Southwest Gas 10-Q 2004 Q3 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 September 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, 36,059,272 shares as of November 2, 2004.

PART I — FINANCIAL INFORMATION

ITEM 1.           FINANCIAL STATEMENTS

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

	SEPTEMBER 30, 2004			DECEMBER 31, 2003
	(Unaudited)
ASSETS
Utility plant:
Gas plant	$	3,200,737		$	3,035,969
Less: accumulated depreciation		(966,805	)		(896,309	)
Acquisition adjustments, net		2,398			2,533
Construction work in progress		27,133			33,543
Net utility plant		2,263,463			2,175,736
Other property and investments		98,184			87,443
Current assets:
Cash and cash equivalents		10,179			17,183
Accounts receivable, net of allowances		87,306			126,783
Accrued utility revenue		29,700			66,700
Deferred income taxes		2,636			6,914
Deferred purchased gas costs		54,424			9,151
Prepaids and other current assets		65,010			54,356
Total current assets		249,255			281,087
Deferred charges and other assets		67,169			63,840
Total assets	$	2,678,071		$	2,608,106
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 45,000,000 shares; issued
and outstanding - 35,925,055 and 34,232,098 shares)	$	37,555		$	35,862
Additional paid-in capital		545,461			510,521
Retained earnings		78,646			84,084
Total equity		661,662			630,467
Subordinated debentures due to Southwest Gas Capital II		100,000			100,000
Long-term debt, less current maturities		1,164,650			1,121,164
Total capitalization		1,926,312			1,851,631
Current liabilities:
Current maturities of long-term debt		30,905			6,435
Short-term debt		38,000			52,000
Accounts payable		67,380			110,114
Customer deposits		47,706			44,290
Accrued general taxes		38,384			32,466
Accrued interest		20,186			19,665
Other current liabilities		48,868			45,442
Total current liabilities		291,429			310,412
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		281,317			277,332
Taxes payable		3,817			6,661
Accumulated removal costs		79,000			68,000
Other deferred credits		96,196			94,070
Total deferred income taxes and other credits		460,330			446,063
Total capitalization and liabilities	$	2,678,071		$	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 SEPTEMBER 30,						NINE MONTHS ENDED SEPTEMBER 30,						TWELVE MONTHS ENDED SEPTEMBER 30,
	2004			2003			2004			2003			2004			2003
Operating revenues:
Gas operating revenues	$	206,459		$	167,827		$	866,999		$	733,192		$	1,168,160		$	1,014,275
Construction revenues		58,008			52,335			149,565			146,107			200,109			201,446
Total operating revenues		264,467			220,162			1,016,564			879,299			1,368,269			1,215,721
Operating expenses:
Net cost of gas sold		102,978			72,398			450,690			358,908			574,285			472,942
Operations and maintenance		74,289			66,012			214,957			196,502			285,317			264,431
Depreciation and amortization		36,725			34,345			108,867			101,183			144,123			135,341
Taxes other than income taxes		9,528			9,075			29,026			27,530			37,406			35,613
Construction expenses		49,964			46,617			130,285			129,358			175,112			179,101
Total operating expenses		273,484			228,447			933,825			813,481			1,216,243			1,087,428
Operating income (loss)		(9,017	)		(8,285	)		82,739			65,818			152,026			128,293
Other income and (expenses):
Net interest deductions		(20,079	)		(18,935	)		(57,622	)		(58,709	)		(76,019	)		(78,970	)
Net interest deductions on subordinated debentures		(1,930	)		(750	)		(5,791	)		(750	)		(7,721	)		(750	)
Preferred securities distributions		--			(1,442	)		--			(4,180	)		--			(5,549	)
Other income (deductions)		2,076			978			3,252			2,575			4,922			17,588
Total other income and (expenses)		(19,933	)		(20,149	)		(60,161	)		(61,064	)		(78,818	)		(67,681	)
Income (loss) before income taxes		(28,950	)		(28,434	)		22,578			4,754			73,208			60,612
Income tax expense (benefit)		(12,597	)		(11,027	)		6,249			726			22,405			18,769
Net income (loss)	$	(16,353	)	$	(17,407	)	$	16,329		$	4,028		$	50,803		$	41,843
Basic earnings (loss) per share	$	(0.46	)	$	(0.51	)	$	0.47		$	0.12		$	1.47		$	1.25
Diluted earnings (loss) per share	$	(0.46	)	$	(0.51	)	$	0.47		$	0.12		$	1.45		$	1.24
Dividends paid per share	$	0.205		$	0.205		$	0.615		$	0.615		$	0.82		$	0.82
Average number of common shares outstanding		35,412			33,852			34,857			33,653			34,661			33,545
Average shares outstanding (assuming dilution)		--			--			35,116			33,911			34,942			33,816

        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)

	NINE MONTHS ENDED SEPTEMBER 30,						TWELVE MONTHS ENDED SEPTEMBER 30,
	2004			2003			2004			2003
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	16,329		$	4,028		$	50,803		$	41,843
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization		108,867			101,183			144,123			135,341
Deferred income taxes		8,263			16,305			36,102			1,118
Changes in current assets and liabilities:
Accounts receivable, net of allowances		39,477			57,945			(14,052	)		13,220
Accrued utility revenue		37,000			37,073			(1,700	)		1,072
Deferred purchased gas costs		(45,273	)		(4,288	)		(76,966	)		(6,098	)
Accounts payable		(42,734	)		(34,192	)		13,044			2,477
Accrued taxes		3,074			(10,982	)		13,670			20,020
Other current assets and liabilities		(3,749	)		85			(2,142	)		10,603
Other		(4,880	)		265			(6,154	)		(3,975	)
Net cash provided by operating activities		116,374			167,422			156,728			215,621
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(195,360	)		(163,899	)		(272,132	)		(249,168	)
Other		3,336			3,685			(18,564	)		6,386
Net cash used in investing activities		(192,024	)		(160,214	)		(290,696	)		(242,782	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		36,633			13,675			44,248			17,075
Dividends paid		(21,420	)		(20,698	)		(28,407	)		(27,507	)
Issuance of subordinated debentures, net		--			96,393			(81	)		96,393
Issuance of long-term debt, net		72,759			161,208			71,548			158,496
Retirement of long-term debt, net		(5,326	)		(137,576	)		(7,763	)		(139,931	)
Retirement of preferred securities		--			(60,000	)		--			(60,000	)
Temporary changes in long-term debt		--			(19,814	)		19,814			(19,814	)
Change in short-term debt		(14,000	)		(53,000	)		38,000			--
Net cash provided by (used in) financing activities		68,646			(19,812	)		137,359			24,712
Change in cash and cash equivalents		(7,004	)		(12,604	)		3,391			(2,449	)
Cash at beginning of period		17,183			19,392			6,788			9,237
Cash at end of period	$	10,179		$	6,788		$	10,179		$	6,788
Supplemental information:
Interest paid, net of amounts capitalized	$	60,497		$	59,460		$	79,598		$	77,625
Income taxes paid (received), net		179			(956	)		(25,598	)		(606	)

        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 interim 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 revenues 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. These consolidated financial statements should 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 and second quarter 2004 Form 10-Qs.

Intercompany Transactions. NPL recognizes revenues generated from contracts with Southwest (see Note 2 below). Accounts receivable for these services were $5.8 million at September 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 in Note 9 — Employee Benefits in the 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 September 30,
	Three Months						Nine Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Net income (loss), as reported	$	(16,353	)	$	(17,407	)	$	16,329		$	4,028		$	50,803		$	41,843
Add:
Stock-based employee
compensation expense included
in reported net income (loss),
net of related tax benefits		365			442			1,253			1,354			2,337			1,799
Deduct:
Total stock-based employee
compensation expense
determined under fair value
based method for all awards,
net of related tax benefits		(445	)		(560	)		(1,651	)		(1,722	)		(2,849	)		(2,234	)
Pro forma net income (loss)	$	(16,433	)	$	(17,525	)	$	15,931		$	3,660		$	50,291		$	41,408
Earnings (loss) per share:
Basic - as reported	$	(0.46	)	$	(0.51	)	$	0.47		$	0.12		$	1.47		$	1.25
Basic - pro forma		(0.46	)		(0.52	)		0.46			0.11			1.45			1.23
Diluted - as reported		(0.46	)		(0.51	)		0.47			0.12			1.45			1.24
Diluted - pro forma		(0.46	)		(0.52	)		0.45			0.11			1.44			1.22

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. In the second quarter of 2004, 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 September 30,
	Three Months						Nine Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Service cost	$	3,448		$	3,067		$	10,343		$	9,201		$	13,409		$	12,098
Interest cost		5,915			5,311			17,745			15,933			23,055			21,075
Expected return on plan assets		(7,017	)		(6,805	)		(21,051	)		(20,414	)		(27,854	)		(27,209	)
Amortization of prior service costs		13			14			40			42			55			56
Amortization of unrecognized
transition obligation		--			199			--			597			198			807
Amortization of net (gain) loss		--			--			--			--			--			(53	)
Net periodic benefit cost	$	2,359		$	1,786		$	7,077		$	5,359		$	8,863		$	6,774

	PBOP
	Period Ended September 30,
	Three Months						Nine Months						Twelve Months
	2004			2003			2004			2003			2004			2003
Service cost	$	181		$	169		$	542		$	507		$	710		$	656
Interest cost		545			523			1,636			1,571			2,160			2,069
Expected return on plan assets		(357	)		(301	)		(1,071	)		(904	)		(1,372	)		(1,200	)
Amortization of prior service costs		--			--			--			--			--			--
Amortization of unrecognized
transition obligation		217			217			651			651			867			867
Amortization of net (gain) loss		53			64			159			192			224			192
Net periodic benefit cost	$	639		$	672		$	1,917		$	2,017		$	2,589		$	2,584

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 September 30, 2004
Revenues from external customers	$	206,459		$	43,423	$	249,882
Intersegment revenues		--			14,585		14,585
Total	$	206,459		$	58,008	$	264,467
Segment net income (loss)	$	(18,954	)	$	2,601	$	(16,353	)
Three months ended September 30, 2003
Revenues from external customers	$	167,827		$	38,974	$	206,801
Intersegment revenues		--			13,361		13,361
Total	$	167,827		$	52,335	$	220,162
Segment net income (loss)	$	(18,590	)	$	1,183	$	(17,407	)
Nine months ended September 30, 2004
Revenues from external customers	$	866,999		$	106,445	$	973,444
Intersegment revenues		--			43,120		43,120
Total	$	866,999		$	149,565	$	1,016,564
Segment net income	$	10,992		$	5,337	$	16,329
Nine months ended September 30, 2003
Revenues from external customers	$	733,192		$	103,466	$	836,658
Intersegment revenues		--			42,641		42,641
Total	$	733,192		$	146,107	$	879,299
Segment net income	$	991		$	3,037	$	4,028
Twelve months ended September 30, 2004
Revenues from external customers	$	1,168,160		$	140,696	$	1,308,856
Intersegment revenues		--			59,413		59,413
Total	$	1,168,160		$	200,109	$	1,368,269
Segment net income	$	44,212		$	6,591	$	50,803
Twelve months ended September 30, 2003
Revenues from external customers	$	1,014,275		$	139,412	$	1,153,687
Intersegment revenues		--			62,034		62,034
Total	$	1,014,275		$	201,446	$	1,215,721
Segment net income	$	37,665		$	4,178	$	41,843

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. At September 30, 2004, $138 million was outstanding under the facility.

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 were used to finance construction expenditures in southern Nevada.

In September 2004, the Company remarketed the $20 million 3.35% 2003 Series D IDRBs, due 2038, at a rate of 5.25%. The original 3.35% interest rate was an 18-month rate which was required to be remarketed by September 2004.

Note 4 – Common Stock

During 2004, the Company has issued approximately 1.7 million additional shares of common stock through its Equity Shelf Program, Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), Employee Investment Plan, Management Incentive Plan, and Stock Incentive Plan. Of this activity, approximately 860,000 shares were issued in at-the-market offerings through the Equity Shelf Program (at an average price of $23.39 per share).

In August 2004, the Company registered 1 million additional shares of common stock with the SEC for issuance under the DRSPP.

Note 5 – Avista Agreement

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 in this region. 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 Calfornia 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.

Note 6 – Subsequent Events

In October 2004, the Company issued $75 million in Clark County, Nevada 5% Series 2004B Industrial Development Refunding Revenue Bonds (“IDRRBs”). The Series 2004B IDRRBs were issued at a discount of 0.625%. The proceeds of the new IDRRBs will be used to refinance $75 million in 6.5% 1993 Series A IDRBs due 2033. The redemption of the 1993 Series A IDRBs will occur on December 1, 2004 and includes an early redemption premium of 1% ($750,000).

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 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 1,579,000 residential, commercial, industrial, and other customers, of which 55 percent are located in Arizona, 36 percent are in Nevada, and 9 percent are in California. During the twelve months ended September 30, 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, 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 September 30,
	Three Months						Nine Months				Twelve Months
	2004			2003			2004		2003		2004		2003
Contribution to net income (loss)
(Thousands of dollars)
Natural gas operations	$	(18,954	)	$	(18,590	)	$	10,992	$	991	$	44,212	$	37,665
Construction services		2,601			1,183			5,337		3,037		6,591		4,178
Net income (loss)	$	(16,353	)	$	(17,407	)	$	16,329	$	4,028	$	50,803	$	41,843
Basic earnings (loss) per share
Natural gas operations	$	(0.53	)	$	(0.55	)	$	0.32	$	0.03	$	1.28	$	1.12
Construction services		0.07			0.04			0.15		0.09		0.19		0.13
Consolidated	$	(0.46	)	$	(0.51	)	$	0.47	$	0.12	$	1.47	$	1.25

See separate discussions atResults of Natural Gas Operations and Results of Construction Services.

As reflected in the table above, the natural gas operations segment accounted for an average of 88 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 gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The three principal factors affecting operating margin are general rate relief, weather, and customer growth.

10

In connection with Southwest’s general rate applications filed in March 2004 with the Public Utilities Commission of Nevada (“PUCN”), in August 2004, the PUCN approved a total annual increase of $13.7 million for Southwest’s southern and northern Nevada service territories effective September 2004. The rate order included certain rate design improvements to mitigate weather variations. (See the section onRates and Regulatory Proceedings for additional information.)

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. Year-to-date weather for 2004 was warmer than normal as were temperatures in the corresponding period of 2003 with a net increase in weather-related margin between periods of $16 million. During the current period, operating margin was negatively impacted by $9 million, while the negative impact in the prior period was $25 million.

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 88,000 more customers during the third quarter of 2004 (including 9,000 from an acquisition) than in the third 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. However, growth, coupled with external factors, is causing operating expenses to trend upward corresponding to the customer growth rate and inflation. Operations and maintenance expenses for the first nine months of 2004 reflect this trend. Primary factors responsible for this trend include insurance, regulatory costs, employee-related costs, and costs to develop energy efficient technology.

Customer growth requires significant capital outlays for new transmission and distribution plant. Necessary financing of continued construction has occurred during 2004. In July 2004, the Company issued $65 million in Clark County, Nevada IDRBs. The net proceeds from the 5.25% tax-exempt bonds were used to finance construction expenditures in southern Nevada. The Company also issued 1.7 million shares of common stock through its various stock plans receiving $36.6 million in net proceeds in 2004. (See the section on2004 Construction Expenditures and Financing for additional information.)

In July 2004, the Company announced an agreement with Avista Corporation to purchase Avista’s natural gas distribution properties in South Lake Tahoe, California. Avista serves approximately 18,000 customers in this region. The cash purchase price for the properties is $15 million, subject to closing adjustments. (See the section on Asset Purchases for additional information.)

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Results of Natural Gas Operations

Quarterly Analysis

	Three Months Ended September 30,
	2004			2003
	(Thousands of dollars)
Gas operating revenues	$	206,459		$	167,827
Net cost of gas sold		102,978			72,398
Operating margin		103,481			95,429
Operations and maintenance expense		74,289			66,012
Depreciation and amortization		32,844			30,517
Taxes other than income taxes		9,528			9,075
Operating income (loss)		(13,180	)		(10,175	)
Other income (expense)		1,566			658
Net interest deductions		19,814			18,779
Net interest deductions on subordinated debentures		1,930			750
Preferred securities distributions		--			1,442
Income (loss) before income taxes		(33,358	)		(30,488	)
Income tax expense (benefit)		(14,404	)		(11,898	)
Contribution to consolidated net income (loss)	$	(18,954	)	$	(18,590	)

Contribution from natural gas operations decreased $364,000 in the third 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 and the recognition of a nonrecurring income tax benefit.

Operating margin increased approximately $8 million, or eight percent, in the third quarter of 2004 compared to the third quarter of 2003. Customer growth contributed an incremental $5 million in operating margin during the quarter and rate relief in California and Nevada added $3 million. During the last 12 months, the Company added a record 79,000 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 $8.3 million, or 13 percent, reflecting general increases in labor and maintenance costs along with incremental operating expenses associated with providing service to a rapidly growing customer base. Additional factors include BMG-related operating expenses, insurance, employee-related costs, and costs to develop energy efficient technology.

Depreciation expense and general taxes increased $2.8 million, or seven percent, as a result of construction activities. Average gas plant in service increased $244 million, or eight percent, as compared to the third 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.

Net financing costs rose $773,000 between periods due to an increase in average debt outstanding to help finance growth, partially offset by 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.

Income tax expense in the current period includes a $1.6 million benefit based on an analysis of current and deferred taxes following completion of general rate cases and the closure of federal tax year 2000.

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Nine-Month Analysis

	Nine Months Ended September 30,
	2004		2003
	(Thousands of dollars)
Gas operating revenues	$	866,999	$	733,192
Net cost of gas sold		450,690		358,908
Operating margin		416,309		374,284
Operations and maintenance expense		214,957		196,502
Depreciation and amortization		97,396		89,372
Taxes other than income taxes		29,026		27,530
Operating income		74,930		60,880
Other income (expense)		1,627		1,509
Net interest deductions		57,122		57,991
Net interest deductions on subordinated debentures		5,791		750
Preferred securities distributions		--		4,180
Income (loss) before income taxes		13,644		(532	)
Income tax expense (benefit)		2,652		(1,523	)
Contribution to consolidated net income	$	10,992	$	991

Contribution from natural gas operations increased $10 million in the first nine 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 $42 million, or 11 percent, in the first nine months of 2004 compared to the first nine 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, principally in California, added $12 million in margin and customer growth contributed an incremental $14 million.

Operations and maintenance expense increased $18.5 million, or nine percent, reflecting general increases in labor and maintenance costs along with incremental operating expenses associated with providing service to a growing customer base. Additional factors include BMG-related operating expenses, insurance, employee-related costs, and costs to develop energy efficient technology.

Depreciation expense and general taxes increased $9.5 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 first nine 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.

Income tax expense in the current period includes a $1.6 million benefit based on an analysis of current and deferred taxes following completion of general rate cases and the closure of federal tax year 2000.

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Twelve-Month Analysis

	Twelve Months Ended September 30,
	2004		2003
	(Thousands of dollars)
Gas operating revenues	$	1,168,160	$	1,014,275
Net cost of gas sold		574,285		472,942
Operating margin		593,875		541,333
Operations and maintenance expense		285,317		264,431
Depreciation and amortization		128,815		119,567
Taxes other than income taxes		37,406		35,613
Operating income		142,337		121,722
Other income (expense)		3,073		16,344
Net interest deductions		75,382		77,949
Net interest deductions on subordinated debentures		7,721		750
Preferred securities distributions		--		5,549
Income before income taxes		62,307		53,818
Income tax expense		18,095		16,153
Contribution to consolidated net income	$	44,212	$	37,665

Contribution to consolidated net income increased $6.5 million in the current twelve-month period compared to the same period a year ago. The improvement in contribution resulted from higher operating margin, partially offset by increased operating costs and a decline in other income.

Operating margin increased $53 million, or ten 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 $21 million, while rate relief, principally in California, added $12 million.

Operations and maintenance expense increased $20.9 million, or eight percent, reflecting general increases in labor and maintenance costs and incremental operating expenses associated with providing service to a steadily growing customer base. Additional factors include BMG-related operating expenses, insurance, employee-related costs, and costs to develop energy efficient technology.

Depreciation expense and general taxes increased $11 million, or seven percent, as a result of additional plant in service. Average gas plant in service for the current twelve-month period increased $249 million, or nine percent, compared to the corresponding period a year ago. This was attributable to the upgrade of existing operating facilities, the expansion of the system to accommodate continued customer growth, and the BMG system acquisition costs.

Other income declined $13.3 million between periods. The prior period reflects income of $14.6 million associated with the timing of merger-related insurance recoveries, net of costs. The current period includes a $1.8 million improvement in interest income primarily associated with the unrecovered balance of deferred purchased gas costs.

Net financing costs decreased $1.1 million, or one percent, primarily due to interest savings generated from the refinancing of IDRBs and preferred securities instruments, partially offset by costs associated with increased average debt outstanding.

Income tax expense in the current period includes a $1.6 million benefit, recognized in the third quarter of 2004, and $2 million of income tax benefits, recognized in the fourth quarter of 2003, associated with plant-related items. The prior twelve-month 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.

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Results of Construction Services

Construction services contribution to net income for the three months ended September 30, 2004 increased $1.4 million when compared to the corresponding period in 2003. The increase primarily reflects the unfavorable settlement of a $1.3 million insurance claim in the third quarter of 2003. Contribution to net income for the nine months and twelve months ended September 30, 2004 increased $2.3 million and $2.4 million, respectively, when compared to the same periods ended September 30, 2003. The increases were primarily due to an improvement in the number of profitable bid jobs, and a favorable equipment resale market in the current periods, in addition to the unfavorable insurance settlement in the third quarter of 2003. 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 third quarter, a total of $10.6 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 for 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 requested increased and seasonally adjusted basic service charges to recover fixed costs and a margin-balancing account to 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 related to differences in returns on common equity, capital structure and depreciation rates.

In August 2004, the PUCN approved annualized rate increases of $6.4 million for northern Nevada and $7.3 million in southern Nevada effective September 2004. The order did not include a margin balancing account, but approved certain rate design improvements to mitigate weather variations. The monthly basic service charge was increased by $0.50 per residential customer and declining block rates were implemented. In addition, the PUCN ordered the Company to outline a plan to increase summer usage and file a weather normalization plan to address margin volatility issues with its next general rate case.

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.

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

	September 30, 2004		December 31, 2003
Arizona	$	4.5	$	(5.8	)
Northern Nevada		7.6		1.7
Southern Nevada		33.9		5.1
California		8.4		8.2
	$	54.4	$	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 were effective June 2004.

In June 2004, Southwest made its annual PGA filings with the PUCN. If the PGA filings are 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 made effective December 2004. A PUCN decision is expected in the fourth quarter of 2004.

In a separate action, the PUCN issued an order in October 2004 instructing Southwest to eliminate the PGA provisions in its tariff and instead account for gas costs as provided under the deferred energy provisions of the Nevada Administrative Code. These provisions result in little difference in the method used to account for or report purchased gas costs, including the ability of the Company to defer over or under collections of gas costs to balancing accounts. However, Southwest intends to file comments with the PUCN during November to clarify the requirements. The changes become effective at the time Southwest makes its next gas cost adjustment filing.

Other Filings

LNG Facilities. The Company leases a liquefied natural gas (“LNG”) facility and approximately 61 miles of transmission main on its northern Nevada system under a lease that expires in July 2005. These storage and transmission facilities provide peaking capabilities during high demand months. Negotiations to purchase the facilities were begun several years ago and preparations were also being made to provide alternatives to the leased facilities to be in service by July 2005 in the event that a purchase agreement could not be consummated.

In May 2004, Paiute Pipeline Company (“Paiute”), an interstate pipeline subsidiary of Southwest Gas, filed an application with the Federal Energy Regulatory Commission (“FERC”) to abandon the leased facilities and to construct a compressor station to replace a portion of the transmission system capacity. Tuscarora Gas Transmission Company (“Tuscarora”) also made a filing with the FERC proposing to expand its system to provide additional service to the customers whose LNG service was to be terminated.

In June 2004, the Company received a notice of default and demand for indemnification asserting that it was in default on the lease from Uzal, LLC (“Uzal”), the owner of the facilities. The Company responded to the notice of default certifying that no event of default exists and disputing the scope of the claims. In June 2004, 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. In July 2004, Uzal filed an application with the FERC seeking authorization to provide storage and transportation service from the LNG facilities.

In October 2004, the Company and Uzal reached an agreement to resolve their dispute. Subject to securing regulatory approval, the litigation will be dismissed and Paiute will purchase the LNG facilities and associated transmission main for approximately $22 million, and continue to provide natural gas storage service in northern California and northern Nevada.

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In addition to the Paiute-Uzal Settlement, Paiute and Southwest are parties to a Joint Parties Settlement filed with the FERC. Other members of the Joint Parties Settlement include Avista Corporation, Public Service Resources Corporation, Sierra Pacific Power Company, Tuscarora, and Uzal.

The Joint Parties Settlement is predicated upon Paiute’s acquisition of the LNG facilities pursuant to the Paiute-Uzal Settlement. The Joint Parties Settlement, once it receives regulatory approval and the required closing on the purchase of the LNG facilities occurs, will completely resolve five pending, contested FERC proceedings, as well as two related court cases.

FERC approval of the Joint Parties Settlement would result in the issuance of a Certificate of Public Convenience and Necessity to Paiute authorizing it to acquire and operate the LNG facilities, as well as providing Paiute with the authority to provide long-term LNG storage services to its customers under new storage service agreements. FERC approval would determine that the purchase price of the LNG facilities and the allocation of the purchase price between the storage and transmission functions is reasonable for both rate and accounting purposes. Finally, Paiute would withdraw its application related to the abandonment of the leased facilities and construction of a compressor station. In addition, Tuscarora would withdraw its application to construct its proposed 2005 expansion project, and Uzal would withdraw its application seeking authorization to provide storage and transportation service from the LNG facilities. A FERC decision on the Joint Parties Settlement is expected in the fourth quarter of 2004.

El Paso Transportation System. Over the past several years, 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. Management believes adequate capacity exists for the upcoming 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 September 30, 2004, capital expenditures for the natural gas operations segment were $248 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 $107 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 twelve months were negatively impacted by natural gas prices as PGA balances have changed from an over-collection of $22.4 million at September 30, 2003 to an under-collection of $54.4 million at September 30, 2004. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances.

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Asset Purchases

In July 2004, the Company announced an agreement with Avista to purchase Avista’s natural gas distribution properties in South Lake Tahoe, California. Avista serves approximately 18,000 customers in this region. 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 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. The purchase price will be financed using existing credit facilities.

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 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 BNY Capital Markets, Inc. (“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 (“Equity Shelf Program”) from time to time with BNYCMI acting as agent.

During 2004, the Company issued approximately 1.7 million additional shares through its DRSPP, Employee Investment Plan, Management Incentive Plan, Stock Incentive Plan, and Equity Shelf Program.

Of this activity, approximately 860,000 shares were issued in at-the-market offerings through the Equity Shelf Program with gross proceeds of $20.1 million, agent commissions of $201,000, and net proceeds of $19.9 million. For the quarter ended September 30, 2004, approximately 548,000 shares were issued with gross proceeds of $12.9 million, agent commissions of $129,000, and net proceeds of $12.7 million.

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 were used to finance construction and improvement of pipeline systems and facilities located in southern Nevada.

In August 2004, the Company registered 1 million additional shares of common stock with the SEC for issuance under the DRSPP.

In September 2004, the Company remarketed the $20 million 3.35% 2003 Series D IDRBs, due 2038, at a rate of 5.25%. The original 3.35% interest rate was an 18-month rate which was required to be remarketed by September 2004.

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In October 2004, the Company issued $75 million in Clark County, Nevada 5% Series 2004B IDRRBs due 2033. The Series 2004B IDRRBs were issued at a discount of 0.625%. The proceeds of the new IDRRBs will be used to refinance $75 million in 6.5% 1993 Series A IDRBs due 2033. The redemption of the 1993 Series A IDRBs will occur on December 1, 2004 and includes an early redemption premium of 1% ($750,000).

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 September 30, 2004, the combined balances in PGA accounts totaled an under-collection of $54.4 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.

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 ($112 million was available at September 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
	September 30, 2004		December 31, 2003
Ratio of earnings to fixed charges		1.80		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

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$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.

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, 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

See Item 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.

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

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 2-5.    None.

ITEM 6.           EXHIBITS

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

Exhibit 4	- Indenture for $65 million Clark County IDRBs.
Exhibit 10	- Form of Executive Option Grant under 2002 Stock Incentive Plan.
Exhibit 12	- Computation of Ratios of Earnings to Fixed Charges.
Exhibit 31	- Section 302 Certifications.
Exhibit 32	- Section 906 Certifications.

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SIGNATURES

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.

Southwest Gas Corporation
——————————————————————
(Registrant)

Date: November 8, 2004

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

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