Edgar Filing: SOUTHWEST GAS CORP

Form 10-Q

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, 2011

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION

(Exact name of registrant as specified in its charter)


California		88-0085720
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

5241 Spring Mountain Road
Post Office Box 98510
Las Vegas, Nevada		89193-8510
(Address of principal executive offices)		(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes X No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer X Accelerated filer Non-accelerated filer Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes No X

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, 45,911,371 shares as of October 28, 2011.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

(Unaudited)


	SEPTEMBER 30, 2011			DECEMBER 31, 2010
ASSETS
Utility plant:
Gas plant	$	4,667,840		$	4,569,105
Less: accumulated depreciation		(1,614,486	)		(1,535,429	)
Acquisition adjustments, net		1,136			1,271
Construction work in progress		106,389			37,489

Net utility plant		3,160,879			3,072,436

Other property and investments		178,546			134,648

Restricted cash		37,783			37,781

Current assets:
Cash and cash equivalents		19,836			116,096
Accounts receivable, net of allowances		119,576			147,605
Accrued utility revenue		31,300			64,400
Income taxes receivable, net		7,688			21,514
Deferred income taxes		24,640			8,046
Deferred purchased gas costs		-			356
Prepaids and other current assets		83,604			87,877

Total current assets		286,644			445,894

Deferred charges and other assets		275,385			293,434

Total assets	$	3,939,237		$	3,984,193


CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 45,901,110 and 45,599,036 shares)	$	47,531		$	47,229
Additional paid-in capital		817,035			807,885
Accumulated other comprehensive income (loss), net		(39,437	)		(30,784	)
Retained earnings		363,125			343,131

Total Southwest Gas Corporation equity		1,188,254			1,167,461
Noncontrolling interest		(808	)		(465	)

Total equity		1,187,446			1,166,996
Long-term debt, less current maturities		936,857			1,124,681

Total capitalization		2,124,303			2,291,677

Current liabilities:
Current maturities of long-term debt		221,102			75,080
Accounts payable		99,599			165,536
Customer deposits		84,459			86,891
Accrued general taxes		40,313			40,438
Accrued interest		19,553			20,162
Deferred purchased gas costs		93,652			123,344
Other current liabilities		122,985			85,510

Total current liabilities		681,663			596,961

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		505,409			466,628
Taxes payable		929			1,234
Accumulated removal costs		227,000			211,000
Other deferred credits		399,933			416,693

Total deferred income taxes and other credits		1,133,271			1,095,555

Total capitalization and liabilities	$	3,939,237		$	3,984,193

The accompanying notes are an integral part of these statements.

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED 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,
	2011			2010			2011			2010			2011			2010
Operating revenues:
Gas operating revenues	$	195,647		$	213,893		$	1,022,914		$	1,133,671		$	1,401,150		$	1,561,644
Construction revenues		156,945			93,790			346,623			228,588			436,499			299,420

Total operating revenues		352,592			307,683			1,369,537			1,362,259			1,837,649			1,861,064

Operating expenses:
Net cost of gas sold		67,165			81,303			468,026			581,294			622,907			779,911
Operations and maintenance		89,087			86,746			268,745			260,386			363,302			352,047
Depreciation and amortization		50,341			47,582			148,618			142,438			196,643			189,368
Taxes other than income taxes		10,585			10,006			30,750			29,388			40,231			38,826
Construction expenses		134,161			81,862			305,242			202,806			380,240			264,510

Total operating expenses		351,339			307,499			1,221,381			1,216,312			1,603,323			1,624,662

Operating income		1,253			184			148,156			145,947			234,326			236,402

Other income and (expenses):
Net interest deductions		(17,307	)		(19,266	)		(52,621	)		(56,444	)		(71,854	)		(75,044	)
Net interest deductions on subordinated debentures		-			-			-			(1,912	)		-			(3,845	)
Other income (deductions)		(8,087	)		6,715			(6,814	)		1,038			(4,002	)		2,964

Total other income and (expenses)		(25,394	)		(12,551	)		(59,435	)		(57,318	)		(75,856	)		(75,925	)

Income (loss) before income taxes		(24,141	)		(12,367	)		88,721			88,629			158,470			160,477
Income tax expense (benefit)		(8,394	)		(7,403	)		32,101			30,126			56,900			55,946

Net income (loss)		(15,747	)		(4,964	)		56,620			58,503			101,570			104,531
Net income (loss) attributable to noncontrolling interest		(106	)		(141	)		(343	)		(389	)		(378	)		(753	)

Net income (loss) attributable to Southwest Gas Corporation	$	(15,641	)	$	(4,823	)	$	56,963		$	58,892		$	101,948		$	105,284


Basic earnings (loss) per share	$	(0.34	)	$	(0.11	)	$	1.24		$	1.30		$	2.23		$	2.33

Diluted earnings (loss) per share	$	(0.34	)	$	(0.11	)	$	1.23		$	1.29		$	2.21		$	2.31

Dividends declared per share	$	0.2650		$	0.2500		$	0.7950		$	0.7500		$	1.0450		$	0.9875


Average number of common shares outstanding		45,881			45,447			45,837			45,354			45,766			45,262
Average shares outstanding (assuming dilution)		-			-			46,264			45,756			46,203			45,657

The accompanying notes are an integral part of these statements.

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

(Unaudited)


	NINE MONTHS ENDED SEPTEMBER 30,						TWELVE MONTHS ENDED SEPTEMBER 30,
	2011			2010			2011			2010
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	56,620		$	58,503		$	101,570		$	104,531
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		148,618			142,438			196,643			189,368
Deferred income taxes		27,490			18,946			58,655			24,489
Changes in current assets and liabilities:
Accounts receivable, net of allowances		28,029			73,005			(34,859	)		1,061
Accrued utility revenue		33,100			40,100			300			600
Deferred purchased gas costs		(29,336	)		62,543			(58,866	)		49,651
Accounts payable		(65,937	)		(88,196	)		28,939			3,820
Accrued taxes		13,396			(8,644	)		6,800			29,085
Other current assets and liabilities		14,829			12,807			14,917			1,650
Gains on sale		(1,960	)		(694	)		(2,813	)		(1,766	)
Changes in undistributed stock compensation		4,278			3,863			4,844			4,389
AFUDC and property-related changes		(619	)		(693	)		(871	)		(963	)
Changes in other assets and deferred charges		7,534			(4,938	)		210			(9,365	)
Changes in other liabilities and deferred credits		8,291			6,786			(15,969	)		6,043

Net cash provided by operating activities		244,333			315,826			299,500			402,593


CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(263,626	)		(151,417	)		(327,648	)		(196,864	)
Change in restricted cash		(2	)		11,990			(4	)		(37,779	)
Changes in customer advances		(4,764	)		317			(5,911	)		2,519
Miscellaneous inflows		3,803			2,304			5,574			4,788
Miscellaneous outflows		(2,719	)		(2,800	)		(2,719	)		(2,853	)

Net cash used in investing activities		(267,308	)		(139,606	)		(330,708	)		(230,189	)


CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		4,728			7,475			8,351			11,854
Dividends paid		(35,760	)		(33,455	)		(47,151	)		(44,134	)
Interest rate swap settlement		-			-			(11,691	)		-
Issuance of long-term debt, net		212,812			-			336,772			49,834
Retirement of long-term debt		(275,065	)		(3,301	)		(275,091	)		(3,632	)
Redemption of subordinated debentures		-			(100,000	)		-			(100,000	)
Change in credit facility		20,000			(92,400	)		20,000			(99,300	)

Net cash provided by (used in) financing activities		(73,285	)		(221,681	)		31,190			(185,378	)


Change in cash and cash equivalents		(96,260	)		(45,461	)		(18	)		(12,974	)
Cash and cash equivalents at beginning of period		116,096			65,315			19,854			32,828


Cash and cash equivalents at end of period	$	19,836		$	19,854		$	19,836		$	19,854


Supplemental information:
Interest paid, net of amounts capitalized	$	50,809		$	57,454		$	80,355		$	75,768
Income taxes paid (received)		(13,714	)		18,505			(13,019	)		2,017

The accompanying notes are an integral part of these statements.

Note 1 – Nature of Operations and Basis of Presentation

Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) are composed of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas 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; therefore, results of operations for interim periods are not necessarily indicative of results for a full year. Variability in weather from normal temperatures, primarily in Arizona, can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. NPL 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 condensed 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 (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. The preparation of the condensed 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 expense 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 results for the interim periods, have been made. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the 2010 Annual Report to Shareholders, which is incorporated by reference into the 2010 Form 10-K, and the first and second quarter 2011 reports on Form 10-Q.

Intercompany Transactions. NPL recognizes revenues generated from contracts with Southwest (see Note 3 below). Accounts receivable for these services are presented in the table below (thousands of dollars):


	September 30, 2011		December 31, 2010

Accounts receivable for NPL services	$	13,680	$	8,111

The accounts receivable balance, revenues, and associated profits are included in the condensed consolidated financial statements of the Company and were not eliminated during consolidation in accordance with accounting treatment for rate-regulated entities.

Other Income (Deductions). The following table provides the composition of significant items included in Other income (deductions) on the consolidated statements of income (thousands of dollars):


	Three Months Ended						Nine Months Ended						Twelve Months Ended
	September 30						September 30						September 30
	2011			2010			2011			2010			2011			2010

Change in COLI policies	$	(6,700	)	$	7,750		$	(1,900	)	$	5,620		$	2,250		$	7,223
Interest income		118			49			308			127			375			154
Pipe replacement costs		(1,266	)		(927	)		(3,113	)		(3,918	)		(4,218	)		(4,305	)
Miscellaneous income and (expense)		(239	)		(157	)		(2,109	)		(791	)		(2,409	)		(108	)

Total other income (deductions)	$	(8,087	)	$	6,715		$	(6,814	)	$	1,038		$	(4,002	)	$	2,964

Reflected in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress toward the ultimate death benefits, is also recorded without tax consequences.

Reclassifications. A reclassification between two miscellaneous operating cash flow categories was made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation with no impact on net cash provided by operating activities.

Out-of-Period Adjustment. In September 2011, the Company identified an isolated error in a regulatory deferral mechanism that overstated revenues by $3.7 million for periods prior to the third quarter of 2011. Management concluded the error was not material to any individual prior interim or annual period (or to the current annual period) and, therefore, the error was corrected during the third quarter of 2011. The effect was a decrease in revenues and regulatory assets of $3.7 million, of which $2.9 million pertains to years prior to 2011.

Recently Issued Accounting Standards Updates. In May 2011, the Financial Accounting Standards Board (“FASB”) issued the update “Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.” The amended guidance includes several new fair value disclosure requirements, including, among other things, information about transfers between Level 1 and Level 2 of the fair value hierarchy, enhanced information about valuation techniques and unobservable inputs used in Level 3 fair value measurements, and a narrative description of Level 3 measurements’ sensitivity to changes in unobservable inputs. For the Company, the update is effective prospectively beginning January 2012. The adoption of the update is not expected to significantly impact the disclosures of the Company.

In June 2011, the FASB issued the update “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” which eliminates the current option to report the components of other comprehensive income in the statement of changes in equity. An entity will have the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in one continuous statement of comprehensive income or in two separate but consecutive statements. The update includes no changes to the components that are recognized in net income or other comprehensive income under current U.S. GAAP. The provisions of the update are effective for the Company beginning January 1, 2012 (however, early adoption is permitted). The Company is evaluating the update to determine which presentation option to adopt and the timing of adoption.

In September 2011, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350) Testing Goodwill for Impairment.” The update is intended to simplify how entities test goodwill for impairment. The update permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount (including goodwill) as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. The provisions of the update are effective for the Company beginning January 1, 2012 (however, early adoption is permitted). The adoption of the update is not expected to impact the Company’s financial position or results of operations.

Note 2 – Components of Net Periodic Benefit Cost

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees and a separate unfunded supplemental retirement plan (“SERP”) which is limited to officers. Southwest also provides postretirement benefits other than pensions (“PBOP”) to its qualified retirees for health care, dental, and life insurance.


	Qualified Retirement Plan
	Period Ended September 30,
	Three Months						Nine Months						Twelve Months
	2011			2010			2011			2010			2011			2010
(Thousands of dollars)
Service cost	$	4,431		$	4,233		$	13,293		$	12,699		$	17,526		$	16,546
Interest cost		9,319			8,904			27,957			26,711			36,860			35,343
Expected return on plan assets		(10,028	)		(9,135	)		(30,085	)		(27,404	)		(39,219	)		(36,209	)
Amortization of net loss		3,587			2,620			10,761			7,859			13,380			8,922

Net periodic benefit cost	$	7,309		$	6,622		$	21,926		$	19,865		$	28,547		$	24,602


	SERP
	Period Ended September 30,
	Three Months						Nine Months						Twelve Months
	2011			2010			2011			2010			2011			2010
(Thousands of dollars)
Service cost	$	54		$	93		$	163		$	279		$	256		$	327
Interest cost		441			511			1,324			1,533			1,836			2,050
Amortization of net loss		158			289			473			867			761			1,095

Net periodic benefit cost	$	653		$	893		$	1,960		$	2,679		$	2,853		$	3,472


	PBOP
	Period Ended September 30,
	Three Months						Nine Months						Twelve Months
	2011			2010			2011			2010			2011			2010
(Thousands of dollars)
Service cost	$	215		$	214		$	644		$	642		$	858		$	824
Interest cost		658			623			1,974			1,869			2,596			2,461
Expected return on plan assets		(595	)		(523	)		(1,785	)		(1,569	)		(2,309	)		(1,970	)
Amortization of transition obligation		217			216			650			650			867			867
Amortization of net loss		147			122			442			366			565			475

Net periodic benefit cost	$	642		$	652		$	1,925		$	1,958		$	2,577		$	2,657

Note 3 – Segment Information

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


	Natural Gas Operations			Construction Services		Total
Three months ended September 30, 2011
Revenues from external customers	$	195,647		$	122,696	$	318,343
Intersegment revenues		-			34,249		34,249

Total	$	195,647		$	156,945	$	352,592

Segment net income (loss)	$	(25,566	)	$	9,925	$	(15,641	)


Three months ended September 30, 2010
Revenues from external customers	$	213,893		$	76,125	$	290,018
Intersegment revenues		-			17,665		17,665

Total	$	213,893		$	93,790	$	307,683

Segment net income (loss)	$	(8,813	)	$	3,990	$	(4,823	)


Nine months ended September 30, 2011
Revenues from external customers	$	1,022,914		$	280,635	$	1,303,549
Intersegment revenues		-			65,988		65,988

Total	$	1,022,914		$	346,623	$	1,369,537

Segment net income	$	42,648		$	14,315	$	56,963


Nine months ended September 30, 2010
Revenues from external customers	$	1,133,671		$	183,875	$	1,317,546
Intersegment revenues		-			44,713		44,713

Total	$	1,133,671		$	228,588	$	1,362,259

Segment net income	$	52,403		$	6,489	$	58,892


Twelve months ended September 30, 2011
Revenues from external customers	$	1,401,150		$	353,973	$	1,755,123
Intersegment revenues		-			82,526		82,526

Total	$	1,401,150		$	436,499	$	1,837,649

Segment net income	$	81,627		$	20,321	$	101,948


Twelve months ended September 30, 2010
Revenues from external customers	$	1,561,644		$	241,575	$	1,803,219
Intersegment revenues		-			57,845		57,845

Total	$	1,561,644		$	299,420	$	1,861,064

Segment net income	$	96,074		$	9,210	$	105,284

Note 4 – Derivatives and Fair Value Measurements

Derivatives. In managing its natural gas supply portfolios, Southwest has historically entered into fixed- and variable-price contracts, which qualify as derivatives. Additionally, Southwest utilizes fixed-for-floating swap contracts (“Swaps”) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business and are exempt from fair value reporting. The variable-price contracts have no significant market value. The Swaps are recorded at fair value.

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (historically ranging from 25% to 50%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from October 2011 through October 2012. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):


	September 30, 2011		December 31, 2010

Swaps contracts		11,370		14,207

Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.

Gains (losses) recognized in income for derivatives not designated as hedging instruments:

(Thousands of dollars)


		Three Months Ended						Nine Months Ended						Twelve Months Ended
Instrument	Location of Gain or (Loss) Recognized in Income on Derivative	September 30						September 30						September 30
Instrument		2011			2010			2011			2010			2011			2010

Swaps	Net cost of gas sold	$	(7,570	)	$	(12,046	)	$	(9,539	)	$	(30,013	)	$	(7,216	)	$	(33,994	)
Swaps	Net cost of gas sold		7,570	^*		12,046	^*		9,539	^*		30,013	^*		7,216	^*		33,994	^*

Total		$	-		$	-		$	-		$	-		$	-		$	-

^* Represents the impact of regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities.

In January 2010, Southwest entered into two forward-starting interest rate swaps (“FSIRS”) to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt that matured in February 2011 and $200 million maturing in May 2012. The counterparties to each agreement are four major banking institutions. The first FSIRS was a designated cash flow hedge and terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. The terms of the second FSIRS are as follows:


Notional amount		$100 million
Fixed rate to be paid by Southwest		4.78%
Mandatory termination date (on or before)		March 20, 2012

Southwest previously designated the second FSIRS agreement as a cash flow hedge of forecasted future interest payments. At inception of the hedge, the terms of the derivative were the same as a perfect hypothetical derivative; thus, there is an expectation that there will be no ineffectiveness, and that the effective portion of unrealized gains and losses on the FSIRS leading up to the forecasted debt issuance will be reported as a component of other comprehensive income. At termination, the final value will be reclassified from accumulated other comprehensive income into earnings over the same period the hedged forecasted transaction affects earnings. However, should conditions occur that indicate the existence of ineffectiveness (e.g., deterioration of counterparty creditworthiness, delay in the forecasted debt issuance, etc.), Southwest will measure ineffectiveness by comparing the change in fair value of the FSIRS with the change in fair value of a hypothetical swap (the hypothetical derivative method). Gains and losses due to ineffectiveness will be recognized immediately in earnings. At September 30, 2011, the remaining FSIRS continued to qualify as an effective hedge. There was no gain or loss reclassified from accumulated other comprehensive income (“AOCI”) into income (effective portion) and no gain or loss recognized in income (ineffective portion) for the Company’s remaining derivative designated as a hedging instrument. See Note 6 –

Equity, Comprehensive Income, and Accumulated Other Comprehensive Income for additional information on both FSIRS contracts.

Gains (losses) recognized in other comprehensive income for derivatives designated as cash flow hedging instruments:


(Thousands of dollars)
	Three Months Ended						Nine Months Ended						Twelve Months Ended
	September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010
Amount of gain (loss) on unrealized FSIRS recognized in other comprehensive income on derivative (effective portion)	$	(13,237	)	$	(11,281	)	$	(16,382	)	$	(32,540	)	$	9,403		$	(32,540	)
Amount of loss on realized FSIRS recognized in other comprehensive income on derivative		-			-			-			-			(11,691	)		-

	$	(13,237	)	$	(11,281	)	$	(16,382	)	$	(32,540	)	$	(2,288	)	$	(32,540	)

The following table sets forth the fair values of the Company’s Swaps and FSIRS and their location in the balance sheets (thousands of dollars):


Fair values of derivatives not designated as hedging instruments:

September 30, 2011		Asset		Liability
Instrument	Balance Sheet Location	Derivatives		Derivatives			Net Total
Swaps	Other current liabilities	$	-	$	(8,489	)	$	(8,489	)
Swaps	Other deferred credits		-		(181	)		(181	)

Total		$	-	$	(8,670	)	$	(8,670	)


December 31, 2010		Asset		Liability
Instrument	Balance Sheet Location	Derivatives		Derivatives			Net Total
Swaps	Deferred charges and other assets	$	656	$	-		$	656
Swaps	Other current liabilities		65		(11,547	)		(11,482	)

Total		$	721	$	(11,547	)	$	(10,826	)


Fair values of derivatives designated as hedging instruments:

September 30, 2011		Asset		Liability
Instrument	Balance Sheet Location	Derivatives		Derivatives			Net Total
FSIRS	Other current liabilities	$	-	$	(23,137	)	$	(23,137	)


December 31, 2010		Asset		Liability
Instrument	Balance Sheet Location	Derivatives		Derivatives			Net Total
FSIRS	Other deferred credits	$	-	$	(6,755	)	$	(6,755	)

The estimated fair values of the natural gas derivatives were determined using future natural gas index prices (as more fully described below). The Company has master netting arrangements with each counterparty that provide for the net settlement of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets.

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps settle, Southwest reverses any prior positions held and records the settled position as an increase or decrease in purchased gas under the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. Neither changes in fair value, nor settled amounts, of Swaps have a direct effect on earnings or other comprehensive income.

The following table shows the amounts Southwest paid to and received from counterparties for settlements of matured Swaps.


	Three Months Ended		Nine Months Ended		Twelve Months Ended
(Thousands of dollars)	September 30, 2011		September 30, 2011		September 30, 2011

Paid to counterparties	$	3,522	$	11,695	$	16,489

No amounts were received from counterparties for settlements of matured Swaps for the three months, nine months, and twelve months ended September 30, 2011.

The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the balance sheets (thousands of dollars).


September 30, 2011
Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	8,489
Swaps	Deferred charges and other assets		181

December 31, 2010
Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(656	)
Swaps	Prepaids and other current assets		11,482

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at September 30, 2011 and December 31, 2010 using NYMEX futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

The estimated fair values of Southwest’s FSIRS were determined using a discounted cash flow model that utilizes forward interest rate curves. The inputs to the model are the terms of the FSIRS. These Level 2 inputs are observable in the marketplace throughout the full term of the FSIRS, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value:


Level 2 – Significant other observable inputs

(Thousands of dollars)	September 30, 2011			December 31, 2010

Assets at fair value:
Deferred charges and other assets – Swaps	$	-		$	656

Liabilities at fair value:
Other current liabilities – Swaps		(8,489	)		(11,482	)
Other deferred credits – Swaps		(181	)		-
Other current liabilities – FSIRS		(23,137	)		-
Other deferred credits – FSIRS		-			(6,755	)

Net Assets (Liabilities)	$	(31,807	)	$	(17,581	)

No financial assets or liabilities accounted for at fair value fell within Level 1 or Level 3 of the fair value hierarchy.

Related Tax Effects of Designated Hedging Activities Allocated to Each Component of Other Comprehensive Income


	Three Months Ended September 30,
	2011									2010

	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)		Net-of- Tax Amount
(Thousands of dollars)
FSIRS:
Realized/unrealized gain (loss)	$	(13,237	)	$	5,030		$	(8,207	)	$	(11,281	)	$	4,287	$	(6,994	)
Amounts reclassified into net income		292			(111	)		181			-			-		-

Other comprehensive income (loss)	$	(12,945	)	$	4,919		$	(8,026	)	$	(11,281	)	$	4,287	$	(6,994	)


	Nine Months Ended September 30,
	2011									2010
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)		Net-of- Tax Amount
(Thousands of dollars)
FSIRS:
Realized/unrealized gain (loss)	$	(16,382	)	$	6,225		$	(10,157	)	$	(32,540	)	$	12,365	$	(20,175	)
Amounts reclassified into net income		877			(333	)		544			-			-		-

Other comprehensive income (loss)	$	(15,505	)	$	5,892		$	(9,613	)	$	(32,540	)	$	12,365	$	(20,175	)


	Twelve Months Ended September 30,
	2011									2010
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)		Net-of- Tax Amount
(Thousands of dollars)
FSIRS:
Realized/unrealized gain (loss)	$	(2,288	)	$	870		$	(1,418	)	$	(32,540	)	$	12,365	$	(20,175	)
Amounts reclassified into net income		974			(370	)		604			-			-		-

Other comprehensive income (loss)	$	(1,314	)	$	500		$	(814	)	$	(32,540	)	$	12,365	$	(20,175	)

(1)	Tax amounts are calculated using a 38% rate.

Note 5 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of September 30, 2011 and December 31, 2010 are disclosed in the following table. The fair values of the revolving credit facility and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for September 30, 2011 and December 31, 2010, as applicable, and other secondary sources which are customarily consulted for data of this kind.


	September 30, 2011					December 31, 2010
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011	$	-		$	-	$	200,000		$	201,560
Notes, 7.625%, due 2012		200,000			207,934		200,000			214,666
Notes, 4.45%, due 2020		125,000			127,390		125,000			125,325
Notes, 6.1%, due 2041		125,000			142,146		-			-
8% Series, due 2026		75,000			95,260		75,000			99,968
Medium-term notes, 7.59% series, due 2017		25,000			30,217		25,000			30,295
Medium-term notes, 7.78% series, due 2022		25,000			31,600		25,000			32,063
Medium-term notes, 7.92% series, due 2027		25,000			31,185		25,000			33,211
Medium-term notes, 6.76% series, due 2027		7,500			8,345		7,500			8,956
Unamortized discount		(2,191	)				(2,534	)

		605,309					679,966

Revolving credit facility and commercial paper, due 2012		20,000			20,000		-			-

Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
6.10% 1999 Series A, due 2038		12,410			12,437		12,410			11,968
5.95% 1999 Series C, due 2038		14,320			14,357		14,320			13,594
5.55% 1999 Series D, due 2038		8,270			8,082		8,270			7,468
5.45% 2003 Series C, due 2038 (rate resets in 2013)		30,000			31,579		30,000			31,547
5.25% 2003 Series D, due 2038		20,000			19,046		20,000			17,474
5.80% 2003 Series E, due 2038 (rate resets in 2013)		15,000			15,166		15,000			15,436
5.25% 2004 Series A, due 2034		65,000			62,847		65,000			58,574
5.00% 2004 Series B, due 2033		31,200			29,465		31,200			27,295
4.85% 2005 Series A, due 2035		100,000			91,905		100,000			84,485
4.75% 2006 Series A, due 2036		24,855			22,401		24,855			20,518
Unamortized discount		(3,395	)				(3,502	)

		517,660					517,553

Other		14,990			14,977		2,242			2,473

		1,157,959					1,199,761
Less: current maturities		(221,102	)				(75,080	)

Long-term debt, less current maturities	$	936,857				$	1,124,681

Note 6 – Equity, Comprehensive Income, and Accumulated Other Comprehensive Income

The table below provides details of activity in equity during the nine months ended September 30, 2011.


(In thousands, except per share amounts)	Southwest Gas Corporation Equity
	Common Stock				Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total


	Shares		Amount
DECEMBER 31, 2010		45,599	$	47,229	$	807,885	$	(30,784	)	$	343,131		$	(465	)	$	1,166,996
Common stock issuances		302		302		9,150											9,452
Net income (loss)											56,963			(343	)		56,620
Other comprehensive income (loss):
Net actuarial gain arising during period, less amortization of unamortized benefit plan cost, net of tax								960									960
FSIRS unrealized loss, net of tax								(10,157	)								(10,157	)
Amounts reclassified to net income, net of tax (Note 4)								544									544
Dividends declared
Common: $0.795 per share											(36,969	)					(36,969	)

SEPTEMBER 30, 2011		45,901	$	47,531	$	817,035	$	(39,437	)	$	363,125		$	(808	)	$	1,187,446

The tables below provide details of comprehensive income and year-to-date activity in AOCI. See Note 4 – Derivatives and Fair Value Measurements for additional information on the FSIRS, including reclassifications into net income.

Comprehensive Income

(Thousands of dollars)


	Three Months Ended September 30,						Nine Months Ended September 30,						Twelve Months Ended September 30,
	2011			2010			2011			2010			2011			2010
Net income (loss)	$	(15,747	)	$	(4,964	)	$	56,620		$	58,503		$	101,570		$	104,531
Net actuarial gain (loss) arising during period, less amortization of unamortized benefit plan cost, net of tax		320			342			960			1,025			2,777			(2,419	)
FSIRS realized and unrealized losses, net of tax		(8,207	)		(6,994	)		(10,157	)		(20,175	)		(1,418	)		(20,175	)
Amounts reclassified into net income, net of tax		181			-			544			-			604			-

Comprehensive income (loss)		(23,453	)		(11,616	)		47,967			39,353			103,533			81,937
Comprehensive loss attributable to noncontrolling interest		(106	)		(141	)		(343	)		(389	)		(378	)		(753	)

Comprehensive income (loss) attributable to Southwest Gas Corporation	$	(23,347	)	$	(11,475	)	$	48,310		$	39,742		$	103,911		$	82,690

Tax (expense) benefit associated with net actuarial gain (loss) arising during period	$	(197	)	$	(209	)	$	(589	)	$	(628	)	$	(1,702	)	$	1,484

Tax benefit associated with FSIRS realized and unrealized losses recognized in other comprehensive income	$	5,030		$	4,287		$	6,225		$	12,365		$	870		$	12,365

Tax expense associated with FSIRS reclassified out of AOCI to net income	$	(111	)	$	-		$	(333	)	$	-		$	(370	)	$	-

AOCI - Rollforward

(Thousands of dollars)


	Defined Benefit Plans									FSIRS								AOCI
	Before-Tax			Tax (Expense) Benefit			After-Tax			Before-Tax			Tax (Expense) Benefit		After-Tax			AOCI
Beginning Balance AOCI December 31, 2010	$	(31,304	)	$	11,896		$	(19,408	)	$	(18,349	)	$	6,973	$	(11,376	)	$	(30,784	)
Current period change		1,549			(589	)		960	*		(15,505	)		5,892		(9,613	)**		(8,653	)

Ending Balance AOCI September 30, 2011	$	(29,755	)	$	11,307		$	(18,448	)	$	(33,854	)	$	12,865	$	(20,989	)	$	(39,437	)

*	Net actuarial gain (loss), less amortization of unamortized benefit plan cost

**	FSIRS unrealized loss of $10,157,000 recognized in other comprehensive income less the portion of the previous FSIRS realized loss that was reclassified to net income in the current period ($544,000).

Approximately $1.5 million of realized/unrealized losses (net of tax) related to the FSIRS reported in AOCI at September 30, 2011 will be reclassified into expense within the next 12 months as interest payments on the related long-term debt occur.

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

Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two business segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services.

Southwest is engaged in the business of purchasing, distributing, and transporting 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 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.

On a seasonally adjusted basis as of September 30, 2011, Southwest had 1,836,000 residential, commercial, industrial, and other natural gas customers, of which 987,000 customers were located in Arizona, 667,000 in Nevada, and 182,000 in California. Residential and commercial customers represented over 99% of the total customer base. During the twelve months ended September 30, 2011, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 86% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 10% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. 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 principal factors typically affecting operating margin are general rate relief, weather, conservation and efficiencies, and customer growth. Of these, weather is the primary reason for volatility in margin. Variances in temperatures from normal levels, primarily in Arizona, can have a significant impact on the margin and associated net income of the Company. See also Rates and Regulatory Proceedings. A decoupled rate structure designed to mitigate the impacts of weather variability and conservation on margin is utilized in the Nevada service territories. Weather impacts and conservation are also offset by the margin tracking mechanism in Southwest’s California service territories.

NPL 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. NPL operates in 18 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including the housing market, interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, bonus depreciation legislation, and local and federal tax rates. Generally, revenues and profits are lowest during the first quarter of the year due to less favorable winter weather conditions. Operating results typically improve as more favorable weather conditions occur during the summer and fall months.

This Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and the notes thereto, as well as the MD&A, included in the 2010 Annual Report to Shareholders, which is incorporated by reference into the 2010 Form 10-K, and the first and second quarter 2011 reports on Form 10-Q.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations. As needed, certain items are covered in greater detail in later sections of management’s discussion and analysis. As reflected in the table below, the natural gas operations segment accounted for an average of 86% of twelve-month-to-date consolidated net income over the past two years. As such, management’s discussion and analysis is primarily focused on that segment. Natural gas sales are seasonal, peaking during the winter months; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Summary Operating Results


	Period Ended September 30,
	Three Months						Nine Months				Twelve Months
	2011			2010			2011		2010		2011		2010
		(In thousands, except per share amounts)

Contribution to net income (loss)
Natural gas operations	$	(25,566	)	$	(8,813	)	$	42,648	$	52,403	$	81,627	$	96,074
Construction services		9,925			3,990			14,315		6,489		20,321		9,210

Net income (loss)	$	(15,641	)	$	(4,823	)	$	56,963	$	58,892	$	101,948	$	105,284


Average number of common shares outstanding		45,881			45,447			45,837		45,354		45,766		45,262


Basic earnings (loss) per share
Consolidated	$	(0.34	)	$	(0.11	)	$	1.24	$	1.30	$	2.23	$	2.33


Natural Gas Operations
Operating margin	$	128,482		$	132,590		$	554,888	$	552,377	$	778,243	$	781,733

Consolidated results for the third quarter of 2011 decreased compared to the same period in 2010, due to a decline in the gas operations segment. The reduction primarily resulted from decreases in other income and gas segment operating margin, and increases in operating costs. The decline was partially offset by lower financing costs and an improvement in construction services results.

3rd Quarter 2011 Overview

Natural gas operations highlights include the following:

•

Other income decreased $14.8 million between comparative periods primarily due to lower COLI policy-related income (including net death benefits)

•

Operating margin decreased approximately $4 million compared to the prior-year quarter

•

Net financing costs declined $2 million between comparative periods

•

Liquidity position is adequate and outlook is favorable

Construction services highlights include the following:

•

Revenues increased 67% compared to the prior-year quarter

•

Contribution to consolidated results improved $5.9 million between comparative periods

Company-Owned Life Insurance (“COLI”). Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $213 million at September 30, 2011. The net cash surrender value of these policies (which is the amount the Company would receive if it voluntarily terminated the policies) is approximately $70 million at September 30, 2011 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with movements in the broader stock and bond markets. As indicated in Note 1, the cash surrender value movement of COLI policies diverged considerably in each of the three-, nine-, and twelve-month periods presented. Management currently expects average returns of $2 million to $4 million annually on the COLI policies, excluding any net death benefits recognized. Based on the current investment mix, both positive and negative deviations from expected levels are likely to continue.

Out-of-Period Adjustment. As disclosed in Note 1, Southwest recorded a $3.7 million decrease to revenues in the third quarter of 2011 related to an isolated error in a regulatory deferral mechanism that overstated revenues for periods prior to the third quarter of 2011. Approximately $800,000 of the adjustment relates to the first half of 2011 while $2.9 million pertains to years prior to 2011 ($300,000 to $400,000 per quarter in 2009 and 2010).

Weather. The rate structures in each of Southwest’s three states provide varying levels of protection from risks that drive operating margin volatility, particularly weather risk and conservation efforts. Southwest’s exposure to these risks on operating margin is largely limited to its Arizona operating areas as both Nevada and California operations are now under decoupled rate structures. Weather was not a significant factor in either the third quarter of 2010 or 2011.

Arizona Rate Proceedings. In December 2010, the Arizona Corporation Commission (“ACC”) issued a Policy Statement which allowed utilities to file proposals for alternative mechanisms, including revenue-per-customer decoupling, in general rate case filings, to address the financial disincentives to utilities of promoting energy efficiency. In anticipation of the Policy Statement, the Company’s recent Arizona rate case filing requested a rate structure to decouple recovery of the Company’s fixed costs from fluctuations in usage, both higher and lower, to enable the Company to aggressively advocate increased energy efficiency by its customers by eliminating the existing financial disincentive. Hearings were held during the summer on a settlement agreement containing provisions to mitigate the impacts on operating margin of weather and conservation. For more information see the Rates and Regulatory Proceedings discussion.

Customer Growth. Southwest added 16,000 net new customers over the last twelve months while completing 13,000 first time meter sets. Southwest continues to project net customer growth of 1% or less for 2011.

Liquidity. Southwest believes its liquidity position is adequate and the outlook is favorable. Southwest has a $300 million credit facility maturing in May 2012. The facility is provided through a consortium of eight major banking institutions. Usage of the facility has been minimal during the first nine months of 2011. The outstanding balance at September 30, 2011 was $20 million, leaving $280 million available for working capital needs. The lower usage was primarily due to existing cash reserves and natural gas prices that were relatively stable. The ongoing slowdown in housing construction has also allowed Southwest to fund construction expenditures primarily with internally generated cash. Management intends to replenish its borrowing capacity by the end of the first quarter of 2012.

Results of Natural Gas Operations

Quarterly Analysis


	Three Months Ended September 30,
	2011			2010
	(Thousands of dollars)
Gas operating revenues	$	195,647		$	213,893
Net cost of gas sold		67,165			81,303

Operating margin		128,482			132,590
Operations and maintenance expense		89,087			86,746
Depreciation and amortization		43,640			42,574
Taxes other than income taxes		10,585			10,006

Operating income (loss)		(14,830	)		(6,736	)
Other income (deductions)		(8,093	)		6,704
Net interest deductions		17,116			19,115

Income (loss) before income taxes		(40,039	)		(19,147	)
Income tax expense (benefit)		(14,473	)		(10,334	)

Contribution to consolidated net income (loss)	$	(25,566	)	$	(8,813	)

Contribution to consolidated net income (loss) from natural gas operations declined by $16.8 million in the third quarter of 2011 compared to the same period a year ago. The reduction was primarily due to decreases in other income and operating margin and higher operating expenses, partially offset by a decrease in financing costs.

Operating margin decreased $4 million in the third quarter of 2011 compared to the third quarter of 2010 primarily due to the out-of-period adjustment related to a regulatory deferral mechanism. Rate relief, weather, and customer growth were not significant components of the change in margin between the third quarters of 2011 and 2010. Approximately 16,000 net new customers were added during the last twelve months.

Operations and maintenance expense increased $2.3 million, or 3%, between quarters primarily due to general cost increases.

Depreciation expense increased $1.1 million, or 3%, as a result of additional plant in service. Average gas plant in service for the current quarter increased $130 million, or 3%, compared to the corresponding quarter a year ago.

Taxes other than income taxes increased $579,000 between quarters primarily due to higher Arizona property tax rates. Both quarters include rate increases that were retroactive to January 1 of their respective years.

Other income decreased $14.8 million between quarters primarily due to changes in COLI policy-related amounts. Cash surrender values of COLI policies (net of recognized death benefits) decreased $6.7 million in the current quarter, while the prior-year quarter reflected a $7.8 million increase in COLI-related values (including net death benefits recognized).

Net financing costs decreased $2 million between quarters primarily due to cost savings from refinancing and reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs).

Income tax expense (benefit) includes $1.6 million of previously unrecognized tax benefits and related interest associated with the expiration of the statute of limitations with respect to a previously recorded uncertain tax position.

Nine-Month Analysis


	Nine Months Ended September 30,
	2011			2010
	(Thousands of dollars)
Gas operating revenues	$	1,022,914		$	1,133,671
Net cost of gas sold		468,026			581,294

Operating margin		554,888			552,377
Operations and maintenance expense		268,745			260,386
Depreciation and amortization		130,997			127,416
Taxes other than income taxes		30,750			29,388

Operating income		124,396			135,187
Other income (deductions)		(6,804	)		997
Net interest deductions		52,097			56,001
Net interest deductions on subordinated debentures		-			1,912

Income before income taxes		65,495			78,271
Income tax expense		22,847			25,868

Contribution to consolidated net income	$	42,648		$	52,403

Contribution to consolidated net income from natural gas operations decreased by $9.8 million in the first nine months of 2011 compared to the same period a year ago. The decline was primarily due to higher operating costs and a decrease in other income, partially offset by a decrease in financing costs and higher operating margin.

Operating margin increased $3 million between periods. Differences in heating demand, caused primarily by weather variations, provided $4 million in operating margin. Rate relief in California provided $2 million of the operating margin increase and new customers contributed an additional $1 million. The increases were partially offset by the regulatory deferral mechanism adjustment in the third quarter of 2011.

Operations and maintenance expense increased $8.4 million, or 3%, between periods primarily due to higher general cost increases. In addition, the increase includes approximately $1 million of costs associated with restoring service to approximately 20,000 Arizona customers in early February 2011, following an outage due to extreme weather conditions.

Depreciation expense increased $3.6 million, or 3%, as a result of additional plant in service. Average gas plant in service for the current period increased $139 million, or 3%, compared to the corresponding period a year ago.

The $1.4 million increase in taxes other than income taxes is primarily due to higher property tax rates in Arizona.

Other income, which principally includes returns on COLI policies and non-utility expenses, decreased $7.8 million between the nine-month periods of 2011 and 2010. Cash surrender values of COLI policies (net of recognized death benefits) decreased $1.9 million in the current-year period, while values of COLI policies (including recognized net death benefits) increased during the nine-month period of 2010 by $5.6 million.

Net financing costs decreased $5.8 million between periods primarily due to cost savings from debt refinancing, reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs), and the redemption of $100 million of Subordinated Debentures in March 2010.

Twelve-Month Analysis


	Twelve Months Ended September 30,
	2011			2010
	(Thousands of dollars)
Gas operating revenues	$	1,401,150		$	1,561,644
Net cost of gas sold		622,907			779,911

Operating margin		778,243			781,733
Operations and maintenance expense		363,302			352,047
Depreciation and amortization		174,037			168,653
Taxes other than income taxes		40,231			38,826

Operating income		200,673			222,207
Other income (deductions)		(3,785	)		2,998
Net interest deductions		71,209			74,475
Net interest deductions on subordinated debentures		-			3,845

Income before income taxes		125,679			146,885
Income tax expense		44,052			50,811

Contribution to consolidated net income	$	81,627		$	96,074

Contribution to consolidated net income from natural gas operations decreased by $14.4 million in the current twelve-month period as compared to the corresponding period a year ago. The reduction was primarily due to decreases in other income and operating margin, and higher operating expenses, partially offset by a decline in financing costs.

Operating margin decreased $3 million between periods. Margin increases due to rate relief totaled $5 million ($2 million in Nevada and $3 million in California). Customer growth contributed $1 million of operating margin. Differences in heating demand caused by weather variations between periods resulted in a decrease of $5 million. The remaining decrease was due to the regulatory deferral mechanism adjustment in the third quarter of 2011.

Operations and maintenance expense increased $11.3 million, or 3%, primarily due to higher general costs and employee-related costs including pension expense. The increases were mitigated by cost containment efforts (including lower staffing levels).

Depreciation expense increased $5.4 million, or 3%, as a result of additional plant in service. Average gas plant in service for the current period increased $135 million, or 3%, compared to the corresponding period a year ago. This was attributable to reinforcement work, franchise requirements, routine and accelerated pipe replacement activities, and new business.

Taxes other than income taxes increased $1.4 million primarily due to higher property tax rates in Arizona.

Other income, which principally includes returns on COLI policies and non-utility expenses, decreased $6.8 million between the twelve-month periods of 2011 and 2010. The current period reflects a net COLI-related increase (including recognized death benefits) of $2.3 million, while the prior-year period had $7.2 million of cash surrender value increases (including recognized net death benefits).

Net financing costs decreased $7.1 million between the twelve-month periods of 2011 and 2010 primarily due to the redemption of the Subordinated Debentures in March 2010, cost savings from debt refinancing, and reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs).

Results of Construction Services

Quarter. Contribution to consolidated net income from construction services for the three months ended September 30, 2011 increased $5.9 million compared to the same period of 2010.

Revenues increased $63.2 million, a 67% improvement, when compared to the same period of 2010. Revenue from replacement construction continues to be strong. Construction expenses increased $52.3 million, or 64%, due to the increase in construction work. Depreciation expense increased $1.7 million due to additional equipment purchases. Gains on sale of equipment were $657,000 and $138,000 for the third quarters of 2011 and 2010, respectively.

Nine Months-to-Date. Contribution to consolidated net income from construction services for the nine months ended September 30, 2011 increased $7.8 million compared to the same period of 2010.

Revenues increased $118 million, a 52% improvement, when compared to the same period of 2010 primarily due to increased replacement construction. Construction expenses increased $102 million due to the increase in replacement construction work. Depreciation expense increased $2.6 million between the current period and the prior-year period due to an increase in equipment purchases. Gains on sale of equipment were $2 million and $695,000 for the first nine months of 2011 and 2010, respectively.

Twelve Months-to-Date. The contribution to consolidated net income from construction services for the twelve-month period ended September 30, 2011 increased $11.1 million compared to the same period of 2010.

Revenues increased $137 million due primarily to an increase in the volume of replacement work. Construction expenses increased $116 million between the twelve-month periods due primarily to costs associated with the increase in replacement construction work. Depreciation expense rose $1.9 million due to an increase in new equipment purchases. Gains on sale of equipment were $2.8 million and $1.8 million for the twelve-month periods of 2011 and 2010, respectively.

NPL’s revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Typically, revenues and profit are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating results typically improve as more favorable weather conditions occur during the summer and fall months. Current low interest rates, the impact of bonus depreciation legislation, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on NPL’s growth and resulting earnings. These factors are likely to allow NPL to sustain this approximate level of performance for the near term.

Rates and Regulatory Proceedings

Arizona Energy Efficiency and Decoupling Proceeding. In August 2010, the ACC issued a Notice of Proposed Rulemaking on Gas Energy Efficiency, which adopted an energy efficiency requirement for Arizona’s gas utilities, including Southwest, to achieve cumulative annual energy savings of 6% by December 2020. In October 2010, the Chairman of the ACC issued a draft Policy Statement, which would allow utilities to file proposals for alternative mechanisms including revenue-per-customer decoupling, in connection with a general rate case to address the financial disincentives to utilities of promoting energy efficiency. The Policy Statement was approved by the ACC in December 2010.

Arizona General Rate Case. Southwest filed a general rate application with the ACC in November 2010 requesting an increase in authorized annual operating revenues of $73.2 million, or 9.26%, to reflect increased operating costs, investments in infrastructure, and costs of capital, as well as margin attrition due to decreased average usage by customers. The application requested an overall rate of return of 9.73% on original cost rate base of $1.074 billion, an 11% return on common equity, and a capital structure utilizing 52% common equity.

The rate case filing also requested a rate structure to decouple recovery of the Company’s fixed costs from natural gas usage and enable the Company to aggressively advocate for increased energy efficiency by its customers. The filed structure anticipated the approval of the Policy Statement discussed in the Arizona Energy Efficiency and Decoupling Proceeding section above. The proposed mechanism, referred to as the Energy Efficiency Enabling Provision (“EEEP”), is a revenue-per-customer decoupling mechanism designed to eliminate the link between

volumetric sales and revenues that currently exists with traditional rate designs, such that the existing financial disincentive associated with the Company’s pursuit of cost-effective energy efficiency is eliminated. This will allow management to focus on customers and to concentrate its attention on the cost of providing service. The pursuit of increased energy efficiency by customers is supported by the requested approval of a detailed energy efficiency and renewable energy resource plan.

After several weeks of negotiations, a majority of the parties agreed to a settlement, which was filed with the ACC in July 2011. In addition to Southwest, parties supporting the settlement include the ACC Staff, the Arizona Community Action Association, the Arizona Investment Council, the Natural Resources Defense Council, and the Southwest Energy Efficiency Project. The Residential Utility Consumer Office and Tucson Electric Power Company are not parties to the agreement. Two options were presented in the settlement: one providing for partial decoupling (Alternative A) and one with a full decoupling provision (Alternative B). Alternative A would include a $54.9 million revenue increase, or 6.95%, with a 9.75% return on common equity. Rate design improvements would include adoption of a weather normalization provision along with a “lost fixed-cost recovery mechanism” which would hold the Company financially harmless from reduced sales associated with conservation and energy efficiency programs. Alternative B would include a $52.6 million revenue increase, or 6.66%, with a 9.5% return on common equity. This option would allow for monthly weather normalization and an annual true-up for any non-weather margin variances from authorized amounts per customer. If approved, Alternative B would also require a rate case moratorium, preventing Southwest from filing a general rate case prior to April 2016. Hearings on the proposed settlement were held during the summer and a decision from the ACC is expected by the end of the year. The settlement recommends that new rates be placed in effect by January 2012. Management cannot predict whether either settlement alternative will be approved by the ACC or the timing of rate relief.

PGA Filings

The rate schedules in all of Southwest’s service territories contain provisions that permit adjustments to rates as the cost of purchased gas changes. These deferred energy provisions and purchased gas adjustment clauses are collectively referred to as “PGA” clauses. Differences between gas costs recovered from customers and amounts paid for gas by Southwest result in over- or under-collections. At September 30, 2011, over-collections in all service territories resulted in a liability of $93.7 million on the Company’s balance sheet. 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. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

As of September 30, 2011, December 31, 2010, and September 30, 2010, Southwest had the following outstanding PGA balances receivable/(payable) (millions of dollars):


	September 30, 2011			December 31, 2010			September 30, 2010
Arizona	$	(35.2	)	$	(45.2	)	$	(56.7	)
Northern Nevada		(12.8	)		(8.4	)		(12.9	)
Southern Nevada		(43.9	)		(69.8	)		(77.9	)
California		(1.8	)		0.4			(5.0	)

	$	(93.7	)	$	(123.0	)	$	(152.5	)

Nevada Annual Rate Adjustment (“ARA”) Application. In June 2011, Southwest filed its ARA application with the Public Utilities Commission of Nevada (“PUCN”) to establish revised Deferred Energy Account Adjustment (“DEAA”) rates (in addition to adjustments to the Variable Interest Expense Recovery, the Uncollectible Gas Cost Expense rates, and other rate-related items). Recently approved legislation allows Southwest to make quarterly DEAA adjustments based upon a twelve-month rolling average. Southwest filed its first quarterly DEAA rate adjustment application under the new rules in July 2011, which was approved, and was made effective in October 2011.

Capital Resources and Liquidity

Cash on hand and cash flows from operations have generally been sufficient over the past two years to provide for most net investing activities (primarily construction expenditures and property additions). During the past two years, the Company has been able to use cash inflows to reduce the net amount of debt outstanding. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt.

To facilitate future financings, the Company has a universal shelf registration statement providing for the issuance and sale of registered securities from time to time, which may consist of secured debt, unsecured debt, preferred stock, or common stock. The number and dollar amount of securities issued under the universal shelf registration statement, which was filed with the SEC and automatically declared effective in December 2008, will be determined at the time of the offerings, if any, and presented in the applicable prospectuses.

Cash Flows

Operating Cash Flows. Cash flows provided by consolidated operating activities decreased $71.5 million in the first nine months of 2011 as compared to the same period in 2010. The primary drivers of the change were temporary fluctuations in working capital components, most notably, PGA balances.

Investing Cash Flows. Net cash used in consolidated investing activities increased $128 million in the first nine months of 2011 as compared to the same period in 2010. The increase was primarily due to additional construction expenditures, including routine and accelerated (to take advantage of bonus depreciation tax incentives) pipe replacement, and equipment purchases by NPL due to increased replacement construction work of its customers. In addition, 2010 included a draw-down of funds, restricted for construction activities, associated with an industrial development revenue bond issuance in 2009. Similar draw-downs to fund construction did not occur in 2011.

Financing Cash Flows. Net cash used in consolidated financing activities decreased $148 million during the first nine months of 2011 as compared to the same period in 2010 primarily due to the issuance of new debt including $125 million 6.1% Senior Notes and borrowings on the long-term portion of Southwest’s credit facility, partially offset by debt repayments including the $200 million 8.375% Notes repaid in February 2011. The remaining amounts in issuances and retirements of long-term debt primarily relate to borrowings and repayments under NPL’s line of credit. The prior-year period included the redemption of the subordinated debentures as well as the repayment of other debt, primarily repayment of previous borrowings under Southwest’s credit facility. Dividends paid increased in the first nine months of 2011 as compared to 2010 as a result of a quarterly dividend increase and an increase in the number of shares outstanding.

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.

Gas Segment Construction Expenditures, Debt Maturities, and Financing

During the twelve-month period ended September 30, 2011, construction expenditures for the natural gas operations segment were $261 million. The majority of these expenditures represented costs associated with routine and accelerated replacement of existing transmission, distribution, and general plant (see also Bonus Depreciation below). Cash flows from operating activities of Southwest were $259 million and provided approximately 84% of construction expenditures and dividend requirements. Other necessary funding was provided by cash on hand, external financing activities and existing credit facilities.

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2013 will be approximately $680 million (including $110 million of accelerated expenditures). During the three-year period, cash flows from operating activities of Southwest (including bonus depreciation benefits) are expected to provide approximately 80% of the gas operations total construction expenditures and dividend requirements. During the three-year period, the Company expects to raise approximately $15 million from its various common stock programs. Any cash requirements not met by operating activities are expected to be provided by cash on hand (including restricted cash), existing credit facilities and/or 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’s 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 December 2010, the Company issued $125 million in 4.45% Senior Notes, due December 2020 at a discount of 0.182%. A portion of the net proceeds was used to pay down borrowings under the credit facility. In February 2011, the Company used approximately $75 million of the remaining net proceeds in connection with its repayment of the 8.375% $200 million Notes that matured in February 2011. The remaining proceeds were used for general corporate purposes.

In February 2011, the Company issued $125 million of 6.1% Senior Notes to certain institutional investors pursuant to a November 2010 note purchase agreement. The Senior Notes are unsecured and unsubordinated obligations of the Company, due in February 2041. Funds from the issuance were used to partially repay the 8.375% $200 million Notes that matured in February 2011.

Southwest also has $200 million of long-term debt maturing in May 2012 and plans to fund that obligation by issuing $200 million of debentures by the maturity date. In connection with the planned 2012 debt issuance, the Company, in January 2010, entered into a forward-starting interest rate swap (“FSIRS”) agreement to partially hedge the risk of interest rate variability during the period leading up to the planned issuance. See Note 4 – Derivatives and Fair Value Measurements for more information on the FSIRS.

During the nine months ended September 30, 2011, the Company issued shares of common stock through the Stock Incentive Plan, raising approximately $5 million.

Bonus Depreciation. As a result of two tax acts signed into law in 2010, a bonus depreciation tax deduction of 100% is available for qualified property acquired or constructed and placed in service from September 9, 2010 through December 31, 2011 and a 50% bonus tax depreciation deduction is available for qualified property acquired or constructed and placed in service from January 1, 2012 through December 31, 2012. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provisions of the two acts will defer the payment of approximately $65 million and $30 million of federal income taxes during 2011 and 2012, respectively.

Dividend Policy

The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. In February 2011, the Board of Directors increased the quarterly dividend payout from 25 cents to 26.5 cents per share, effective with the June 2011 payment.

Liquidity

Liquidity refers to the ability of an enterprise to generate sufficient amounts of cash through its operating activities and external financing to meet its cash requirements. Several general factors (some of which are out of the control of the Company) that could significantly affect liquidity in future years include: variability of natural gas prices, changes in the ratemaking policies of regulatory commissions, regulatory lag, customer growth in the natural gas segment’s service territories, Southwest’s ability to access and obtain capital from external sources, interest rates, changes in income tax laws, pension funding requirements, inflation, and the level of Company earnings. Natural gas prices and related gas cost recovery rates have historically had the most significant impact on Company liquidity.

Pension funding requirements for the Southwest pension plan during calendar-year 2011 were initially estimated at $28 million. In October 2011, Southwest voluntarily contributed an incremental $31 million to the pension plan (and accelerated $9 million of funding from 2012) in order to improve the plan’s funded status. Funds for the contribution were provided by cash on hand and borrowings under the Company’s credit facility.

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, 2011, the combined balance in the PGA accounts totaled an over-collection of $93.7 million. See PGA Filings for more information on recent regulatory filings.

The Company has a $300 million credit facility that expires in May 2012. Southwest previously designated $150 million of the $300 million facility as long-term debt and the remaining $150 million for working capital purposes. At September 30, 2011, $20 million was outstanding on the credit facility. Borrowings under the credit facility ranged from $0 for the first eight months of the year to a maximum of $20 million at September 30, 2011. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any, or meeting the refund needs of over-collected balances. This credit facility has been, and is expected to continue to be, adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing prior to its expiration. Management believes the Company currently has an adequate liquidity position and intends to replenish its borrowing capacity by the end of the first quarter of 2012.

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


	For the Twelve Months Ended
	September 30, 2011		December 31, 2010

Ratio of earnings to fixed charges		2.97		2.87

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), and net amortized debt costs.

Credit Rating Upgrades. In April 2011, Standard & Poor’s Ratings Services (“S&P”) upgraded the Company’s unsecured long-term debt ratings from BBB (with a positive outlook) to BBB+ (with a stable outlook). S&P cited the Company’s improved financial results and stable financial metrics. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal.

In June 2011, Fitch Ratings (“Fitch”) upgraded the Company’s long-term issuer default rating and its senior unsecured rating to BBB+ from BBB; the outlook has been revised to stable from positive. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB+ indicates a credit quality that is considered prudent for investment.

Forward-Looking Statements

This quarterly report contains statements which constitute “forward-looking statements” within the meaning of the Private 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,” “forecast,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, the Company’s COLI strategy, annual COLI returns, amount and timing for completion of estimated future construction expenditures, forecasted operating cash flows and results of operations, funding sources of cash requirements, sufficiency of working capital, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, the amount and form of any such financing, plans to fund maturing obligations, the effectiveness of the forward-starting interest rate swap agreement in hedging against changing interest rates, earnings trends, certain benefits of tax acts, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals (including the form of approved rate mechanisms) are 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, conditions in the housing market, the ability to recover costs through PGA mechanisms, 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, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, renewal of franchises, easements and rights-of-way, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition, and the ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

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 2010 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 (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. 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 may not be detected.

Based on the most recent evaluation, as of September 30, 2011, 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 (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the third quarter of 2011 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 1A.

through 3. None.

ITEM 4.

[REMOVED AND RESERVED]

ITEM 5.

OTHER INFORMATION None.

ITEM 6.

EXHIBITS

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


Exhibit 12.01	-	Computation of Ratios of Earnings to Fixed Charges.
Exhibit 31.01	-	Section 302 Certifications.
Exhibit 32.01	-	Section 906 Certifications.
Exhibit 101		The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in Extensible Business Reporting Language (“XBRL”): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Income, (iii) the Condensed Consolidated Statements of Cash Flows, and (iv) the Notes to the Condensed Consolidated Financial Statements.

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, 2011
		/s/ Gregory J. Peterson
		Gregory J. Peterson
		Vice President/Controller and Chief Accounting Officer