest to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service. On an interim basis, Southwest generally defers over or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At June 30, 2004, the combined balances in PGA accounts totaled an under-collection of $51.3 million. At December 31, 2003, the combined balances in PGA accounts totaled an under-collection of $9.2 million. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances. SeePGA Filingsfor more information on recent regulatory filings.

17

Effective May 2004, the Company obtained a new $250 million three-year credit facility of which $150 million is for working capital purposes (and related outstanding amounts will be designated as short-term debt). Interest rates for the new facility are calculated at either the London Interbank Offering Rate (“LIBOR”) plus an applicable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. The new facility replaces the former $250 million credit facility consisting of a $125 million three-year facility and a $125 million 364-day facility. The Company believes the $150 million designated for working capital purposes is adequate to meet anticipated liquidity needs ($96 million was available at June 30, 2004).

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):

	For the Twelve Months Ended
	June 30, 2004	December 31, 2003
Ratio of earnings to fixed charges	1.82	1.60

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.

Insurance Coverage

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company has been responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers would be responsible for amounts up to the policy limits. For the policy year August 2004 to July 2005, the self-insured retention amount associated with general liability claims increased from $1 million per incident to $1 million per incident plus payment of the first $10 million in aggregate claims above $1 million in the policy year. Management cannot predict the likelihood that any claim will exceed $1 million. Therefore, the impact, if any, this policy change will have on the future results of operations or financial condition of the Company is not determinable.

LNG Lease

The Company leases the liquefied natural gas (“LNG”) facilities and approximately 61 miles of transmission main on its northern Nevada system under a lease that expires in July 2005. The rental payments for the facilities are $3.3 million and $1.7 million for 2004 and 2005, respectively. The Company received a notice of default and demand for indemnification, in June, asserting that it is in default on the lease. The Company has responded to the notice of default certifying that no event of default exists and disputing the scope of the claims. In June 2004, Uzal, LLC (“Uzal”) filed suit in the United States District Court, District of Nevada, alleging breach of the lease and certain related agreements, tortious interference with contract, and tortious interference with prospective economic advantage. Uzal seeks an injunction keeping the Company from accepting any authorization to proceed with the abandonment and expansion proposed in certain FERC applications, an order directing it to abide by its contractual obligations not to affect adversely the residual value of the plant, and damages. The Company intends to vigorously defend this action and a motion to dismiss the entire action has been filed. The ultimate disposition of this proceeding is not presently determinable; however, it is the opinion of management that this litigation will not have a material adverse impact on the Company’s financial position or results of operations.

Forward-Looking Statements

This quarterly report contains statements which constitute “forward-looking statements” within the meaning of the Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this quarterly report are forward-looking statements, including, without limitation,

18

statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, changes in natural gas prices, our ability to recover costs through our PGA mechanism, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, resolution of pending litigation, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition and our ability to raise capital in external financings or through our DRSPP. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing, operations, and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, seeItem 1. Business-Company Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk in the Company’s 2003 Annual Report on 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 provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and benefits of controls must be considered relative to their costs. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Based on the most recent evaluation, as of June 30, 2004, 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 second quarter of 2004 that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.

19

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is named as a defendant in various legal proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that none of this litigation individually or in the aggregate will have a material adverse impact on the Company’s financial position or results of operations.

ITEMS 2-3. None.

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

The Annual Meeting of Shareholders was held on May 6, 2004 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:

(1) Cumulative voting became effective for all shareholders when the intent to cumulatively vote shares was announced at the Annual Meeting of Shareholders. Each shareholder/proxy was entitled to give one nominee for director a number of votes equal to the number of directors to be elected (in this case 11) multiplied by the number of votes to which the shareholder’s shares were normally entitled. A shareholder/proxy could distribute their votes on the same principle among as many of the nominees for director as the shareholder/proxy desired. Withholding votes or voting against a nominee had no legal effect. The 11 nominees that received the highest allocation of affirmative votes were elected as indicated below.

               Name                      Votes For         Elected   

George C. Biehl      29,125,961       Yes

Thomas E. Chestnut      29,125,961       Yes

Manuel J. Cortez      29,125,961       Yes

Richard M. Gardner      29,125,961       Yes

LeRoy C. Hanneman, Jr.      29,125,961       Yes

Thomas Y. Hartley      29,125,961       Yes

James J. Kropid      29,125,961       Yes

Michael O. Maffie      29,125,961       Yes

Michael J. Melarkey      26,850,000       Yes

Carolyn M. Sparks      29,125,961       Yes

Terrence L. Wright      29,125,961       Yes

Salvatore J. Zizza        4,462,831       No

(2) The proposal to ratify the selection of PricewaterhouseCoopers LLP as independent accountants for the Company was approved. Shareholders voted 29,644,997 shares in favor, 330,599 against, and 276,055 abstentions.

(3) The proposal to ratify the Amended and Restated Management Incentive Plan of the Company was approved. Shareholders voted 19,943,657 shares in favor, 5,052,836 against, and 472,309 abstentions.

ITEM 5. None.

20

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report on Form 10-Q:

Exhibit 3(ii) - -  Amended Bylaws of Southwest Gas Corporation.

Exhibit 10 - -  $250 Million Three-Year Credit Facility.

Exhibit 12 - -  Computation of Ratios of Earnings to Fixed Charges.

Exhibit 31 - -  Section 302 Certifications.

Exhibit 32 - -  Section 906 Certifications.

(b) Reports on Form 8-K:

On May 17, 2004, the Company filed exhibits associated with the April 2004 sales agency financing agreement with BNY Capital Markets, Inc.

On July 28, 2004, the Company announced that Jeffrey W. Shaw, Chief Executive Officer, was elected to the Board of Directors.

On July 29, 2004, the Company reported summary financial information for the quarter, six, and twelve months ended June 30, 2004, pursuant to Item 12 of Form 8-K.

21

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.

Date: August 6, 2004 Southwest Gas Corporation
(Registrant)


/s/ Roy R. Centrella
Roy R. Centrella
Vice President/Controller and Chief Accounting Officer

22