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.

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, ~~46,512,597~~46,518,555 shares as of ~~July~~October 29, 2014.


	JUNE 30,			DECEMBER 31,
	2014			2013				SEPTEMBER 30, 2014			DECEMBER 31, 2013
ASSETS
Utility plant:
Gas plant	$	5,398,729		$	5,252,469			$	5,485,091		$	5,252,469
Less: accumulated depreciation		(1,928,978	)		(1,868,504	)			(1,954,553	)		(1,868,504	)
Acquisition adjustments, net		640			730				595			730
Construction work in progress		74,884			101,413				77,183			101,413

Net utility plant		3,545,275			3,486,108				3,608,316			3,486,108

Other property and investments		267,763			260,871				265,468			260,871

Restricted cash		16,649			—

Current assets:
Cash and cash equivalents		26,890			41,077				39,165			41,077
Accounts receivable, net of allowances		183,472			219,469				184,790			219,469
Accrued utility revenue		31,600			72,700				32,000			72,700
Income taxes receivable, net		4,283			3,790				20,398			3,790
Deferred income taxes		—			31,130				—			31,130
Deferred purchased gas costs		80,441			18,217				78,318			18,217
Prepaids and other current assets		83,805			108,289		��		95,845			108,289

Total current assets		410,491			494,672				450,516			494,672

Deferred charges and other assets		322,111			323,523				317,361			323,523

Total assets	$	4,562,289		$	4,565,174			$	4,641,661		$	4,565,174


CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 46,503,111 and 46,356,125 shares)	$	48,133		$	47,986
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 46,518,555 and 46,356,125 shares)								$	48,148		$	47,986
Additional paid-in capital		844,851			840,521				846,127			840,521
Accumulated other comprehensive income (loss), net		(39,638	)		(41,698	)			(38,608	)		(41,698	)
Retained earnings		613,760			567,714				598,552			567,714

Total Southwest Gas Corporation equity		1,467,106			1,414,523				1,454,219			1,414,523
Noncontrolling interest		(2,214	)		(2,128	)			(2,257	)		(2,128	)

Total equity		1,464,892			1,412,395				1,451,962			1,412,395
Long-term debt, less current maturities		1,365,926			1,381,327				1,437,706			1,381,327

Total capitalization		2,830,818			2,793,722				2,889,668			2,793,722

Current liabilities:
Current maturities of long-term debt		23,741			11,105				11,265			11,105
Accounts payable		94,400			183,511				98,991			183,511
Customer deposits		72,896			73,367				71,320			73,367
Accrued general taxes		35,657			39,681				39,704			39,681
Accrued interest		18,187			17,920				23,318			17,920
Deferred income taxes		5,566			—				11,304			—
Other current liabilities		132,165			108,580				138,096			108,580

Total current liabilities		382,612			434,164				393,998			434,164

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		663,470			674,411				671,560			674,411
Taxes payable		—			284				—			284
Accumulated removal costs		291,000			279,000				297,000			279,000
Other deferred credits		394,389			383,593				389,435			383,593

Total deferred income taxes and other credits		1,348,859			1,337,288				1,357,995			1,337,288

Total capitalization and liabilities	$	4,562,289		$	4,565,174			$	4,641,661		$	4,565,174


	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,						TWELVE MONTHS ENDED JUNE 30,						THREE MONTHS ENDED SEPTEMBER 30,						NINE MONTHS ENDED SEPTEMBER 30,						TWELVE MONTHS ENDED SEPTEMBER 30,
	2014			2013			2014			2013			2014			2013			2014			2013			2014			2013			2014			2013
Operating revenues:
Gas operating revenues	$	271,479		$	238,869		$	757,972		$	732,469		$	1,325,657		$	1,267,567		$	226,027		$	195,031		$	983,999		$	927,500		$	1,356,653		$	1,267,025
Construction revenues		181,674			172,705			303,577			292,610			661,595			617,877			206,448			192,315			510,025			484,925			675,728			633,966

Total operating revenues		453,153			411,574			1,061,549			1,025,079			1,987,252			1,885,444			432,475			387,346			1,494,024			1,412,425			2,032,381			1,900,991

Operating expenses:
Net cost of gas sold		97,985			69,388			289,362			269,996			455,367			414,892			72,987			47,746			362,349			317,742			480,608			409,361
Operations and maintenance		97,620			94,935			200,028			192,022			392,920			374,267			93,389			95,981			293,417			288,003			390,328			379,621
Depreciation and amortization		62,186			58,570			125,077			117,503			244,391			231,225			62,037			58,744			187,114			176,247			247,684			233,251
Taxes other than income taxes		10,965			11,073			22,421			22,868			45,104			44,131			11,835			11,153			34,256			34,021			45,786			44,684
Construction expenses		157,642			148,700			270,841			255,388			588,737			532,106			173,937			167,581			444,778			422,969			595,093			545,420

Total operating expenses		426,398			382,666			907,729			857,777			1,726,519			1,596,621			414,185			381,205			1,321,914			1,238,982			1,759,499			1,612,337

Operating income		26,755			28,908			153,820			167,302			260,733			288,823			18,290			6,141			172,110			173,443			272,882			288,654

Other income and (expenses):
Net interest deductions		(17,305	)		(15,290	)		(34,824	)		(31,168	)		(67,356	)		(63,777	)		(17,421	)		(15,097	)		(52,245	)		(46,265	)		(69,680	)		(62,464	)
Other income (deductions)		2,863			1,452			4,475			5,521			11,254			6,994			440			2,668			4,915			8,189			9,026			8,026

Total other income and (expenses)		(14,442	)		(13,838	)		(30,349	)		(25,647	)		(56,102	)		(56,783	)		(16,981	)		(12,429	)		(47,330	)		(38,076	)		(60,654	)		(54,438	)

Income before income taxes		12,313			15,070			123,471			141,655			204,631			232,040
Income tax expense		2,686			5,003			43,147			50,914			70,175			83,607
Income (loss) before income taxes																				1,309			(6,288	)		124,780			135,367			212,228			234,216
Income tax expense (benefit)																				(618	)		(3,231	)		42,529			47,683			72,788			84,426

Net income		9,627			10,067			80,324			90,741			134,456			148,433
Net income (loss)																				1,927			(3,057	)		82,251			87,684			139,440			149,790
Net income (loss) attributable to noncontrolling interest		—			(41	)		(86	)		(140	)		(393	)		(536	)		(43	)		(193	)		(129	)		(333	)		(243	)		(620	)

Net income attributable to Southwest Gas Corporation	$	9,627		$	10,108		$	80,410		$	90,881		$	134,849		$	148,969
Net income (loss) attributable to Southwest Gas Corporation																			$	1,970		$	(2,864	)	$	82,380		$	88,017		$	139,683		$	150,410

Basic earnings per share	$	0.21		$	0.22		$	1.73		$	1.96		$	2.91		$	3.22

Diluted earnings per share	$	0.21		$	0.22		$	1.71		$	1.95		$	2.88		$	3.19
Basic earnings (loss) per share																			$	0.04		$	(0.06	)	$	1.77		$	1.90		$	3.01		$	3.25

Diluted earnings (loss) per share																			$	0.04		$	(0.06	)	$	1.76		$	1.88		$	2.98		$	3.22

Dividends declared per share	$	0.365		$	0.330		$	0.730		$	0.660		$	1.390		$	1.250		$	0.365		$	0.330		$	1.095		$	0.990		$	1.425		$	1.285


Average number of common shares outstanding		46,502			46,331			46,471			46,291			46,407			46,214			46,513			46,337			46,485			46,306			46,451			46,265
Average shares outstanding (assuming dilution)		46,948			46,757			46,910			46,704			46,860			46,654			46,966			—			46,928			46,732			46,904			46,704


	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,						TWELVE MONTHS ENDED JUNE 30,						THREE MONTHS ENDED SEPTEMBER 30,						NINE MONTHS ENDED SEPTEMBER 30,						TWELVE MONTHS ENDED SEPTEMBER 30,
	2014			2013			2014			2013			2014			2013			2014			2013			2014			2013			2014			2013
Net income	$	9,627		$	10,067		$	80,324		$	90,741		$	134,456		$	148,433

Net income (loss)																			$	1,927		$	(3,057	)	$	82,251		$	87,684		$	139,440		$	149,790


Other comprehensive income (loss), net of tax
Defined benefit pension plans:
Net actuarial gain (loss)		—			—			—			—			62,214			(46,409	)		—			—			—			—			62,214			(46,409	)
Amortization of prior service cost		55			54			110			109			221			109			55			55			165			164			221			164
Amortization of transition obligation		—			—			—			—			—			270			—			—			—			—			—			135
Amortization of net actuarial loss		3,666			5,298			7,333			10,596			17,927			18,530			3,667			5,297			11,000			15,893			16,297			19,861
Prior service cost		—			—			—			—			—			(1,502	)		—			—			—			—			—			(1,502	)
Regulatory adjustment		(3,210	)		(4,702	)		(6,420	)		(9,404	)		(73,667	)		24,366			(3,210	)		(4,701	)		(9,630	)		(14,105	)		(72,176	)		23,290

Net defined benefit pension plans		511			650			1,023			1,301			6,695			(4,636	)		512			651			1,535			1,952			6,556			(4,461	)

Forward-starting interest rate swaps:
Amounts reclassified into net income		519			519			1,037			1,037			2,074			2,074			518			518			1,555			1,555			2,074			2,074

Net forward-starting interest rate swaps		519			519			1,037			1,037			2,074			2,074			518			518			1,555			1,555			2,074			2,074

Total other comprehensive income (loss), net of tax		1,030			1,169			2,060			2,338			8,769			(2,562	)		1,030			1,169			3,090			3,507			8,630			(2,387	)

Comprehensive income		10,657			11,236			82,384			93,079			143,225			145,871
Comprehensive income (loss)																				2,957			(1,888	)		85,341			91,191			148,070			147,403
Comprehensive income (loss) attributable to noncontrolling interest		—			(41	)		(86	)		(140	)		(393	)		(536	)		(43	)		(193	)		(129	)		(333	)		(243	)		(620	)

Comprehensive income attributable to Southwest Gas Corporation	$	10,657		$	11,277		$	82,470		$	93,219		$	143,618		$	146,407
Comprehensive (loss) income attributable to Southwest Gas Corporation																			$	3,000		$	(1,695	)	$	85,470		$	91,524		$	148,313		$	148,023

Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) consist 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 for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. All of Southwest’s service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on operating margin. 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. 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 primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. Typically, NPL revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating revenues typically improve as more favorable weather conditions occur during the summer and fall months.

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 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 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 2013 Annual Report to Shareholders, which is incorporated by reference into the 2013 Form 10-K, and the first and second quarter 2014 reports on Form 10-Q.

Prepaids and other current assets. Prepaids and other current assets includes gas pipe inventory and operating supplies of ~~$23~~$24 million at ~~June~~September 30, 2014 and $21 million at December 31, 2013.

Cash and Cash Equivalents.For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. Cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. Upon contract expiration, customer advances of approximately ~~$5.6~~$7 million and ~~$4.8~~$7.9 million, during the first ~~six~~nine months of 2014 and 2013, respectively, were applied as contributions toward utility construction activity and represent non-cash investing activity.

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

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 Property and Investments.Other property and investments includes (millions of dollars):


							September 30, 2014			December 31, 2013
	June 30, 2014			December 31, 2013
NPL property and equipment	$	332		$	320		$	335		$	320
NPL accumulated provision for depreciation and amortization		(172	)		(163	)		(177	)		(163	)
Net cash surrender value of COLI policies		96			93			96			93
Other property		12			11			11			11

Total	$	268		$	261		$	265		$	261

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


																		Three Months Ended						Nine Months Ended					Twelve Months Ended
	Three Months Ended						Six Months Ended					Twelve Months Ended						September 30						September 30					September 30
	June 30						June 30					June 30						2014			2013			2014		2013			2014			2013
	2014			2013			2014		2013			2014			2013
Change in COLI policies	$	2,300		$	1,800		$	3,200	$	5,600		$	10,000		$	8,900		$	(300	)	$	2,500		$	2,900	$	8,100		$	7,200		$	9,200
Interest income		612			144			1,109		264			1,306			683			772			158			1,881		422			1,920			561
Pipe replacement costs		—			(36	)		—		(121	)		(11	)		(1,759	)		—			(42	)		—		(163	)		31			(828	)
Miscellaneous income and (expense)		(49	)		(456	)		166		(222	)		(41	)		(830	)		(32	)		52			134		(170	)		(125	)		(907	)

Total other income (deductions)	$	2,863		$	1,452		$	4,475	$	5,521		$	11,254		$	6,994		$	440		$	2,668		$	4,915	$	8,189		$	9,026		$	8,026

Included 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, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work. The replacement program work subject to non-recoverability was substantially completed in 2012.

Reclassifications. A reclassification was made to the prior year’s financial information between two categories on the Condensed Consolidated Statements of Comprehensive Income to present it on a basis comparable with the current year’s presentation, with no impact on comprehensive income overall.

Recently Issued Accounting Standards ~~Update.~~Updates. In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. The core principle of the update is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. The Company plans to adopt this update, as required, on January 1, 2017 for interim and annual reporting periods. Early adoption is not permitted. The Company is evaluating what impact this standard might have on its consolidated financial statements and disclosures.

In August 2014, the FASB issued the update “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which requires management to asses a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Under the update, disclosures are required when conditions give rise to substantial doubt about a company’s ability to continue as a going concern within one year from the financial statement issuance date. The update is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. This update is not expected to have a material impact on the Company’s disclosures.

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 care, and life insurance.

Net periodic benefit costs included in the table below are components of an overhead loading process associated with the cost of labor. The overhead process ultimately results in allocation of net periodic benefit costs to the same accounts to which productive labor is charged. As a result, net periodic benefit costs become components of various accounts, primarily operations and maintenance expense, net utility plant, and deferred charges and other assets.


																			Qualified Retirement Plan
	Qualified Retirement Plan																		Period Ended September 30,
	Period Ended June 30,																		Three Months						Nine Months						Twelve Months
	Three Months						Six Months						Twelve Months						2014			2013			2014			2013			2014			2013
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	5,340		$	5,764		$	10,680		$	11,528		$	22,208		$	21,688		$	5,340		$	5,764		$	16,020		$	17,292		$	21,784		$	22,372
Interest cost		10,860			9,402			21,721			18,803			40,525			37,936			10,860			9,402			32,581			28,205			41,983			37,771
Expected return on plan assets		(13,335	)		(12,460	)		(26,671	)		(24,920	)		(51,591	)		(47,810	)		(13,336	)		(12,460	)		(40,007	)		(37,380	)		(52,467	)		(48,825	)
Amortization of net actuarial loss		5,718			8,065			11,436			16,131			27,566			28,072			5,718			8,065			17,154			24,196			25,219			30,167

Net periodic benefit cost	$	8,583		$	10,771		$	17,166		$	21,542		$	38,708		$	39,886		$	8,582		$	10,771		$	25,748		$	32,313		$	36,519		$	41,485


	SERP																		SERP
	Period Ended June 30,																		Period Ended September 30,
	Three Months						Six Months						Twelve Months						Three Months						Nine Months						Twelve Months
																			2014			2013			2014			2013			2014			2013
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	73		$	93		$	146		$	187		$	332		$	324		$	73		$	93		$	219		$	280		$	312		$	348
Interest cost		436			384			872			767			1,640			1,582			436			384			1,308			1,151			1,692			1,559
Amortization of net actuarial loss		196			243			392			486			877			827			196			243			588			729			830			899

Net periodic benefit cost	$	705		$	720		$	1,410		$	1,440		$	2,849		$	2,733		$	705		$	720		$	2,115		$	2,160		$	2,834		$	2,806


																			PBOP
	PBOP																		Period Ended September 30,
	Period Ended June 30,																		Three Months						Nine Months						Twelve Months
	Three Months						Six Months						Twelve Months						2014			2013			2014			2013			2014			2013
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	275		$	305		$	551		$	610		$	1,161		$	1,098		$	275		$	305		$	826		$	915		$	1,131		$	1,159
Interest cost		708			621			1,415			1,241			2,656			2,515			707			620			2,122			1,861			2,743			2,498
Expected return on plan assets		(816	)		(706	)		(1,632	)		(1,412	)		(3,044	)		(2,614	)		(816	)		(706	)		(2,448	)		(2,118	)		(3,154	)		(2,719	)
Amortization of prior service cost		88			88			177			177			355			177			89			89			266			266			355			266
Amortization of transition obligation		—			—			—			—			—			434			—			—			—			—			—			217
Amortization of net actuarial loss		—			237			—			473			472			988			—			236			—			709			236			967

Net periodic benefit cost	$	255		$	545		$	511		$	1,089		$	1,600		$	2,598		$	255		$	544		$	766		$	1,633		$	1,311		$	2,388

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


	Natural Gas Operations		Construction Services		Total		Natural Gas Operations			Construction Services		Total
Three months ended June 30, 2014
Three months ended September 30, 2014
Revenues from external customers							$	226,027		$	183,290	$	409,317
Intersegment revenues								—			23,158		23,158

Total							$	226,027		$	206,448	$	432,475

Segment net income (loss)							$	(11,452	)	$	13,422	$	1,970


Three months ended September 30, 2013
Revenues from external customers							$	195,031		$	168,200	$	363,231
Intersegment revenues								—			24,115		24,115

Total							$	195,031		$	192,315	$	387,346

Segment net income (loss)							$	(11,939	)	$	9,075	$	(2,864	)


							Natural Gas Operations			Construction Services		Total
Nine months ended September 30, 2014
Revenues from external customers	$	271,479	$	156,966	$	428,445	$	983,999		$	438,409	$	1,422,408
Intersegment revenues		—		24,708		24,708		—			71,616		71,616

Total	$	271,479	$	181,674	$	453,153	$	983,999		$	510,025	$	1,494,024

Segment net income	$	1,798	$	7,829	$	9,627	$	62,945		$	19,435	$	82,380

Three months ended June 30, 2013

Nine months ended September 30, 2013
Revenues from external customers	$	238,869	$	150,434	$	389,303	$	927,500		$	423,500	$	1,351,000
Intersegment revenues		—		22,271		22,271		—			61,425		61,425

Total	$	238,869	$	172,705	$	411,574	$	927,500		$	484,925	$	1,412,425

Segment net income	$	1,964	$	8,144	$	10,108	$	69,317		$	18,700	$	88,017


							Natural Gas Operations			Construction Services		Total
Twelve months ended September 30, 2014
Revenues from external customers							$	1,356,653		$	577,384	$	1,934,037
Intersegment revenues								—			98,344		98,344

Total							$	1,356,653		$	675,728	$	2,032,381

Segment net income							$	117,797		$	21,886	$	139,683


Twelve months ended September 30, 2013
Revenues from external customers							$	1,267,025		$	552,032	$	1,819,057
Intersegment revenues								—			81,934		81,934

Total							$	1,267,025		$	633,966	$	1,900,991

Segment net income							$	121,327		$	29,083	$	150,410

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.

As part of the June 2013 Nevada Annual Rate Adjustment and associated stipulation, the Company agreed to suspend further Swaps and fixed-price purchases pursuant to the Volatility Mitigation Program for its Nevada service territories. The decision will not impact previously executed purchase agreements. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (up to approximately 35%, 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 ~~July~~October 2014 through March 2016. 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):

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

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the three-, ~~six-~~nine-, and twelve-month periods ended ~~June~~September 30, 2014 and 2013 and their location in the Condensed Consolidated Statements of Income (thousands of dollars):

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


Gains (losses) recognized in income for derivatives not designated as hedging instruments: (Thousands of dollars)																				Gains (losses) recognized in income for derivatives not designated as hedging instruments: (Thousands of dollars)
																						Three Months Ended						Nine Months Ended						Twelve Months Ended
		Three Months Ended						Six Months Ended						Twelve Months Ended							Location of Gain or (Loss)	September 30						September 30						September 30
Instrument	Location of Gain or (Loss) Recognized in Income on Derivative	June 30						June 30						June 30							Recognized in Income on Derivative	2014			2013			2014			2013			2014			2013
Instrument		2014			2013			2014			2013			2014			2013

Swaps	Net cost of gas sold	$	(83	)	$	(7,669	)	$	5,907		$	(2,593	)	$	9,476		$	(2,885	)		Net cost of gas sold	$	(2,277	)	$	(353	)	$	3,630		$	(2,946	)	$	7,552		$	(6,855	)
Swaps	Net cost of gas sold		83	*		7,669	*		(5,907	)*		2,593	*		(9,476	)*		2,885	*		Net cost of gas sold		2,277	*		353	*		(3,630	)*		2,946	*		(7,552	)*		6,855	*

Total		$	—		$	—		$	—		$	—		$	—		$	—				$	—		$	—		$	—		$	—		$	—		$	—

No gains (losses) were recognized, in income or other comprehensive income during the periods presented, for derivatives designated as cash flow hedging instruments. Previously, 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 issuance of fixed-rate debt. At settlement of the first FSIRS in December 2010, Southwest paid an aggregate $11.7 million to the counterparties. The second FSIRS terminated in March 2012 at which time Southwest paid counterparties an aggregate $21.8 million. The losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) and into interest expense.

The following table sets forth the fair values of the Company’s Swaps and their location in the Condensed Consolidated Balance Sheets (thousands of dollars):


June 30, 2014		Asset Derivatives				Liability Derivatives				Net Total
September 30, 2014					September 30, 2014					Net Total			Asset				Liability
Instrument	Balance Sheet Location	Asset Derivatives		Asset Derivatives		Liability Derivatives			Liability Derivatives				Net Total				Balance Sheet Location		Derivatives				Derivatives				Net Total
Swaps				Asset Derivatives				Deferred charges and other assets	Liability Derivatives				Net Total			$	124			$	(17	)		$	107
Swaps	Deferred charges and other assets	$	483			$	—			$	483			Prepaids and other current assets			198				(146	)			52
Swaps	Prepaids and other current assets		1,884				(140	)			1,744			Other current liabilities			174				(389	)			(215	)

Total		$	2,367			$	(140	)		$	2,227					$	496			$	(552	)		$	(56	)


December 31, 2013		Asset Derivatives				Liability Derivatives				Net Total			December 31, 2013			Asset				Liability
Instrument	Balance Sheet Location					Liability Derivatives				Net Total			Balance Sheet Location		Derivatives				Derivatives				Net Total
Swaps	Deferred charges and other assets	Asset Derivatives	$	257			$	(77	)		$	180			Deferred charges and other assets		$	257			$	(77	)		$	180
Swaps	Prepaids and other current assets		1,054				(253	)			801			Prepaids and other current assets			1,054				(253	)			801
Swaps	Other current liabilities		126				(282	)			(156	)		Other current liabilities			126				(282	)			(156	)
Swaps	Other deferred credits		7				(11	)			(4	)		Other deferred credits			7				(11	)			(4	)

Total		$	1,444			$	(623	)		$	821					$	1,444			$	(623	)		$	821

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. The Company had no outstanding collateral associated with the Swaps during either period shown in the above table.

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 mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of 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)	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014		Twelve Months Ended June 30, 2014		September 30, 2014		September 30, 2014		September 30, 2014
Paid to counterparties	$	—	$	15	$	2,291	$	71	$	86	$	2,020

Received from counterparties	$	196	$	4,515	$	4,522	$	78	$	4,593	$	4,593

The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the Condensed Consolidated Balance Sheets (thousands of dollars).


June 30, 2014 Instrument	Balance Sheet Location	Net Total
September 30, 2014					September 30, 2014
Instrument						Balance Sheet Location	Net Total
Swaps						Other deferred credits	$	(107	)
Swaps	Other deferred credits	$	(483	)		Other current liabilities		(52	)
Swaps	Other current liabilities		(1,744	)		Prepaids and other current assets		215

December 31, 2013 Instrument	Balance Sheet Location	Net Total
December 31, 2013					December 31, 2013
Instrument						Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(180	)		Other deferred credits	$	(180	)
Swaps	Other current liabilities		(801	)		Other current liabilities		(801	)
Swaps	Prepaids and other current assets		156			Prepaids and other current assets		156
Swaps	Deferred charges and other assets		4			Deferred charges and other assets		4

Fair Value ~~Measurements.~~Measurements. The estimated fair values of Southwest’s Swaps were determined at ~~June~~September 30, 2014 and December 31, 2013 using New York Mercantile Exchange (“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 (inputs, other than quoted prices, for similar assets or liabilities) 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 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 recorded at fair value:


(Thousands of dollars)	June 30, 2014		December 31, 2013			September 30, 2014			December 31, 2013

Assets at fair value:
Prepaids and other current assets - Swaps	$	1,744	$	801		$	52		$	801
Deferred charges and other assets - Swaps		483		180			107			180

Liabilities at fair value:
Other current liabilities - Swaps		—		(156	)		(215	)		(156	)
Other deferred credits - Swaps		—		(4	)		—			(4	)

Net Assets (Liabilities)	$	2,227	$	821		$	(56	)	$	821

No financial assets or liabilities accounted for at fair value fell within Level 1 (quoted prices in active markets for identical financial assets) or Level 3 (significant unobservable inputs) of the fair value hierarchy.

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of ~~June~~September 30, 2014 and December 31, 2013 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper), the NPL revolving credit facility, and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, and are categorized as Level 1 (quoted prices for identical financial instruments or liabilities that can be accessed at the measurement date) within thethree-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The market values of debentures (except the 6.1% Notes) and fixed-rate IDRBs are categorized as Level 2. The 6.1% Notes (private placement, not actively traded) and NPL other debt obligations (not actively traded) are categorized as Level 3 (based on significant unobservable inputs to their fair values). Fair values for the debentures, fixed-rate IDRBs, and NPL other debt obligations were determined through a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.


											September 30, 2014					December 31, 2013
											Carrying			Market		Carrying			Market
	June 30, 2014					December 31, 2013					Amount			Value		Amount			Value
(Thousands of dollars)	Carrying Amount			Market Value		Carrying Amount			Market Value
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	136,964	$	125,000		$	130,953	$	125,000		$	135,925	$	125,000		$	130,953
Notes, 6.1%, due 2041		125,000			157,689		125,000			141,873		125,000			155,978		125,000			141,873
Notes, 3.875%, due 2022		250,000			266,398		250,000			252,485		250,000			265,345		250,000			252,485
Notes, 4.875%, due 2043		250,000			277,840		250,000			257,280		250,000			275,035		250,000			257,280
8% Series, due 2026		75,000			104,001		75,000			96,263		75,000			103,548		75,000			96,263
Medium-term notes, 7.59% series, due 2017		25,000			28,539		25,000			28,741		25,000			28,151		25,000			28,741
Medium-term notes, 7.78% series, due 2022		25,000			32,116		25,000			30,586		25,000			31,814		25,000			30,586
Medium-term notes, 7.92% series, due 2027		25,000			34,194		25,000			31,497		25,000			34,066		25,000			31,497
Medium-term notes, 6.76% series, due 2027		7,500			9,259		7,500			8,468		7,500			9,240		7,500			8,468
Unamortized discount		(5,394	)				(5,560	)				(5,309	)				(5,560	)

		902,106					901,940					902,191					901,940

Revolving credit facility and commercial paper		—			—		10,000			10,000		50,000			50,000		10,000			10,000

Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000		50,000			50,000		50,000			50,000
Fixed-rate bonds:
5.25% 2003 Series D, due 2038		20,000			20,215		20,000			20,150		20,000			20,190		20,000			20,150
5.25% 2004 Series A, due 2034		65,000			65,041		65,000			64,522		65,000			64,929		65,000			64,522
5.00% 2004 Series B, due 2033		31,200			31,207		31,200			30,284		31,200			31,217		31,200			30,284
4.85% 2005 Series A, due 2035		100,000			99,934		100,000			95,192		100,000			100,935		100,000			95,192
4.75% 2006 Series A, due 2036		24,855			24,911		24,855			22,974		24,855			24,809		24,855			22,974
Unamortized discount		(2,710	)				(2,776	)				(2,679	)				(2,776	)

		438,345					438,279					438,376					438,279

NPL credit facility		12,529			12,529		—			—		24,500			24,500		—			—
NPL other debt obligations		36,687			36,851		42,213			42,119		33,904			33,993		42,213			42,119

		1,389,667					1,392,432					1,448,971					1,392,432
Less: current maturities		(23,741	)				(11,105	)				(11,265	)				(11,105	)

Long-term debt, less current maturities	$	1,365,926				$	1,381,327				$	1,437,706				$	1,381,327

In March 2014, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2017 and was extended to March 2019. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. In addition to extending the credit facility, among other amendments, the applicable margins and unused commitment fees were reduced and the

Pricing Level definitions were modified. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At ~~June~~September 30, 2014, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate.

Also in March 2014, the Company amended its 6.1% $125 million notes (“Notes”) note purchase agreement. The amendment modifies the Permitted Lien category permitting liens securing indebtedness not to exceed 10% of total capitalization as of the end of any quarter. This provision in the agreement prohibits liens on any property securing other indebtedness under bank facilities unless the Notes are secured in a similar manner. The provision was amended to clarify that it only applies to bank facilities of Southwest Gas Corporation.

In October 2014, construction services subsidiaries of the Company, including NPL, Isleworth Holding Co., and 2431251 Ontario, Inc. (collectively “Borrowers”) entered into a $300 million secured revolving credit and term loan facility. The facility is scheduled to expire in October 2019 and replaces NPL’s previous $75 million credit facility, which was scheduled to expire in June 2015. SeeNote 8 – Acquisition of Construction Services Businesses for more information. In October, NPL used available capacity under the new facility to refinance borrowings under its existing facility that were outstanding at September 30, 2014. Therefore, these borrowings are shown as long-term obligations.

Interest rates for the $300 million secured facility are calculated at the LIBOR, the Canadian Dealer Offered Rate (“CDOR”), or an alternate base rate or Canadian base rate, plus in each case an applicable margin that is determined based on the Borrowers’ consolidated leverage ratio. The applicable margin ranges from 1.00% to 2.25% for loans bearing interest with reference to LIBOR or CDOR and from 0.00% to 1.25% for loans bearing interest with reference to the alternate base rate or Canadian base rate. The Borrowers are also required to pay a commitment fee on the unfunded portion of the commitments based on the consolidated leverage ratio. The commitment fee ranges from 0.15% to 0.40% per annum.

In October 2014, notices were sent to holders of Southwest’s $65 million 2004 5.25% Series A fixed-rate IDRBs (originally due in 2034) that such IDRBs will be redeemed at par plus accrued interest in November 2014. Sufficient capacity exists on the long-term portion of Southwest’s credit facility which is intended to be used to fund the redemption. Therefore, the IDRBs being redeemed continue to be presented as long-term obligations.

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

The table below provides details of activity in equity during the ~~six~~nine months ended ~~June~~September 30, 2014.


																							Southwest Gas Corporation Equity
																															Accumulated
	Southwest Gas Corporation Equity														Non- controlling Interest				Total									Additional			Other								Non-
	Common Stock				Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings											Common Stock					Paid-in			Comprehensive				Retained				controlling
(In thousands, except per share amounts)	Shares		Amount															Shares						Amount		Capital			Income (Loss)			Earnings				Interest				Total
DECEMBER 31, 2013		46,356	$	47,986		$	840,521			$	(41,698	)		$		567,714				$	(2,128	)	$	1,412,395		46,356		$	47,986		$	840,521			$	(41,698	)		$	567,714		$	(2,128	)	$	1,412,395
Common stock issuances		147		147		4,330														4,477				162		162			5,606														5,768
Net income (loss)												80,410				(86	)			80,324																82,380				(129	)		82,251
Other comprehensive income (loss):
Net actuarial gain (loss) arising during period, less amortization of unamortized benefit plan cost, net of tax									1,023											1,023												1,535											1,535
Amounts reclassified to net income, net of tax (FSIRS)									1,037											1,037												1,555											1,555
Dividends declared
Common: $0.73 per share												(34,364	)							(34,364	)
Common: $1.095 per share																																				(51,542	)						(51,542	)

JUNE 30, 2014		46,503	$	48,133	$	844,851		$	(39,638	)	$	613,760			$	(2,214	)		$	1,464,892
SEPTEMBER 30, 2014																								46,518	$	48,148		$	846,127		$	(38,608	)		$	598,552			$	(2,257	)	$	1,451,962

The following information provides insight into amounts impacting Other Comprehensive Income (Loss), both before and after-tax, within the Condensed Consolidated Statements of Comprehensive Income, which also impact Accumulated Other Comprehensive Income in the Company’s Condensed Consolidated Balance Sheets and the associated column in the equity table above. See Note 4 – Derivatives and Fair Value Measurements for additional information on the FSIRS.

~~Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss)~~


	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013									Twelve Months Ended									Twelve Months Ended
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Amortization of net actuarial (gain)/loss	$	5,914		$	(2,248	)	$	3,666		$	8,545		$	(3,247	)	$	5,298
Amortization of prior service cost		88			(33	)		55			88			(34	)		54
Regulatory adjustment		(5,177	)		1,967			(3,210	)		(7,584	)		2,882			(4,702	)

Pension plans other comprehensive income (loss)		825			(314	)		511			1,049			(399	)		650

FSIRS (designated hedging activities):
Amounts reclassifed into net income		837			(318	)		519			837			(318	)		519

FSIRS other comprehensive income		837			(318	)		519			837			(318	)		519

Total other comprehensive income (loss)	$	1,662		$	(632	)	$	1,030		$	1,886		$	(717	)	$	1,169


	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Amortization of net actuarial (gain)/loss	$	11,828		$	(4,495	)	$	7,333		$	17,090		$	(6,494	)	$	10,596
Amortization of prior service cost		177			(67	)		110			177			(68	)		109
Regulatory adjustment		(10,355	)		3,935			(6,420	)		(15,168	)		5,764			(9,404	)

Pension plans other comprehensive income (loss)		1,650			(627	)		1,023			2,099			(798	)		1,301

FSIRS (designated hedging activities):
Amounts reclassifed into net income		1,673			(636	)		1,037			1,673			(636	)		1,037

FSIRS other comprehensive income		1,673			(636	)		1,037			1,673			(636	)		1,037

Total other comprehensive income (loss)	$	3,323		$	(1,263	)	$	2,060		$	3,772		$	(1,434	)	$	2,338
																			September 30, 2014									September 30, 2013
																			Before-			Tax			Net-of-			Before-			Tax			Net-of-
	Twelve Months Ended June 30, 2014									Twelve Months Ended June 30, 2013									Tax			(Expense)			Tax			Tax			(Expense)			Tax
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(134	)		221			177			(68	)		109			355			(134	)		221			266			(102	)		164
Amortization of transition obligation		—			—			—			434			(164	)		270			—			—			—			217			(82	)		135
Amortization of net actuarial (gain)/loss		28,915			(10,988	)		17,927			29,887			(11,357	)		18,530			26,285			(9,988	)		16,297			32,033			(12,172	)		19,861
Prior service cost		—			—			—			(2,423	)		921			(1,502	)		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		(118,817	)		45,150			(73,667	)		39,300			(14,934	)		24,366			(116,412	)		44,236			(72,176	)		37,564			(14,274	)		23,290

Pension plans other comprehensive income (loss)		10,798			(4,103	)		6,695			(7,478	)		2,842			(4,636	)		10,573			(4,017	)		6,556			(7,196	)		2,735			(4,461	)

FSIRS (designated hedging activities):
Amounts reclassifed into net income		3,345			(1,271	)		2,074			3,345			(1,271	)		2,074			3,345			(1,271	)		2,074			3,345			(1,271	)		2,074

FSIRS other comprehensive income (loss)		3,345			(1,271	)		2,074			3,345			(1,271	)		2,074			3,345			(1,271	)		2,074			3,345			(1,271	)		2,074

Total other comprehensive income (loss)	$	14,143		$	(5,374	)	$	8,769		$	(4,133	)	$	1,571		$	(2,562	)	$	13,918		$	(5,288	)	$	8,630		$	(3,851	)	$	1,464		$	(2,387	)

Tax amounts are calculated using a 38% rate.

Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, reported in Accumulated other comprehensive income (“AOCI”) at ~~June~~September 30, 2014, will be reclassified into interest expense within the next 12 months, as the related interest payments on long-term debt occur.

The following represents a rollforward of AOCI, presented on the Company’s Condensed Consolidated Balance Sheets:


AOCI - Rollforward (Thousands of dollars)																						AOCI - Rollforward (Thousands of dollars)
	Defined Benefit Plans									FSIRS													Defined Benefit Plans									FSIRS
	Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			AOCI				Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			AOCI
Beginning Balance AOCI December 31, 2013	$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	(41,698	)		$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	(41,698	)

Other comprehensive income before reclassifications		—			—			—			—			—			—			—				—			—			—			—			—			—			—
FSIRS amounts reclassified from AOCI (1)		—			—			—			1,673			(636	)		1,037			1,037				—			—			—			2,509			(954	)		1,555			1,555
Amortization of prior service cost (2)		177			(67	)		110			—			—			—			110				266			(101	)		165			—			—			—			165
Amortization of net actuarial loss (2)		11,828			(4,495	)		7,333			—			—			—			7,333				17,742			(6,742	)		11,000			—			—			—			11,000
Regulatory adjustment (3)		(10,355	)		3,935			(6,420	)		—			—			—			(6,420	)			(15,533	)		5,903			(9,630	)		—			—			—			(9,630	)

Net current period other comprehensive income (loss)		1,650			(627	)		1,023			1,673			(636	)		1,037			2,060				2,475			(940	)		1,535			2,509			(954	)		1,555			3,090

Ending Balance AOCI June 30, 2014	$	(39,573	)	$	15,038		$	(24,535	)	$	(24,360	)	$	9,257		$	(15,103	)	$	(39,638	)
Ending Balance AOCI September 30, 2014																							$	(38,748	)	$	14,725		$	(24,023	)	$	(23,524	)	$	8,939		$	(14,585	)	$	(38,608	)

The following table represents amounts (before income tax impacts) included in AOCI (in the table above), that have not yet been recognized in net periodic benefit cost:

In July 2014, the Company purchased for $16.5 million a portion of its corporate headquarters office complex in Las Vegas that it had previously leased. With the ~~closing~~completion of the purchase, the lease terminated.

In October 2014, the Company, through its subsidiaries, led principally by NPL, completed the acquisition of three privately held, affiliated construction businesses for approximately US$185 million including debt assumed. The acquisition will extend the construction services operations into Canada and provide additional opportunities for market expansion. Funding for the acquisition was primarily provided by a new $300 million secured revolving credit and term loan facility described below and inNote 5 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link Line”) that provides construction and maintenance services for the Canadian utility industry, with operations in Ontario, Canada; (ii) the holding company W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”; and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating in Pennsylvania as a specialty midstream pipeline contractor (“Brigadier”).

At ~~June 30, 2014,~~the close of the acquisition, certain of the principal previous owners of the acquired companies retained an approximate 10% indirect equity interest in Link-Line and W.S. Nicholls. The approximate 10% indirect equity interest of the principal sellers has special dividend rights which entitle the sellers as holders to payments equal to 3.4% of any cash dividend paid by NPL to the Company, and subject to certain conditions, such interests may become exchangeable for a 3.4% equity interest in a holding company for the Company’s entire construction services segment.

The Company is currently performing a detailed valuation analysis of the assets and liabilities of the acquired companies, which is expected to be completed during the fourth quarter of 2014. The analysis includes the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of acquired intangibles including customer relationships and trade names. Based on preliminary results, a substantial majority of the purchase price ~~plus related closing~~will be allocated to goodwill and other finite-lived and indefinite-lived intangibles. Including amortization of acquired intangibles and acquisition transaction costs, the acquired companies are expected to be accretive to earnings per share during the first twelve months of operations.

To facilitate the acquisition, in October 2014, construction services subsidiaries of the Company, including NPL, Isleworth Holding Co., and ~~fees were being held~~2431251 Ontario, Inc., entered into a $300 million secured revolving credit and term loan facility. The new credit facility is scheduled to expire in ~~escrow until the purchase~~October 2019 and replaces NPL’s previous $75 million credit facility, which was ~~consummated. This amount is shown as restricted cash on the condensed consolidated balance sheet at~~scheduled to expire in June ~~30, 2014.~~2015.

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 for customers in portions of Arizona, Nevada, and California. Southwest is the largest distributor of natural gas 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 for customers in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

As of ~~June~~September 30, 2014, Southwest had ~~1,910,000~~1,912,000 residential, commercial, industrial, and other natural gas customers, of which 1,023,000 customers were located in Arizona, ~~699,000~~701,000 in Nevada, and 188,000 in California. Residential and commercial customers represented over 99% of the total customer base. During the twelve months ended ~~June~~September 30, 2014, 56% of operating margin was earned in Arizona, 34% in Nevada, and 10% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% 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 affecting changes in operating margin are general rate relief and customer growth. All of Southwest’s service territories have decoupled rate structures, which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of weather variability and conservation on margin, allowing the Company to aggressively pursue energy efficiency initiatives.

NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in 20 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented or modified pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with previous bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the country. Generally, revenues are lowest during the first quarter of the year due to less favorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. In certain circumstances, such as with large, longer duration bid contracts, or unit-price contracts with caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid. In October 2014, NPL expanded its operations into Canada through the acquisition of Link Line and W.S. Nicholls. In connection with the acquisition, Brigadier, a U.S. business, was also acquired.

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 MD&A included in the 2013 Annual Report to Shareholders, which is incorporated by reference into the 2013 Form 10-K, and the first and second quarter 2014 reports on Form10-Q.

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 ~~84%~~82% 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 results for a full year.


	Period Ended June 30,												Period Ended September 30,
	Three Months				Six Months				Twelve Months				Three Months						Nine Months				Twelve Months
	2014		2013		2014		2013		2014		2013		2014			2013			2014		2013		2014		2013
	(In thousands, except per share amounts)												(In thousands, except per share amounts)
Contribution to net income
Contribution to net income (loss)
Natural gas operations	$	1,798	$	1,964	$	74,397	$	81,256	$	117,310	$	121,877	$	(11,452	)	$	(11,939	)	$	62,945	$	69,317	$	117,797	$	121,327
Construction services		7,829		8,144		6,013		9,625		17,539		27,092		13,422			9,075			19,435		18,700		21,886		29,083

Net income	$	9,627	$	10,108	$	80,410	$	90,881	$	134,849	$	148,969
Net income (loss)													$	1,970		$	(2,864	)	$	82,380	$	88,017	$	139,683	$	150,410

Average number of common shares outstanding		46,502		46,331		46,471		46,291		46,407		46,214		46,513			46,337			46,485		46,306		46,451		46,265

Basic earnings per share
Basic earnings (loss) per share
Consolidated	$	0.21	$	0.22	$	1.73	$	1.96	$	2.91	$	3.22	$	0.04		$	(0.06	)	$	1.77	$	1.90	$	3.01	$	3.25

Natural Gas Operations
Operating margin	$	173,494	$	169,481	$	468,610	$	462,473	$	870,290	$	852,675	$	153,040		$	147,285		$	621,650	$	609,758	$	876,045	$	857,664

~~California General Rate Case.~~Effective June 2014, Southwest received general rate relief in California. The California Public Utilities Commission (“CPUC”) decision authorized an overall annualized increase of $7.1 million. See~~Rates and Regulatory Proceedings~~ ~~for more information.~~

Customer Growth.Southwest completed 20,000 first-time meter sets, but realized ~~28,000~~29,000 net new customers over the last twelve months, an increase of 1.5%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for 2014.

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 ~~$240~~$237 million at ~~June~~September 30, 2014. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately ~~$96.2~~$96.1 million at ~~June~~September 30, 2014 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration and purchase additional policies as necessary. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. 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 of the Notes to Condensed Consolidated Financial Statements, cash surrender values of COLI policies ~~increased $2.3 million~~(including incremental death benefits) decreased $300,000 in the ~~second~~third quarter of 2014, ~~$3.2~~increased $2.9 million in the first ~~six~~nine months of 2014, and ~~$10~~increased $7.2 million ~~(including incremental death benefits)~~ during the twelve months ended ~~June~~September 30, 2014. Management currently expects average returns of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized, although in any given period, losses are possible.

Credit Rating Downgrade. In October 2014, Standard & Poor’s Ratings Services (“S&P”) downgraded the Company’s unsecured long-term debt ratings from A- to BBB+ (with a stable outlook). S&P cited the Company’s acquisition of Link-Line, W.S. Nicholls, and Brigadier, which increases the relative size of the higher-risk construction services business segment. 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 May 2013, Fitch Ratings rated the Company’s senior unsecured debt as A. In January 2014, Moody’s Investors Service, Inc. rated the Company’s senior unsecured debt as A3.

Liquidity.Southwest believes its liquidity position is solid. Southwest has a $300 million credit facility maturing in March 2019. The facility is provided through a consortium of eight major banking institutions. ~~No borrowings were~~The maximum amount outstanding on the credit facility (including a commercial paper program) ~~at any time~~ during the ~~second~~third quarter of ~~2014.~~2014 was $50 million. At ~~June~~September 30, 2014, ~~no borrowings were~~$50 million was outstanding on the commercial paper program. In November 2014, the Company plans to redeem the $65 million 5.25% 2004 Series A IDRBs and anticipates using available capacity on the long-term ~~or short-term portions~~portion of its credit facility to complete the ~~credit facility.~~redemption. Southwest has no significant debt maturities prior to 2017.

The contribution to consolidated net income from natural gas operations decreased $166,000 in the second quarter of 2014 compared to the second quarter of 2013. The decline was primarily due to increases in operating expenses and net interest deductions, partially offset by increases in operating margin and other income.

Operating margin increased $4$6 million between quarters including approximately $2$5 million of rate relief in California due to a final decision in the California general rate case (seeRates and Regulatory Proceedings). New customers contributed $2$1 million in operating margin during the ~~second~~third quarter of 2014, as approximately ~~28,000~~29,000 net new customers were added during the last twelve months.

Operations and maintenance expense ~~increased $2.7~~decreased $2.6 million, or 3%, between quarters. ~~Increases in general costs and expense related to reserves for uncollectible accounts were mitigated by declines~~Declines in employee-related costs, including pension ~~expense.~~expense, were partially offset by increases in general costs.

Depreciation and amortization expense increased ~~$2.8~~$2.1 million, or 6%4% between quarters. Average gas plant in service for the current quarter increased ~~$290~~$306 million, or 6%, compared to the corresponding quarter a year ago. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in California.

Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, ~~increased $1.4~~decreased $2.2 million between quarters. The current quarter reflects COLI policy cash surrender value ~~increases~~decreases of ~~$2.3 million,~~$300,000 (net of death benefits recognized), while the prior-year quarter included ~~$1.8~~$2.5 million in COLI-related ~~income and net death benefits recognized.~~income. In addition, interest income on deferred PGA balances increased between quarters due to ~~under-collected~~ PGA balances that were under collected in the current ~~quarter.~~period.

Net interest deductions increased ~~$2.2~~$2.4 million between quarters, primarily due to the issuance of $250 million of long-term debt in the fourth quarter of 2013. The increase was mitigated by higher interest expense in the prior-year quarter associated with over-collected deferred PGA balances.

The income tax benefit in the second quarter of 2014 reflects the impact of permanent differences (primarily nontaxable COLI increases) relative to the small seasonal pretax income and is not indicative of the expected effective rate for a full year.


	Six Months Ended June 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	757,972	$	732,469	$	983,999	$	927,500
Net cost of gas sold		289,362		269,996		362,349		317,742

Operating margin		468,610		462,473		621,650		609,758
Operations and maintenance expense		200,028		192,022		293,417		288,003
Depreciation and amortization		102,007		96,065		152,540		144,492
Taxes other than income taxes		22,421		22,868		34,256		34,021

Operating income		144,154		151,518		141,437		143,242
Other income (deductions)		4,460		5,511		4,902		8,174
Net interest deductions		34,286		30,564		51,445		45,344

Income before income taxes		114,328		126,465		94,894		106,072
Income tax expense		39,931		45,209		31,949		36,755

Contribution to consolidated net income	$	74,397	$	81,256	$	62,945	$	69,317

The contribution to consolidated net income from natural gas operations decreased ~~$6.9~~$6.4 million in the first ~~six~~nine months of 2014 compared to the same period a year ago. The decline was primarily due to increases in operating expenses and net interest deductions and a decrease in other income, partially offset by an increase in operating margin.

Operating margin increased $6$12 million between periods including approximately $2$7 million of rate relief in California (seeRates and Regulatory Proceedings). New customers contributed $5$6 million in operating margin during the first ~~six~~nine months of 2014. ~~The increase was partially offset by a $1 million~~Operating margin ~~decrease~~ associated with customers outside the decoupling mechanisms and ~~lower~~ other miscellaneous ~~revenues.~~revenues declined by $1 million.

Operations and maintenance expense increased $8$5.4 million, or 4%2%, between periods primarily due to a $5 million legal accrual in the first quarter of 2014. General cost increases were ~~partially~~largely offset by declines in employee-related costs, including pension expense.

Depreciation and amortization expense increased ~~$5.9~~$8 million, or 6% between periods. Average gas plant in service for the current period increased ~~$279~~$289 million, or 6%, compared to the corresponding period a year ago. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Amortization associated with the recovery of regulatory assets increased approximately ~~$1 million.~~$900,000 (primarily due to Arizona demand-side management, or “DSM” programs).

Other income decreased ~~$1.1~~$3.3 million between periods. The current period reflects COLI policy cash surrender value increases of ~~$3.2~~$2.9 million, while the prior-year period included ~~$5.6~~$8.1 million in COLI-related ~~income and~~income. Amounts for both periods included net death benefits recognized. Interest income on deferred PGA balances increased between periods due to under-collected PGA balances in the current period.

Net interest deductions increased ~~$3.7~~$6.1 million between periods, primarily due to the issuance of $250 million of long-term debt in the fourth quarter of 2013. The increase was mitigated by higher interest expense in the prior-year period associated with over-collected deferred PGA balances.


	Twelve Months Ended June 30,				Twelve Months Ended September 30,
	2014		2013		2014		2013
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	1,325,657	$	1,267,567	$	1,356,653	$	1,267,025
Net cost of gas sold		455,367		414,892		480,608		409,361

Operating margin		870,290		852,675		876,045		857,664
Operations and maintenance expense		392,920		374,267		390,328		379,621
Depreciation and amortization		199,790		189,435		201,896		191,099
Taxes other than income taxes		45,104		44,131		45,786		44,684

Operating income		232,476		244,842		238,035		242,260
Other income (deductions)		11,210		6,990		8,989		8,022
Net interest deductions		66,277		62,518		68,656		61,224

Income before income taxes		177,409		189,314		178,368		189,058
Income tax expense		60,099		67,437		60,571		67,731

Contribution to consolidated net income	$	117,310	$	121,877	$	117,797	$	121,327

The contribution to consolidated net income from natural gas operations decreased ~~$4.6~~$3.5 million between the twelve-month periods of 2014 and 2013. The decline was primarily due to increases in operating expenses and net interest deductions, partially offset by ~~increases~~an increase in operating ~~margin and other income.~~margin.

Operating margin increased ~~nearly~~ $18 million between periods including $6$9 million of combined rate relief. Customer growth contributed $8 million toward the increase. Incremental margin from customers outside the decoupling mechanisms and other miscellaneous revenues (including amounts associated with recoveries of Arizona regulatory assets) contributed the remainder of the increase.

Operations and maintenance expense increased ~~$18.7~~$10.7 million, or 5%3%, between periods primarily due to higher general costs and legal accruals and expenses (including $5 million in the first quarter of 2014), ~~and uncollectible accounts expense,~~ partially offset by declines in employee-related costs, including pension expense.

Depreciation and amortization expense increased ~~$10.4~~$10.8 million, or 5%6% between periods. Average gas plant in service for the current period increased ~~$256~~$275 million, or 5%, as compared to the prior-year period. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. ~~Increases in depreciation from these plant additions were partially offset by lower depreciation rates in Nevada (effective November 2012).~~ Amortization associated with the recovery of ~~Arizona~~ regulatory assets, ~~conservation and energy efficiency~~notably Arizona DSM programs, ~~in Nevada, and other amortization collectively~~ increased ~~$4.5~~$3.2 million.

Taxes other than income taxes increased $1$1.1 million between periods due to higher property taxes in Arizona and ~~changes resulting from the most recent Nevada general rate case, whereby modified business and mill taxes became components of operating expenses.~~Nevada.

Other income increased ~~$4.2 million~~$967,000 between the twelve-month periods of 2014 and 2013. The current period reflects a ~~$10~~$7.2 million increase in COLI policy cash surrender values including net death benefits recognized, while the prior twelve-month period reflected a ~~$8.9~~$9.2 million increase in COLI-related income and net death benefits recognized. Interest income increased $1.4 million between periods primarily due to the higher PGA balance receivable in 2014. In addition, Arizona non-recoverable pipe replacement costs were ~~$1.7 million~~$859,000 lower in the current twelve-month period as this pipe replacement activity was substantially completed in 2012.

Net interest deductions increased ~~$3.8~~$7.4 million between the twelve-month periods of 2014 and 2013 primarily due to interest costs associated with the issuance of debt in the fourth quarter of 2013, partially offset by cost savings from 2013 debt refinancing and redemptions, and lower interest expense associated with deferred PGA balances payable.

Operating margin for 2014 is expected to be favorably influenced by customer growth similar to 2013. ~~Rate relief from~~A proportionate share of Paiute’s recent settlement rate increase is anticipated during the ~~California rate case decision, effective June 2014, is expected to provide approximately $5 million of incremental margin in the second half~~fourth quarter of 2014 (seeRates and Regulatory Proceedings). Rate relief from the recent California rate case decision has been largely recognized and incremental margin (above 2013 levels) for the fourth quarter of 2014 will not be significant.

Operating expenses for 2014 compared to 2013 will continue to be impacted by inflation, general cost increases, and depreciation expense on plant additions. Incremental costs, offset by a $9 million annualized decrease in pension costs (approximately $7 million to be reflected in operations and maintenance expense), are expected to result in an overall operating expense increase of approximately 3%, including the legal accrual recorded in the first quarter of 2014.

COLI-related income of ~~$3.2~~$2.9 million for the first ~~half~~nine months of 2014 is ~~slightly higher than anticipated. Southwest expects longer term normal changes in COLI cash surrender values to~~consistent on a proportionate basis with Southwest’s estimated annual range ~~from~~of $3 million to $5 ~~million on an annual basis.~~million. However, individual quarterly and annual periods will likely continue to be subject to volatility.

Southwest anticipates an approximate ~~$5 million to~~ $6 million increase in net interest deductions in 2014 compared to 2013 primarily due to the October 2013 issuance of $250 million of 4.875% senior notes, partially offset by interest savings associated with the ~~redemptions that occurred during 2013.~~planned IDRB redemption in November 2014.

Infrastructure tracker mechanisms in Nevada and Arizona are expected to contribute modestly to 2014 operating results and trend upward over the next several years.


	Three Months Ended June 30,					Six Months Ended June 30,						Twelve Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,						Twelve Months Ended September 30,
	2014		2013			2014			2013			2014			2013			2014			2013			2014			2013			2014			2013
(Thousands of dollars)
Construction revenues	$	181,674	$	172,705		$	303,577		$	292,610		$	661,595		$	617,877		$	206,448		$	192,315		$	510,025		$	484,925		$	675,728		$	633,966
Operating expenses:
Construction expenses		157,642		148,700			270,841			255,388			588,737			532,106			173,937			167,581			444,778			422,969			595,093			545,420
Depreciation and amortization		11,662		10,824			23,070			21,438			44,601			41,790			11,504			10,317			34,574			31,755			45,788			42,152

Operating income		12,370		13,181			9,666			15,784			28,257			43,981			21,007			14,417			30,673			30,201			34,847			46,394
Other income (deductions)		15		4			15			10			44			4			(2	)		5			13			15			37			4
Net interest deductions		246		404			538			604			1,079			1,259			262			317			800			921			1,024			1,240

Income before income taxes		12,139		12,781			9,143			15,190			27,222			42,726			20,743			14,105			29,886			29,295			33,860			45,158
Income tax expense		4,310		4,678			3,216			5,705			10,076			16,170			7,364			5,223			10,580			10,928			12,217			16,695

Net income		7,829		8,103			5,927			9,485			17,146			26,556			13,379			8,882			19,306			18,367			21,643			28,463
Net income (loss) attributable to noncontrolling interest		—		(41	)		(86	)		(140	)		(393	)		(536	)		(43	)		(193	)		(129	)		(333	)		(243	)		(620	)

Contribution to consolidated net income attributable to NPL	$	7,829	$	8,144		$	6,013		$	9,625		$	17,539		$	27,092		$	13,422		$	9,075		$	19,435		$	18,700		$	21,886		$	29,083

Quarterly Analysis.Contribution to consolidated net income from construction services for the three months ended ~~June~~September 30, 2014 ~~decreased $315,000~~increased $4.3 million compared to the same period of ~~2013 primarily due to increased depreciation and amortization expense offset by lower interest expense.~~2013.

Revenues increased $9$14.1 million when compared to the ~~second~~third quarter of 2013 primarily due to incremental work ~~with~~from increased capital spending by several existing customers, ~~and progress on~~substantial completion of the accumulation of delayed work under blanket contracts carried over from the first ~~quarter.~~and second quarters, and increased bid work. Construction expenses increased ~~$8.9~~$6.4 million between quarters, primarily due to the above revenue growth. General and administrative expenses (included in construction expenses) include $1.2 million of transaction costs related to the business acquisition of Link-Line, W.S. Nicholls, and Brigadier, which was completed in October 2014. Depreciation expense increased $838,000 due to new equipment purchases. Gains on sale of equipment (reflected as an offset to construction expenses) were $1.7 million and $1.5 million for the second quarters of 2014 and 2013, respectively.

~~Six-Month Analysis.~~Contribution to consolidated net income from construction services for the six months ended June 30, 2014 decreased $3.6 million compared to the same period of 2013 primarily due to the impacts of severe winter weather conditions in the Midwest and East Coast during the first quarter of 2014.

Revenues increased $11 million when compared to the first half of 2013 primarily due to several bid projects that were started in late 2013 and an increase in the amount of work with several customers. This increase was partially offset by a reduction in revenue due to extreme winter weather conditions during the first quarter of 2014, which hindered normal construction work in the Midwest and East Coast operating areas. Construction expenses increased $15.5 million between periods, primarily due to the above noted projects. Additionally, the delay or suspension of projects due to adverse weather conditions during the first quarter of 2014 did not result in a ratable reduction in costs in relation to the revenue impacts. Depreciation expense increased $1.6$1.2 million due to new equipment purchases. Gains on sale of equipment (reflected as an offset to construction expenses) were ~~$4.1~~$1.5 million and ~~$2.3~~$704,000 for the third quarters of 2014 and 2013, respectively.

Nine-Month Analysis. Contribution to consolidated net income from construction services for the nine months ended September 30, 2014 increased $735,000 compared to the same period of 2013.

Revenues increased $25.1 million when compared to the first nine months of 2013 primarily due to increased replacement construction work. Increased construction activity in the second and third quarters substantially offset work that was delayed in the first quarter due to unfavorable weather conditions. Construction expenses increased $21.8 million between periods, primarily due to the items noted above, partially offset by greater gains on sale of equipment. General and administrative expense (included in construction expenses) includes $1.4 million of transaction costs related to the business acquisition which was completed in October 2014. Depreciation expense increased $2.8 million due to new equipment purchases. Gains on sale of equipment (reflected as an offset to construction expenses) were $5.7 million and $3 million for the first ~~six~~nine months of 2014 and 2013, respectively.

Twelve-Month Analysis. The contribution to consolidated net income from construction services for thetwelve-month period ended ~~June~~September 30, 2014 decreased ~~$9.6~~$7.2 million compared to the same period of 2013.

Revenues increased ~~$43.7~~$41.8 million due primarily to an increase in utility customer contracts for pipe replacement ~~work partially offset by lower revenues due to adverse weather conditions as discussed in the six-month analysis above.~~work. Included in the prior period was $3 million of revenue associated with fourth quarter 2012 approved change orders on a large fixed-price pipeline replacement contract. Construction expenses increased ~~$56.6~~$49.7 million between twelve-month periods primarily due to costs associated with the increase in pipe replacement construction work. General and administrative expense (included in construction expenses) increased ~~$7.5~~$6.8 million due to changes that were implemented to match NPL’s increased size and business ~~complexity.~~complexity and transaction costs ($1.4 million) related to the business acquisition which was completed in October 2014. In addition, NPL recorded approximately $4$2.7 million in the ~~second half~~fourth quarter of 2013 associated with a legal settlement. Depreciation expense increased ~~$2.8~~$3.6 million due to additional equipment purchased to support growth in the volume of work being performed. Gains on sale of equipment (reflected as an offset to construction expenses) were $6$6.8 million and $7$6.5 million for the twelve-month periods of 2014 and 2013, respectively.

During the past several years, NPL has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For both the twelve months ended ~~June~~September 30, 2014 and 2013, revenues from replacement work were approximately 70% of total revenues. Federal and state pipeline safety-related programs and prior bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. NPL continues to successfully bid on pipe replacement projects throughout the country.

In October 2014, the Company, led principally by NPL, acquired Link-Line, W.S. Nicholls, and Brigadier for approximately US$185 million including debt assumed. Funding for the acquisition was primarily provided by a new $300 million secured revolving credit and term loan facility (seeNote 5 – Long-Term Debt for additional information). Link-Line has approximately 700 employees and is one of the largest natural gas distribution contractors in Canada, with operations primarily in the province of Ontario. W.S. Nicholls has approximately 300 employees and provides fabrication and multi-trade services for industrial projects in the province of Ontario and western Canada. Brigadier has approximately 100 employees and performs midstream construction primarily in Pennsylvania. When combined with NPL, the acquisition creates one of the largest underground natural gas distribution contractors in North America. For 2013, revenues and operating income for the acquired companies were approximately US$250 million and US$16 million, respectively, or approximately 40% of the respective amounts for these line items of NPL. In connection with the acquisition, NPL incurred approximately $1.4 million in acquisition-related costs through September. Additional transaction-related expenses of approximately $3 million are anticipated in the fourth quarter of 2014. These costs are expected to be largely offset by operating income generated during the fourth quarter by the acquired companies.

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 are lowest during the first quarter of the year due to ~~unfavorable~~ winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. The current low interest rate environment, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on NPL’s revenues.

With the completion of the acquisition, management has ~~an improved infrastructure in place~~a larger base on which to grow the business and ~~is seeking~~will continue to seek to increase revenues by approximately 5% to 8% annually on average over the long term. Ultimately, revenues are subject to the timing and amount of work awarded ~~to NPL~~ by ~~its~~ utility ~~customers. As~~customers and success or failure of winning jobs in a competitive bid environment. It is anticipated that earnings generated by the acquired companies will substantially offset the additional acquisition-related costs, noted above, ~~extreme winter weather conditions~~ during the ~~first quarter of 2014 hindered normal~~fourth quarter. Therefore, management expects that construction work in the Midwest and East Coast operating areas. Weather conditions improved in the second quarter of 2014 and NPL is moving forward in an expedited manner to complete delayed work available under blanket contracts. Management remains cautiously optimistic that NPLservices earnings for the full year 2014 will ~~be consistent with, or~~modestly exceed 2013 results.

In 2015, the acquired companies are expected to be accretive to net income after taking into consideration amortization costs associated with acquired intangible assets and related financing costs.

California General Rate Case. In December 2012, Southwest Gas Corporation (“Southwest”) filed a general rate case application, based on a 2014 future test year, with the California Public Utilities Commission (“CPUC”) requesting an annual revenue increase of approximately $11.6 million for its California rate jurisdictions. Southwest sought to continue a Post-Test Year (“PTY”) Ratemaking Mechanism, which allows for annual attrition increases. The application included a request to establish a Customer-Owned Yardline (“COYL”) program and an Infrastructure Reliability and Replacement Adjustment Mechanism (“IRRAM”) to facilitate and complement projects involving the enhancement and replacement of gas infrastructure, promoting timely cost recovery for qualifying non-revenue producing capital expenditures.

In June 2014, the CPUC issued a final decision in this proceeding (“Decision”) authorizing a $7.1 million overall revenue increase and PTY attrition increases of 2.75% annually for 2015 to 2018. A depreciation reduction of $3.1 million as requested by Southwest was also approved. The Decision also provides for a two-way pension balancing account to track differences between authorized and actual pension funding amounts, a limited COYL inspection program for schools, and an IRRAM to recover the costs associated with the new limited COYL program. New rates associated with the Decision were effective June ~~2014. In addition to amounts recognized in the second quarter, the Decision is expected to provide approximately $5 million of additional margin in the second half of~~ 2014.

Nevada Infrastructure Replacement Mechanisms. As part of the Nevada general rate case application in April 2012, Southwest requested to implement an infrastructure replacement mechanism to defer and recover certain costs associated with up to $40 million annually of proposed accelerated replacement of early vintage plastic (“EVPP”) and steel pipe. As part of its fourth quarter 2012 decision, the PUCN indicated a separate rulemaking docket would be needed to address the regulatory issues necessary to implement such a mechanism. In January 2013, the PUCN authorized the opening of a new docket to review the merits of such mechanisms. Draft regulation provided for the establishment of regulatory assets that recover the depreciation expense and authorized pre-tax rate of return of infrastructure replacement investments between rate cases, which would allow Southwest to develop rates to recover the associated amounts in a future general rate case proceeding, at which time the plant would be “rolled into” rate base naturally. In January 2014, the PUCN concluded the rulemaking process by approving final rules, with only slight modifications to earlier proposed rules.

Separately, in March 2013, Southwest submitted a petition to the PUCN requesting authority to defer certain costs associated with the proposed accelerated 2013 replacement of certain EVPP to coincide with bonus depreciation tax relief extended by The American Taxpayer Relief Act of 2012. In June 2013, a stipulation (the “Stipulation”), which provided regulatory asset treatment for specific infrastructure replacement projects occurring during 2013 in the amount of $2 million in northern Nevada and approximately $13.6 million in southern Nevada, was reached by all parties and was approved by the PUCN. While the above-noted infrastructure replacement regulation was being finalized, the Company submitted a filing to the PUCN in November 2013 requesting authority to replace $18.9 million of EVPP in 2014; the PUCN approved the request in January 2014. The new rules (noted in the ~~preceding~~ paragraph above) enabled the Company to make a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying projects for replacement beginning in January 2015. The PUCN issued a final decision on this application in October 2014, approving EVPP replacement expenditures of $14.4 million in 2015. Also in October 2014, Southwest filed its first GIR rate application to request a surcharge to recover cumulative deferrals through August 2014, which were established through five separate regulatory dockets. Southwest requested this surcharge to be effective for both the southern and northern Nevada rate jurisdictions in January 2015.

Effectively, as a result of these mechanisms, the increase in depreciation expense, ordinarily arising from related capital expenditures, will be netted to zero for approved projects, by the deferral process, between general rate cases. Incremental ~~operating margin~~earnings associated with the equity portion of return related to these infrastructure replacements will materialize ~~after the PUCN authorizes~~through billed rates, once a surcharge ~~anticipated to commence during the first quarter of 2016.~~is established.

Arizona COYL Program. The Company received approval, in connection with its most recent Arizona general rate case, to implement a program to conduct leak surveys, and if leaks were present, to replace and relocate service lines and meters for approximately 100,000 Arizona customers whose meters are setoff from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously responsible for the cost of maintaining these lines and were subject to the immediate cessation of natural gas service if low-pressure leaks occurred. To facilitate this program, the Company was authorized to collect estimated leak survey costs in rates commencing in 2012. Effective June 2013, the Arizona Corporation Commission “ACC” authorized a surcharge of $0.00101 per therm to recover the costs of depreciation and pre-tax return the Company would have received if the additional pipe replacement costs themselves had been included in rate base concurrent with the most recent Arizona rate case. The surcharge is expected to be revised annually as the program progresses, with the undepreciated plant

balance to be incorporated in rate base ~~rates~~ at the time of the next Arizona general rate case. In November 2013, the Company filed a request to modify or clarify the COYL provision to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. This request was approved by the ACC in January 2014, and requires that these replacements be coordinated with the Company’s other pipeline replacement projects and that the Company will prioritize leaking COYLs over non-leaking COYLs. A revised surcharge request, filed in February 2014, which proposed to increase COYL cost recovery to approximately $1.5 million annually was approved effective June 2014 (through an updated surcharge of $0.00231 per therm). ~~Approximately 98%~~As of ~~COYL~~September 30, 2014, an offer of a survey has been made to all COYL-eligible customers ~~were contacted for testing through June 2014. Through these efforts, approximately 5,000~~originally identified under Phase I, resulting in more than 5,400 meter relocations since the inception of the program. With the completion of Phase I customer contact, resources are now focused on contacting customers within replacement project areas to participate in the Phase II meter relocation. To date, over 300 customers have ~~been completed or are in progress.~~committed to meter relocations under Phase II.

Proposed LNG Facility.In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. Such an LNG facility would be designed to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system) not to exceed $55 million. The proposed LNG facility would provide a local storage option, operated by Southwest and connected directly to its distribution system, providing greater flexibility to serve customers. Two options were presented in the ACC filing to fill the storage tank; either transferring LNG from tanker trucks or to liquefy the natural gas onsite. The liquefaction option would require the installation of equipment during the construction of the facility, which would provide operational and service flexibility benefits, at an additional cost of approximately $24 million and an estimated additional six months to construct. An ACC decision is expected to occur during 2014. If approved, construction is expected to be complete within approximately 24 to 30 months following ACC approval.

Federal Energy Regulatory Commission (“FERC”) Jurisdiction. During the second and third quarters of 2013, Paiute Pipeline Company, a wholly owned subsidiary of Southwest, notified present and potential shippers of its plans to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area. This additional capacity is required to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. Through the “open season” process, shippers responded with substantial interest. Dependent upon several variables, including the ultimate route of the project, the price of labor and materials, and factors such as environmental impacts, the cost to complete this project has been estimated at approximately $35 million and has a targeted in-service date of November 2015 (contingent upon FERC action). In October 2013, Paiute submitted a filing with the FERC requesting that its Staff initiate a pre-filing review of the proposed expansion project; a certificate application for the project was filed in June 2014. In October 2014, the FERC issued a notice of schedule for environmental review for this project. Based on the FERC’s schedule, and the resulting associated deadlines, the FERC is expected to issue a decision on Paiute’s certificate application in the first half of 2015.

Paiute Pipeline Company filed a general rate case with the FERC in February 2014. The filing fulfilled an obligation from the settlement agreement reached in the 2009 Paiute general rate case. The application requested an increase in operating revenues of approximately $9 million, and included a proposed change in rate design, which would compensate Paiute with a higher return if shippers desire to maintain shorter-lived contracts and, therefore, would incent shippers to sign longer term service agreements. A

In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle its general rate case. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement, which is being drafted by the parties for filing with the FERC in November 2014, would result in a revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. This increase is based on an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed not to file a rate case prior to May 2016, but no later than May 2019.

In October 2014, Paiute requested, and was granted, the authority to place the settlement rates into effect on an interim basis effective September 2014. These rates will remain in effect, subject to final ~~decision has~~FERC approval, which is expected late in the first quarter of 2015. Should the proceeding not ~~been rendered~~be resolved by the agreement in principle, or if the settlement proceeds as a contested settlement, Paiute is authorized to receive the difference between the interim settlement rates and the ~~parties~~separately filed motion rates from affected customers, retroactive to ~~the case are in settlement discussions. In accordance with FERC requirements, new rates will go into effect in~~ September 2014 (based on contracts then in effect), subject to refund, if a settlement among the parties has not been approved by the FERC by that time, and hearings would then be conducted in early 2015. Paiute’s previous general rate case was filed in 2009.2014.

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 ~~June~~September 30, 2014, under-collections in all three states resulted in an asset of ~~$80.4~~$78.3 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~~components, which include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

The following table presents Southwest’s outstanding PGA balances receivable/(payable) (millions of dollars):


	June 30, 2014		December 31, 2013		June 30, 2013			September 30, 2014		December 31, 2013		September 30, 2013
Arizona	$	47.9	$	3.2	$	(16.0	)	$	44.3	$	3.2	$	(11.6	)
Northern Nevada		3.7		4.4		(3.8	)		6.7		4.4		0.2
Southern Nevada		24.5		4.1		(8.8	)		21.7		4.1		(5.3	)
California		4.3		6.5		—			5.6		6.5		2.5

	$	80.4	$	18.2	$	(28.6	)	$	78.3	$	18.2	$	(14.2	)

Arizona PGA Filing. In May 2014, Southwest filed an application to provide for monthly adjustments to the surcharge component of the Gas Cost Balancing Account to allow for more timely refunds to/recoveries from ratepayers, which was approved in July 2014. As part of this filing, the ACC also approved an initial surcharge of $0.06 per therm effective August ~~2014 to allow for more timely recovery of the under-collected balance from ratepayers.~~2014.

Cash on hand and cash flows from operations in the past twelve months provided the majority of cash used in investing activities (primarily for construction expenditures and property additions). Certain pipe replacement work was accelerated during 2011, 2012, and 2013 to take advantage of bonus depreciation tax incentives and to enhance system reliability. During the past three years, the Company was able to achieve cost savings from debt refinancing and strategic debt redemptions. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings, which should provide greater access to capital markets and minimize interest costs.

Operating Cash Flows.Cash flows provided by consolidated operating activities decreased ~~$17.8~~$6.6 million in the first ~~six~~nine months of 2014 as compared to the same period of 2013. The decline in operating cash flows was attributable to ~~lower~~reduced net income and ~~decreases in~~the impacts to cash flows from lower deferred income taxes and working capital components overall, partially offset by increases in cash flows from the impacts after adding back non-cash depreciation and amortization and by changes in other liabilities and deferred credits (notably, ~~due to~~ lower pension funding in 2014).

Investing Cash Flows.Cash used in consolidated investing activities increased ~~$32.2~~$27.5 million in the first ~~six~~nine months of 2014 as compared to the same period of 2013. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by NPL due to the increased replacement construction work of its customers. In addition, the current period includes cash ~~outflows restricted~~outlays for the ~~completion of the~~July 2014 purchase of the corporate headquarters office ~~complex (in escrow at June 2014).~~complex.

Financing Cash Flows.Net cash ~~used in~~provided by consolidated financing activities ~~decreased $43.6~~increased $43.9 million in the first ~~six~~nine months of 2014 as compared to the same period of 2013. The prior period included the repayment of ~~$45~~$53 million of IDRBs. ~~The current period includes the repayment of $10 million of credit facility borrowings.~~ The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under NPL’s line of credit. In addition, the prior period included NPL borrowing under note agreements with two banking institutions entered into during the second quarter of 2013. Dividends paid increased in the first ~~six~~nine months of 2014 as compared to the first ~~six~~nine months of 2013 as a result of an increase in the quarterly dividend rate 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.

During the twelve-month period ended ~~June~~September 30, 2014, construction expenditures for the natural gas operations segment were ~~$336~~$356 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant. Customer growth-related expenditures were also an important factor. Cash flows from operating activities of Southwest were ~~$279~~$290 million

and provided approximately 70% of construction expenditures and dividend requirements of the natural gas operations segment. 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, 2016 will be approximately $1.1 billion. Of this amount, it is expected that approximately $375 million will be incurred in 2014. Southwest plans to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic ~~and steel~~ pipe). Significant replacement activities are expected to continue during the next several years. See alsoRates and Regulatory Proceedings for discussion of Nevada infrastructure, Arizona COYL, a proposed LNG facility, and planned Paiute expansion. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 85% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

During the ~~six~~nine months ended ~~June~~September 30, 2014, the Company issued shares of common stock through the Stock Incentive Plan, raising approximately ~~$237,000.~~$419,000.

In reviewing dividend policy, the Board of Directors (“Board”) considers the adequacy and sustainability of earnings and cash flows of the Company and its subsidiaries; the strength of the Company’s capital structure; the sustainability of the dividend through all business cycles; and whether the dividend is within a normal payout range for its respective businesses. As a result of its ongoing review of dividend policy, in February 2014, the Board increased the quarterly dividend from 33 cents to 36.5 cents per share, effective with the June 2014 payment. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average (approximately 55% to 65%), while maintaining the Company’s stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Board’s continued review of the Company’s dividend rate in the context of the performance of the Company’s ~~two~~ operating segments and their future growth prospects.

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.

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~~most recent PGA rate change went into effect. At ~~June~~September 30, 2014, the combined balance in the PGA accounts totaled an under-collection of ~~$80.4~~$78.3 million. SeePGA Filingsfor more information.

The Company has a $300 million revolving credit facility that ~~was~~is scheduled to expire in ~~March 2017. In March 2014, the credit facility expiration was extended by two years to~~ March 2019. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. At ~~June~~September 30, 2014, ~~no borrowings were~~$50 million was outstanding on ~~either~~ the long-term ~~or short-term portions~~portion of the credit ~~facility.~~facility (all under the commercial paper program). 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 adequate for Southwest’s working capital needs outside of funds raised through

The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the commercial paper program are calculated at the current commercial paper rate during the borrowing term. At ~~June~~September 30, 2014, ~~no borrowings were~~$50 million was outstanding under this program.

In November 2014, the Company plans to redeem at par its $65 million 2004 5.25% Series A fixed-rate IDRBs (originally due in 2034) and anticipates that sufficient capacity on the long-term portion of its credit facility will be available to fund the redemption.

NPL ~~has~~had a $75 million credit facility that was scheduled to expire in June 2015. At September 30, 2014, $24.5 million was outstanding on the NPL credit facility. In October 2014, NPL replaced its existing credit facility with a $300 million secured revolving credit and term loan facility that is scheduled to expire in ~~June 2015. At June 30, 2014, $12.5 million~~October 2019.

The new facility was ~~outstanding on~~utilized in the ~~NPL credit facility.~~recent construction services acquisition and is currently expected to meet NPL’s needs. Liquidity in the construction businesses will be contingent upon such things as mix of business, competition, tax laws, weather, and utility construction and replacement programs in the United States and Canada.

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:

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.

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 is 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 ~~2013~~2014 to July ~~2014,~~2015, these liability insurance policies require Southwest to be responsible for the first $1 million dollars (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. At any given time the Company is involved in various legal matters. Through an assessment process, the Company may determine that certain costs are likely to be incurred in the future related to specific legal matters. In these circumstances and in accordance with accounting policies, the Company will make an accrual. In the first quarter of 2014, the Company recorded a $5 million accrual (the maximum self-insured retention plus aggregate for the policy year) in connection with an incident.

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, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote”, “seek,” 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, payment of debt, interest expense, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, amount and timing for completion of estimated future construction expenditures, including the planned LNG facility in southern Arizona and the proposed Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, incremental operating margin in 2014, operating expense increases in 2014, funding sources of cash requirements, sufficiency of working capital and current credit facility, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, NPL’s projected financial performance and related market growth potential, NPL’s projections about the acquired businesses’ earnings (including accretion within the first twelve months) and future acquisition-related costs, pension and post-retirement benefits, the effect and timing of such effect of any rate changes or regulatory proceedings, including the Paiute Pipeline Company general rate case ~~filing,~~

agreement in principle, infrastructure replacement mechanisms and the COYL programs, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals 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, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, 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, 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, results of NPL bid work, ~~impacts of structural and management changes at NPL,~~ NPL construction expenses, ~~NPL’s ability to expedite projects delayed by weather,~~ differences between actual and originally expected outcomes of NPL bid or other fixed-price construction agreements, acquisitions and management’s plans related thereto, results of acquired companies, ultimate allocation of purchase price of acquisition and the related amortization, including resulting accretion to earnings, competition in our construction businesses, construction and replacement work by pipeline customers, tax law changes in the United States and Canada, the ability to maintain Canadian customer relationships, and our 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 operating expenses will continue in future periods. For additional information on the risks associated with the Company’s business, seeItem 1A. Risk Factors andItem 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report onForm 10-K for the year ended December 31, 2013.

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).

SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk in the Company’s 2013 Annual Report on Form 10-K filed with the SEC. No material changes have occurred related to the Company’s disclosures about market ~~risk.~~risk at September 30, 2014.

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 ~~June~~September 30, 2014, 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 ~~second~~third quarter of 2014 that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.

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.

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

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.


	SIX MONTHS ENDED JUNE 30						TWELVE MONTHS ENDED JUNE 30
	2014			2013			2014			2013
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	80,324		$	90,741		$	134,456		$	148,433
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		125,077			117,503			244,391			231,225
Deferred income taxes		24,493			45,781			47,351			73,824
Changes in current assets and liabilities:
Accounts receivable, net of allowances		35,997			36,649			(23,208	)		(5,436	)
Accrued utility revenue		41,100			41,600			(1,200	)		(1,200	)
Deferred purchased gas costs		(62,224	)		(64,376	)		(108,991	)		(88,324	)
Accounts payable		(91,674	)		(53,924	)		(10,082	)		22,746
Accrued taxes		(4,801	)		(2,452	)		(1,424	)		4,100
Other current assets and liabilities		46,238			24,088			27,234			(23,204	)
Gains on sale		(4,137	)		(2,285	)		(5,964	)		(7,031	)
Changes in undistributed stock compensation		3,766			3,855			6,869			5,839
AFUDC and property-related changes		(1,024	)		(1,002	)		(2,296	)		(2,231	)
Changes in other assets and deferred charges		(15,150	)		(16,393	)		(20,476	)		(22,582	)
Changes in other liabilities and deferred credits		19,462			(4,564	)		41,775			3,931

Net cash provided by operating activities		197,447			215,221			328,435			340,090

CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(175,444	)		(151,877	)		(387,843	)		(371,207	)
Restricted cash		(16,649	)		—			(16,649	)		—
Changes in customer advances		8,947			3,127			13,593			13,900
Miscellaneous inflows		7,060			4,905			10,620			13,766
Miscellaneous outflows		—			—			—			(969	)

Net cash used in investing activities		(176,086	)		(143,845	)		(380,279	)		(344,510	)

CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		237			1,357			515			1,626
Dividends paid		(32,316	)		(28,947	)		(62,904	)		(56,169	)
Issuance of long-term debt, net		17,719			41,673			287,336			130,387
Retirement of long-term debt		(10,716	)		(101,269	)		(46,460	)		(205,269	)
Change in credit facility and commercial paper		(10,000	)		8,000			(119,000	)		119,000
Other		(472	)		—			1,527			—

Net cash provided by (used in) financing activities		(35,548	)		(79,186	)		61,014			(10,425	)

Change in cash and cash equivalents		(14,187	)		(7,810	)		9,170			(14,845	)
Cash and cash equivalents at beginning of period		41,077			25,530			17,720			32,565

Cash and cash equivalents at end of period	$	26,890		$	17,720		$	26,890		$	17,720

Supplemental information:
Interest paid, net of amounts capitalized	$	31,787		$	29,116		$	61,401		$	60,103
Income taxes paid		12,246			3,531			15,565			4,608


	NINE MONTHS ENDED SEPTEMBER 30						TWELVE MONTHS ENDED SEPTEMBER 30
	2014			2013			2014			2013
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	82,251		$	87,684		$	139,440		$	149,790
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		187,114			176,247			247,684			233,251
Deferred income taxes		37,690			43,704			62,625			76,641
Changes in current assets and liabilities:
Accounts receivable, net of allowances		34,679			41,310			(29,187	)		(3,855	)
Accrued utility revenue		40,700			40,700			(700	)		(1,100	)
Deferred purchased gas costs		(60,101	)		(78,709	)		(92,535	)		(108,736	)
Accounts payable		(85,514	)		(54,817	)		(3,029	)		12,793
Accrued taxes		(16,869	)		(1,240	)		(14,704	)		(189	)
Other current assets and liabilities		43,650			27,793			20,941			(11,940	)
Gains on sale		(5,661	)		(2,990	)		(6,783	)		(6,524	)
Changes in undistributed stock compensation		4,612			5,444			6,126			6,366
AFUDC and property-related changes		(1,571	)		(1,658	)		(2,187	)		(2,312	)
Changes in other assets and deferred charges		(17,420	)		(22,454	)		(16,685	)		(25,088	)
Changes in other liabilities and deferred credits		18,344			7,524			28,569			5,449

Net cash provided by operating activities		261,904			268,538			339,575			324,546


CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(293,276	)		(254,437	)		(403,115	)		(374,179	)
Changes in customer advances		13,124			5,203			15,694			23,388
Miscellaneous inflows		9,780			6,407			11,838			11,603

Net cash used in investing activities		(270,372	)		(242,827	)		(375,583	)		(339,188	)


CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		419			1,446			608			1,568
Dividends paid		(49,295	)		(44,238	)		(64,592	)		(57,850	)
Issuance of long-term debt, net		37,719			63,673			285,336			99,553
Retirement of long-term debt		(21,528	)		(130,269	)		(28,272	)		(179,855	)
Change in credit facility and commercial paper		40,000			39,000			(100,000	)		110,000
Change in short-term debt		—			33,000			(33,000	)		33,000
Other		(759	)		—			1,240			—

Net cash provided by (used in) financing activities		6,556			(37,388	)		61,320			6,416


Change in cash and cash equivalents		(1,912	)		(11,677	)		25,312			(8,226	)
Cash and cash equivalents at beginning of period		41,077			25,530			13,853			22,079


Cash and cash equivalents at end of period	$	39,165		$	13,853		$	39,165		$	13,853


Supplemental information:
Interest paid, net of amounts capitalized	$	42,695		$	41,161		$	60,264		$	58,078
Income taxes paid		14,823			4,929			16,744			5,801


	June 30, 2014		December 31, 2013
Accounts receivable for NPL services	$	10,786	$	10,787


	September 30, 2014		December 31, 2013

Accounts receivable for NPL services	$	9,501	$	10,787


	Natural Gas		Construction
	Operations		Services		Total
Six months ended June 30, 2014
Revenues from external customers	$	757,972	$	255,119	$	1,013,091
Intersegment revenues		—		48,458		48,458

Total	$	757,972	$	303,577	$	1,061,549

Segment net income	$	74,397	$	6,013	$	80,410

Six months ended June 30, 2013
Revenues from external customers	$	732,469	$	255,300	$	987,769
Intersegment revenues		—		37,310		37,310

Total	$	732,469	$	292,610	$	1,025,079

Segment net income	$	81,256	$	9,625	$	90,881


	Natural Gas Operations		Construction Services		Total
Twelve months ended June 30, 2014
Revenues from external customers	$	1,325,657	$	562,294	$	1,887,951
Intersegment revenues		—		99,301		99,301

Total	$	1,325,657	$	661,595	$	1,987,252

Segment net income	$	117,310	$	17,539	$	134,849

Twelve months ended June 30, 2013
Revenues from external customers	$	1,267,567	$	532,687	$	1,800,254
Intersegment revenues		—		85,190		85,190

Total	$	1,267,567	$	617,877	$	1,885,444

Segment net income	$	121,877	$	27,092	$	148,969


	June 30, 2014		December 31, 2013
Contract notional amounts		7,658		13,571


Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Thousands of dollars)
	Three Months Ended									Three Months Ended
	September 30, 2014									September 30, 2013
	Before-			Tax			Net-of-			Before-			Tax			Net-of-
	Tax			(Expense)			Tax			Tax			(Expense)			Tax
	Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount
Defined benefit pension plans:
Amortization of net actuarial (gain)/loss	$	5,914		$	(2,247	)	$	3,667		$	8,544		$	(3,247	)	$	5,297
Amortization of prior service cost		89			(34	)		55			89			(34	)		55
Regulatory adjustment		(5,178	)		1,968			(3,210	)		(7,583	)		2,882			(4,701	)

Pension plans other comprehensive income (loss)		825			(313	)		512			1,050			(399	)		651

FSIRS (designated hedging activities):
Amounts reclassifed into net income		836			(318	)		518			836			(318	)		518

FSIRS other comprehensive income		836			(318	)		518			836			(318	)		518

Total other comprehensive income (loss)	$	1,661		$	(631	)	$	1,030		$	1,886		$	(717	)	$	1,169


	Nine Months Ended									Nine Months Ended
	September 30, 2014									September 30, 2013
	Before-			Tax			Net-of-			Before-			Tax			Net-of-
	Tax			(Expense)			Tax			Tax			(Expense)			Tax
	Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount
Defined benefit pension plans:
Amortization of net actuarial (gain)/loss	$	17,742		$	(6,742	)	$	11,000		$	25,634		$	(9,741	)	$	15,893
Amortization of prior service cost		266			(101	)		165			266			(102	)		164
Regulatory adjustment		(15,533	)		5,903			(9,630	)		(22,751	)		8,646			(14,105	)

Pension plans other comprehensive income (loss)		2,475			(940	)		1,535			3,149			(1,197	)		1,952

FSIRS (designated hedging activities):
Amounts reclassifed into net income		2,509			(954	)		1,555			2,509			(954	)		1,555

FSIRS other comprehensive income		2,509			(954	)		1,555			2,509			(954	)		1,555

Total other comprehensive income (loss)	$	4,984		$	(1,894	)	$	3,090		$	5,658		$	(2,151	)	$	3,507


Amounts Recognized in AOCI (Before Tax) (Thousands of dollars)
	September 30, 2014			December 31, 2013
Net actuarial (loss) gain	$	(271,399	)	$	(289,141	)
Prior service cost		(1,801	)		(2,067	)
Less: amount recognized in regulatory assets		234,452			249,985

Recognized in AOCI	$	(38,748	)	$	(41,223	)


	Three Months Ended June 30,
	2014			2013
	(Thousands of dollars)
Gas operating revenues	$	271,479		$	238,869
Net cost of gas sold		97,985			69,388

Operating margin		173,494			169,481
Operations and maintenance expense		97,620			94,935
Depreciation and amortization		50,524			47,746
Taxes other than income taxes		10,965			11,073

Operating income		14,385			15,727
Other income (deductions)		2,848			1,448
Net interest deductions		17,059			14,886

Income before income taxes		174			2,289
Income tax expense (benefit)		(1,624	)		325

Contribution to consolidated net income	$	1,798		$	1,964


	For the Twelve Months Ended
	June 30, 2014		December 31, 2013
Ratio of earnings to fixed charges		3.53		3.90



Exhibit 10.01	–	NPL Credit Agreement.

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 ~~June~~September 30, 2014, 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 Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) the Notes to the Condensed Consolidated Financial Statements.


~~Date: August 6, 2014~~

				/s/ GREGORY J. PETERSON
				Gregory J. Peterson
				Vice President/Controller and Chief Accounting Officer


~~SOUTHWEST GAS CORPORATION~~		~~Form 10-Q~~
~~June 30, 2014~~


~~SOUTHWEST GAS CORPORATION~~		~~Form 10-Q~~
~~June 30, 2014~~

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company