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, ~~47,057,295~~47,375,398 shares as of ~~July~~October 28, 2015.


	JUNE 30, 2015			DECEMBER 31, 2014			SEPTEMBER 30, 2015			DECEMBER 31, 2014
ASSETS
Utility plant:
Gas plant	$	5,681,417		$	5,556,599		$	5,734,807		$	5,556,599
Less: accumulated depreciation		(2,029,322	)		(1,973,098	)		(2,060,402	)		(1,973,098	)
Acquisition adjustments, net		460			550			415			550
Construction work in progress		79,906			74,332			118,554			74,332

Net utility plant		3,732,461			3,658,383			3,793,374			3,658,383

Other property and investments		325,449			326,743			319,243			326,743

Restricted cash		—			821			—			821

Current assets:
Cash and cash equivalents		48,909			39,566			32,959			39,566
Accounts receivable, net of allowances		273,447			281,824			269,058			281,824
Accrued utility revenue		31,800			73,900			32,200			73,900
Income taxes receivable, net		13,997			21,853			37,810			21,853
Deferred income taxes, net		10,492			2,109			291			2,109
Deferred purchased gas costs		3,751			87,556			815			87,556
Prepaids and other current assets		98,445			99,975			105,438			99,975

Total current assets		480,841			606,783			478,571			606,783

Noncurrent assets:
Goodwill		138,257			143,160			129,884			143,160
Deferred income taxes		1,473			—			1,688			—
Deferred charges and other assets		468,381			478,625			460,906			478,625

Total noncurrent assets		608,111			621,785			592,478			621,785

Total assets	$	5,146,862		$	5,214,515		$	5,183,666		$	5,214,515


CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 47,042,327 and 46,523,184 shares)	$	48,672		$	48,153
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—47,375,398 and 46,523,184 shares)							$	49,005		$	48,153
Additional paid-in capital		873,622			851,381			894,625			851,381
Accumulated other comprehensive income (loss), net		(48,750	)		(50,175	)		(48,013	)		(50,175	)
Retained earnings		678,288			639,164			654,492			639,164

Total Southwest Gas Corporation equity		1,551,832			1,488,523			1,550,109			1,488,523
Noncontrolling interest		(2,199	)		(2,257	)		(2,177	)		(2,257	)

Total equity		1,549,633			1,486,266			1,547,932			1,486,266
Redeemable noncontrolling interest		19,301			20,042			13,703			20,042
Long-term debt, less current maturities		1,521,683			1,637,592			1,540,364			1,637,592

Total capitalization		3,090,617			3,143,900			3,101,999			3,143,900

Current liabilities:
Current maturities of long-term debt		20,050			19,192			19,865			19,192
Short-term debt		—			5,000			—			5,000
Accounts payable		130,363			167,988			129,258			167,988
Customer deposits		72,744			71,546			72,268			71,546
Income taxes payable		4,271			—			13,643			—
Accrued general taxes		39,784			44,339			42,249			44,339
Accrued interest		16,159			16,468			21,730			16,468
Deferred income taxes		16,378			—			7,031			—
Deferred purchased gas costs		27,216			—			44,754			—
Other current liabilities		139,225			145,584			143,882			145,584

Total current liabilities		466,190			470,117			494,680			470,117

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		721,352			723,688			722,718			723,688
Accumulated removal costs		302,000			304,000			301,000			304,000
Other deferred credits and other long-term liabilities		566,703			572,810			563,269			572,810

Total deferred income taxes and other credits		1,590,055			1,600,498			1,586,987			1,600,498

Total capitalization and liabilities	$	5,146,862		$	5,214,515		$	5,183,666		$	5,214,515


	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,
	2015			2014			2015			2014			2015			2014			2015			2014			2015			2014			2015			2014
Operating revenues:
Gas operating revenues	$	286,643		$	271,479		$	839,758		$	757,972		$	1,463,873		$	1,325,657		$	219,420		$	226,027		$	1,059,178		$	983,999		$	1,457,266		$	1,356,653
Construction revenues		251,961			181,674			433,066			303,577			869,109			661,595			285,976			206,448			719,042			510,025			948,637			675,728

Total operating revenues		538,604			453,153			1,272,824			1,061,549			2,332,982			1,987,252			505,396			432,475			1,778,220			1,494,024			2,405,903			2,032,381

Operating expenses:
Net cost of gas sold		109,015			97,985			362,777			289,362			578,771			455,367			64,268			72,987			427,045			362,349			570,052			480,608
Operations and maintenance		99,344			97,620			194,854			200,028			378,558			392,920			100,102			93,389			294,956			293,417			385,271			390,328
Depreciation and amortization		66,955			62,186			134,422			125,077			262,372			244,391			66,476			62,037			200,898			187,114			266,811			247,684
Taxes other than income taxes		12,414			10,965			25,411			22,421			50,242			45,104			11,652			11,835			37,063			34,256			50,059			45,786
Construction expenses		225,829			157,642			400,757			270,841			777,773			588,737			246,755			173,937			647,512			444,778			850,591			595,093

Total operating expenses		513,557			426,398			1,118,221			907,729			2,047,716			1,726,519			489,253			414,185			1,607,474			1,321,914			2,122,784			1,759,499

Operating income		25,047			26,755			154,603			153,820			285,266			260,733			16,143			18,290			170,746			172,110			283,119			272,882

Other income and (expenses):
Net interest deductions		(17,717	)		(17,305	)		(35,694	)		(34,824	)		(72,939	)		(67,356	)		(18,401	)		(17,421	)		(54,095	)		(52,245	)		(73,919	)		(69,680	)
Other income (deductions)		162			2,863			2,434			4,475			5,066			11,254			(3,660	)		440			(1,226	)		4,915			966			9,026

Total other income and (expenses)		(17,555	)		(14,442	)		(33,260	)		(30,349	)		(67,873	)		(56,102	)		(22,061	)		(16,981	)		(55,321	)		(47,330	)		(72,953	)		(60,654	)

Income before income taxes		7,492			12,313			121,343			123,471			217,393			204,631
Income tax expense		2,429			2,686			44,401			43,147			79,627			70,175
Income (loss) before income taxes																				(5,918	)		1,309			115,425			124,780			210,166			212,228
Income tax expense (benefit)																				(1,708	)		(618	)		42,693			42,529			78,537			72,788

Net income		5,063			9,627			76,942			80,324			137,766			134,456
Net income (loss)																				(4,210	)		1,927			72,732			82,251			131,629			139,440
Net income (loss) attributable to noncontrolling interests		114			—			10			(86	)		118			(393	)		524			(43	)		534			(129	)		685			(243	)

Net income attributable to Southwest Gas Corporation	$	4,949		$	9,627		$	76,932		$	80,410		$	137,648		$	134,849
Net income (loss) attributable to Southwest Gas Corporation																			$	(4,734	)	$	1,970		$	72,198		$	82,380		$	130,944		$	139,683

Basic earnings (loss) per share																			$	(0.10	)	$	0.04		$	1.54		$	1.77		$	2.80		$	3.01

Basic earnings per share	$	0.11		$	0.21		$	1.65		$	1.73		$	2.95		$	2.91

Diluted earnings per share	$	0.10		$	0.21		$	1.63		$	1.71		$	2.92		$	2.88
Diluted earnings (loss) per share																			$	(0.10	)	$	0.04		$	1.53		$	1.76		$	2.77		$	2.98

Dividends declared per share	$	0.405		$	0.365		$	0.810		$	0.730		$	1.540		$	1.390		$	0.405		$	0.365		$	1.215		$	1.095		$	1.580		$	1.425


Average number of common shares outstanding		46,869			46,502			46,741			46,471			46,628			46,407			47,102			46,513			46,863			46,485			46,777			46,451
Average shares outstanding (assuming dilution)		47,290			46,948			47,164			46,910			47,070			46,860			—			46,966			47,261			46,928			47,194			46,904


	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,
	2015			2014			2015			2014			2015			2014			2015			2014			2015			2014			2015			2014
Net income	$	5,063		$	9,627		$	76,942		$	80,324		$	137,766		$	134,456
	��
Net income (loss)																			$	(4,210	)	$	1,927		$	72,732		$	82,251		$	131,629		$	139,440

Other comprehensive income (loss), net of tax
Defined benefit pension plans:
Net actuarial gain (loss)		—			—			—			—			(107,661	)		62,214			—			—			—			—			(107,661	)		62,214
Amortization of prior service cost		208			55			414			110			524			221			207			55			621			165			676			221
Amortization of net actuarial loss		5,328			3,666			10,658			7,333			17,992			17,927			5,329			3,667			15,987			11,000			19,654			16,297
Prior service cost		—			—			—			—			(4,130	)		—			—			—			—			—			(4,130	)		—
Regulatory adjustment		(4,828	)		(3,210	)		(9,656	)		(6,420	)		83,755			(73,667	)		(4,828	)		(3,210	)		(14,484	)		(9,630	)		82,137			(72,176	)

Net defined benefit pension plans		708			511			1,416			1,023			(9,520	)		6,695			708			512			2,124			1,535			(9,324	)		6,556

Forward-starting interest rate swaps:
Amounts reclassified into net income		518			519			1,037			1,037			2,073			2,074			519			518			1,556			1,555			2,074			2,074

Net forward-starting interest rate swaps		518			519			1,037			1,037			2,073			2,074			519			518			1,556			1,555			2,074			2,074

Foreign currency translation adjustments		209			—			(1,063	)		—			(1,722	)		—			(510	)		—			(1,573	)		—			(2,232	)		—

Total other comprehensive income (loss), net of tax		1,435			1,030			1,390			2,060			(9,169	)		8,769			717			1,030			2,107			3,090			(9,482	)		8,630

Comprehensive income		6,498			10,657			78,332			82,384			128,597			143,225
Comprehensive income (loss)																				(3,493	)		2,957			74,839			85,341			122,147			148,070
Comprehensive income (loss) attributable to noncontrolling interests		122			—			(25	)		(86	)		61			(393	)	��	504			(43	)		479			(129	)		608			(243	)

Comprehensive income attributable to Southwest Gas Corporation	$	6,376		$	10,657		$	78,357		$	82,470		$	128,536		$	143,618
Comprehensive income (loss) attributable to Southwest Gas Corporation																			$	(3,997	)	$	3,000		$	74,360		$	85,470		$	121,539		$	148,313


	SIX MONTHS ENDED JUNE 30						TWELVE MONTHS ENDED JUNE 30						NINE MONTHS ENDED SEPTEMBER 30						TWELVE MONTHS ENDED SEPTEMBER 30
	2015			2014			2015			2014			2015			2014			2015			2014
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	76,942		$	80,324		$	137,766		$	134,456		$	72,732		$	82,251		$	131,629		$	139,440
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		134,422			125,077			262,372			244,391			200,898			187,114			266,811			247,684
Deferred income taxes		3,896			24,493			43,712			47,351			5,961			37,690			32,580			62,625
Changes in current assets and liabilities:
Accounts receivable, net of allowances		6,018			35,997			(33,662	)		(23,208	)		6,570			34,679			(31,792	)		(29,187	)
Accrued utility revenue		42,100			41,100			(200	)		(1,200	)		41,700			40,700			(200	)		(700	)
Deferred purchased gas costs		111,021			(62,224	)		103,906			(108,991	)		131,495			(60,101	)		122,257			(92,535	)
Accounts payable		(38,471	)		(91,674	)		11,704			(10,082	)		(38,878	)		(85,514	)		5,137			(3,029	)
Accrued taxes		7,614			(4,801	)		(1,158	)		(1,424	)		(4,427	)		(16,869	)		(1,131	)		(14,704	)
Other current assets and liabilities		5,163			46,238			(17,696	)		27,234			8,333			43,650			(11,938	)		20,941
Gains on sale		(2,563	)		(4,137	)		(4,597	)		(5,964	)		(3,019	)		(5,661	)		(3,529	)		(6,783	)
Changes in undistributed stock compensation		1,512			3,766			5,719			6,869			2,119			4,612			5,480			6,126
AFUDC		(1,133	)		(1,024	)		(2,104	)		(2,296	)		(2,011	)		(1,571	)		(2,435	)		(2,187	)
Changes in other assets and deferred charges		(15,239	)		(15,150	)		(21,821	)		(20,476	)		(14,423	)		(17,420	)		(18,735	)		(16,685	)
Changes in other liabilities and deferred credits		2,954			19,462			(729	)		41,775			5,348			18,344			2,783			28,569

Net cash provided by operating activities		334,236			197,447			483,212			328,435			412,398			261,904			496,917			339,575


CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(203,640	)		(175,444	)		(425,094	)		(387,843	)		(336,569	)		(293,276	)		(440,191	)		(403,115	)
Acquisition of businesses, net of cash acquired		(9,261	)		—			(199,758	)		—			(9,261	)		—			(199,758	)		—
Restricted cash		785			(16,649	)		18,667			(16,649	)		785			—			2,018			—
Changes in customer advances		9,689			8,947			21,105			13,593			14,300			13,124			21,539			15,694
Miscellaneous inflows		4,892			7,060			9,443			10,620			11,593			9,780			13,424			11,838
Miscellaneous outflows		—			—			(1,400	)		—			—			—			(1,400	)		—

Net cash used in investing activities		(197,535	)		(176,086	)		(577,037	)		(380,279	)		(319,152	)		(270,372	)		(604,368	)		(375,583	)


CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		20,713			237			20,881			515			35,419			419			35,405			608
Dividends paid		(36,001	)		(32,316	)		(69,960	)		(62,904	)		(55,060	)		(49,295	)		(72,040	)		(64,592	)
Issuance of long-term debt, net		93,165			17,719			344,674			287,336			123,816			37,719			355,325			285,336
Retirement of long-term debt		(78,409	)		(10,716	)		(206,848	)		(46,460	)		(143,325	)		(21,528	)		(260,952	)		(28,272	)
Change in credit facility and commercial paper		(120,000	)		(10,000	)		30,000			(119,000	)		(53,000	)		40,000			47,000			(100,000	)
Change in short-term debt		(5,000	)		—			—			—			(5,000	)		—			—			(33,000	)
Principal payments on capital lease obligations		(722	)		—			(1,156	)		—			(1,096	)		—			(1,530	)		—
Other		(534	)		(472	)		(1,319	)		1,527			(504	)		(759	)		(1,002	)		1,240

Net cash provided by (used in) financing activities		(126,788	)		(35,548	)		116,272			61,014			(98,750	)		6,556			102,206			61,320


Effects of currency translation on cash and cash equivalents		(570	)		—			(428	)		—			(1,103	)		—			(961	)		—

Change in cash and cash equivalents		9,343			(14,187	)		22,019			9,170			(6,607	)		(1,912	)		(6,206	)		25,312
Cash and cash equivalents at beginning of period		39,566			41,077			26,890			17,720			39,566			41,077			39,165			13,853


Cash and cash equivalents at end of period	$	48,909		$	26,890		$	48,909		$	26,890		$	32,959		$	39,165		$	32,959		$	39,165


Supplemental information:
Interest paid, net of amounts capitalized	$	34,213		$	31,787		$	67,978		$	61,401		$	45,312		$	42,695		$	68,169		$	60,264
Income taxes paid		28,479			12,246			40,480			15,565			39,856			14,823			49,280			16,744

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. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Results for the natural gas operations segment are lowest during late spring to early fall and improve during winter periods due to the seasonality incorporated in its regulatory rate structures. Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a ~~wholly~~96.6% 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, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). Typically, Centuri 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 United States generally accepted accounting principles (“U.S. 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 2014 Annual Report to Shareholders, which is incorporated by reference into the 2014 Form 10-K, and the first and second quarter 2015 reports on Form 10-Q.

Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The Company’s investment in Western is not significant in relation to its total assets included in the Condensed Consolidated Balance Sheets.

Prepaids and other current assets. Prepaids and other current assets includes gas pipe ~~inventory~~materials and ~~operating~~ supplies of ~~$27~~$25 million at ~~June~~September 30, 2015 and $23 million at December 31, 2014.

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. In general, 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. However, cash and cash equivalents at ~~June~~September 30, 2015 and December 31, 2014 also ~~includes~~include two money market fund investments totaling approximately $250,000 which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

Significant non-cash investing and financing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $2$2.8 million and ~~$5.6~~$7 million, during the first ~~six~~nine months of 2015 and 2014, respectively, were applied as contributions toward utility construction activity and represent non-cash investing activity.

Goodwill. Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill. No impairment was recorded in the first ~~six~~nine months of 2015. The acquisition date adjustment shown in the table below was recorded in the first quarter of 2015. No acquisition date adjustments ~~to goodwill were recorded during the second quarter~~occurred subsequently. The business of ~~2015. See~~~~Note 8 – Acquisition of Construction Services Businesses~~ ~~for more information on the acquisition.~~

Therefore, goodwill assigned to Brigadier is expected to be deductible for tax purposes, resulting in an after-tax value of $4.9 million. All other goodwill associated with the acquisition is not deductible for tax purposes.

Intercompany Transactions. Centuri recognizes revenues generated from contracts with Southwest (seeNote ~~3 –~~ 3—Segment Information below). Centuri’s 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):


	June 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Centuri property and equipment	$	419		$	405		$	419		$	405
Centuri accumulated provision for depreciation and amortization		(206	)		(187	)		(209	)		(187	)
Net cash surrender value of COLI policies		101			99			97			99
Other property		11			10			12			10

Total	$	325		$	327		$	319		$	327

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						Six Months Ended					Twelve Months Ended						Three Months Ended						Nine Months Ended					Twelve Months Ended
	June 30						June 30					June 30						September 30						September 30					September 30
	2015			2014			2015			2014		2015			2014			2015			2014			2015			2014		2015			2014
Change in COLI policies	$	—		$	2,300		$	1,300		$	3,200	$	3,400		$	10,000		$	(3,900	)	$	(300	)	$	(2,600	)	$	2,900	$	(200	)	$	7,200
Interest income		161			612			751			1,109		2,244			1,306			624			772			1,375			1,881		2,096			1,920
Pipe replacement costs		—			—			—			—		—			(11	)
Foreign transaction gain (loss)		(245	)		—			(572	)		—		(750	)		—			(302	)		—			(874	)		—		(1,052	)		—
Miscellaneous income and (expense)		246			(49	)		955			166		172			(41	)		(82	)		(32	)		873			134		122			(94	)

Total other income (deductions)	$	162		$	2,863		$	2,434		$	4,475	$	5,066		$	11,254		$	(3,660	)	$	440		$	(1,226	)	$	4,915	$	966		$	9,026

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 values of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences.

Recently Issued Accounting Standards 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. In accordance with the update, 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. In April 2015, the FASB voted to propose, and in July 2015 it approved, a one-year deferral of the effective

date (annual ~~period~~periods ending after December 15, 2017), but to permit entities to adopt one year earlier if they choose (i.e., the original effective date). The FASB decided, based on its outreach to various stakeholders and the forthcoming exposure drafts, which amend the update, that a deferral is necessary to provide adequate time to effectively implement the update. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2018. The Company is evaluating what impact this update 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 assess 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 ~~and changes thereto are~~is not expected to have a material impact on the Company’s disclosures.

In April 2015, the FASB issued the update “Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs.” To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. Retrospective application of the update is required. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. This update is not expected to have a material impact on the Company’s consolidated financial statements and 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, 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.

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

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (up to 25% in the Arizona and California jurisdictions) 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 2015 through March 2017. 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):

In late 2013, the Company suspended further Swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The decision did not impact previously executed purchase arrangements. Agreements, under the Nevada VMP, made prior to the suspension, terminated following the March 2015 delivery month. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

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, 2015 and 2014 and their location in the Condensed Consolidated Statements of Income:


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:																				Gains (losses) recognized in income for derivatives not designated as hedging instruments:
(Thousands of dollars)
		Three Months Ended						Six Months Ended						Twelve Months Ended							Location of Gain or (Loss) Recognized in Income on Derivative		Three Months Ended								Nine Months Ended								Twelve Months Ended
	Location of Gain or (Loss)	June 30						June 30						June 30								September 30								September 30								September 30
Instrument	Recognized in Income on Derivative	2015			2014			2015			2014			2015			2014					2015				2014				2015				2014				2015				2014
Swaps	Net cost of gas sold	$	707		$	(83	)	$	(1,407	)	$	5,907		$	(9,677	)	$	9,476				Net cost of gas sold		$	(3,282	)		$	(2,277	)		$	(4,689	)		$	3,630			$	(10,682	)		$	7,552
Swaps	Net cost of gas sold		(707	)*		83	*		1,407	*		(5,907	)*		9,677	*		(9,476	)*			Net cost of gas sold			3,282	*			2,277	*			4,689	*			(3,630	)*			10,682	*			(7,552	)*

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”), both of which were designated cash flow hedges, to partially hedge the risk of interest rate variability during the period leading up to the issuance of debt. The first FSIRS terminated in December 2010. The second FSIRS terminated in March 2012. 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, 2015			Asset		Liability
Fair values of derivatives not designated as hedging instruments:											Fair values of derivatives not designated as hedging instruments:
September 30, 2015											September 30, 2015		Asset Derivatives			Liability Derivatives				Net Total
Instrument		Balance Sheet Location	Derivatives		Derivatives			Net Total				Balance Sheet Location				Liability Derivatives				Net Total
Swaps		Other current liabilities	$	105	$	(2,098	)	$	(1,993	)		Other current liabilities	Asset Derivatives	$	—		$	(3,425	)		$	(3,425	)
Swaps		Other deferred credits		28		(208	)		(180	)		Other deferred credits		—			(1,462	)			(1,462	)

Total			$	133	$	(2,306	)	$	(2,173	)			$	—		$	(4,887	)		$	(4,887	)


December 31, 2014	December 31, 2014		Asset		Liability						December 31, 2014		Asset Derivatives			Liability Derivatives				Net Total
Instrument		Balance Sheet Location	Derivatives		Derivatives			Net Total				Balance Sheet Location				Liability Derivatives				Net Total
Swaps		Other current liabilities	$	—	$	(5,062	)	$	(5,062	)		Other current liabilities	Asset Derivatives	$	—		$	(5,062	)		$	(5,062	)
Swaps		Other deferred credits		—		(363	)		(363	)		Other deferred credits		—			(363	)			(363	)

Total			$	—	$	(5,425	)	$	(5,425	)			$	—		$	(5,425	)		$	(5,425	)

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 ofin 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		Six Months Ended		Twelve Months Ended		Three Months Ended		Nine Months Ended		Twelve Months Ended
(Thousands of dollars)	June 30, 2015		June 30, 2015		June 30, 2015		September 30, 2015		September 30, 2015		September 30, 2015
Paid to counterparties	$	690	$	4,660	$	5,474	$	568	$	5,228	$	5,971

Received from counterparties	$	—	$	—	$	198	$	—	$	—	$	120

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, 2015

September 30, 2015

Instrument

Balance Sheet Location

Net Total

Balance Sheet Location

Net Total

Swaps

Prepaids and other current assets

1,993

Prepaids and other current assets

3,425

Swaps

Deferred charges and other assets

180

Deferred charges and other assets

1,462

December 31, 2014

Instrument

Balance Sheet Location

Net Total

Balance Sheet Location

Net Total

Swaps

Prepaids and other current assets

5,062

Prepaids and other current assets

5,062

Swaps

Deferred charges and other assets

363

Deferred charges and other assets

363

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at ~~June~~September 30, 2015 and December 31, 2014 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 that were accounted for at fair value:


Level 2—Significant other observable inputs
(Thousands of dollars)	June 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Liabilities at fair value:
Other current liabilities—Swaps	$	(1,993	)	$	(5,062	)	$	(3,425	)	$	(5,062	)
Other deferred credits—Swaps		(180	)		(363	)		(1,462	)		(363	)

Net Assets (Liabilities)	$	(2,173	)	$	(5,425	)	$	(4,887	)	$	(5,425	)

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.

With regard to the fair values of assets associated with the Company’s pension and postretirement benefit plans, asset values were last updated as required as of December 2014. Refer to Note 9 – Pension and Other Post Retirement Benefits in the 2014 Annual Report to Shareholders on Form 10-K.

On March 10, 2015, the Company filed with the Securities Exchange Commission (“SEC”) an automatic shelf registration statement on Form S-3 (File No. 333-202633), which became effective upon filing, for the offer and sale of up to $100,000,000 of the Company’s common stock from time to time in at-the-market offerings under the prospectus included therein and in accordance with the Sales Agency Agreement, dated March 10, 2015, between the Company and BNY Mellon Capital Markets, LLC (the “Equity Shelf Program”). During the three months ending ~~June~~September 30, 2015, the Company sold, through the continuous equity offering program with BNY Mellon Capital Markets, LLC as agent, an aggregate of ~~180,247~~272,716 shares of the Company’s common stock in the open market at a weighted average price of ~~$53.90~~$54.12 per share, resulting in proceeds to the Company of ~~$9,618,188,~~$14,610,439, net of ~~$97,154~~$147,579 in agent commissions. For the ~~six~~nine months ended ~~June~~September 30, 2015, the Company sold an aggregate of ~~372,509~~645,225 shares of common stock under this program resulting in proceeds to the Company of ~~$20,557,144,~~$35,167,584, net of ~~$207,649~~$355,228 in agent commissions. As of ~~June~~September 30, 2015, the Company had up to ~~$79,235,207~~$64,477,188 of common stock available for sale under the program. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

In addition, during the ~~six~~nine months ended ~~June~~September 30, 2015, the Company issued approximately ~~145,000~~207,000 shares of common stock through the Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan.

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of ~~June~~September 30, 2015 and December 31, 2014 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within thethree-level fair value hierarchy that ranks the inputs, used to measure fair value, by their reliability, due to the Company’s ability to access similar debt arrangements at measurement dates with comparable terms, including variable rates. The fair values of debentures and fixed-rate IDRBs were determined utilizing 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, credit ratings and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. The market values of debentures and fixed-rate IDRBs are categorized as Level 2 (observable market inputs based on market prices of similar securities). The Centuri secured revolving credit and term loan facility and Centuri other debt obligations (not

actively traded) are categorized as Level 3, based on significant unobservable inputs to their fair values. Since Centuri’s debt is not publicly traded, fair values

for the secured revolving credit and term loan facility and other debt obligations were based on a conventional discounted cash flow methodology and ~~utilizes~~utilized current market pricing yield curves, across Centuri’s debt maturity spectrum, of other industrial bonds with an assumed credit rating comparable to the Company’s.


	June 30, 2015					December 31, 2014
	Carrying			Market		Carrying			Market		September 30, 2015					December 31, 2014
	Amount			Value		Amount			Value		Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	133,183	$	125,000		$	133,403	$	125,000		$	132,769	$	125,000		$	133,403
Notes, 6.1%, due 2041		125,000			146,568		125,000			157,290		125,000			147,451		125,000			157,290
Notes, 3.875%, due 2022		250,000			259,723		250,000			262,030		250,000			263,023		250,000			262,030
Notes, 4.875%, due 2043		250,000			256,505		250,000			280,903		250,000			266,370		250,000			280,903
8% Series, due 2026		75,000			99,431		75,000			102,296		75,000			99,380		75,000			102,296
Medium-term notes, 7.59% series, due 2017		25,000			27,063		25,000			27,573		25,000			26,662		25,000			27,573
Medium-term notes, 7.78% series, due 2022		25,000			30,705		25,000			31,144		25,000			30,621		25,000			31,144
Medium-term notes, 7.92% series, due 2027		25,000			32,706		25,000			33,695		25,000			32,726		25,000			33,695
Medium-term notes, 6.76% series, due 2027		7,500			8,896		7,500			9,156		7,500			8,917		7,500			9,156
Unamortized discount		(5,046	)				(5,223	)				(4,957	)				(5,223	)

		902,454					902,277					902,543					902,277

Revolving credit facility and commercial paper		30,000			30,000		150,000			150,000		97,000			97,000		150,000			150,000

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			20,103		20,000			20,277		—			—		20,000			20,277
5.00% 2004 Series B, due 2033		—			—		31,200			31,223		—			—		31,200			31,223
4.85% 2005 Series A, due 2035		100,000			100,629		100,000			100,071		100,000			100,415		100,000			100,071
4.75% 2006 Series A, due 2036		24,855			25,005		24,855			25,399		24,855			25,089		24,855			25,399
Unamortized discount		(1,645	)				(1,943	)				(1,539	)				(1,943	)

		343,210					374,112					323,316					374,112

Centuri secured revolving credit and term loan facility		234,598			235,542		199,267			200,341		208,787			209,213		199,267			200,341
Centuri other debt obligations		31,471			31,749		31,128			31,127		28,583			28,868		31,128			31,127

		1,541,733					1,656,784					1,560,229					1,656,784
Less: current maturities		(20,050	)				(19,192	)				(19,865	)				(19,192	)

Long-term debt, less current maturities	$	1,521,683				$	1,637,592				$	1,540,364				$	1,637,592

In March 2015, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2019 and was extended to March 2020. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. 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, 2015, 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. At ~~June~~September 30, 2015, $5$47 million was outstanding on the credit facility and ~~$25~~$50 million was outstanding on the commercial paper program.

In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated the redemption primarily from cash on hand and borrowings under its $300 million credit facility.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. At ~~June~~September 30, 2015, ~~$235~~$209 million in borrowings were outstanding on the Centuri facility. Centuri assets securing the facility at ~~June~~September 30, 2015 totaled ~~$492~~$557 million.

Note 7 – Equity, Other Comprehensive Income, and Accumulated Other Comprehensive Income

The table below provides details of activity in equity and the redeemable noncontrolling interest during the ~~six~~nine months ended ~~June~~September 30, 2015.


	Southwest Gas Corporation Equity																					Southwest Gas Corporation Equity
							Accumulated												Redeemable							Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)																Redeemable Noncontrolling Interest (Temporary Equity)
					Additional		Other						Non-						Noncontrolling			Common Stock										Retained Earnings				Non-controlling Interest
	Common Stock				Paid-in		Comprehensive			Retained			controlling						Interest
(In thousands, except per share amounts)	Shares		Amount		Capital		Income (Loss)			Earnings			Interest			Total			(Temporary Equity)
(In thousands except per share amounts)																						Shares		Amount				Additional Paid-in Capital							Accumulated Other Comprehensive Income (Loss)				Retained Earnings				Non-controlling Interest				Total			Redeemable Noncontrolling Interest (Temporary Equity)
DECEMBER 31, 2014		46,523	$	48,153	$	851,381	$	(50,175	)	$	639,164		$	(2,257	)	$	1,486,266		$	20,042			46,523	$	48,153					$	1,486,266
Common stock issuances		519		519		22,241											22,760						852		852													38,319
Net income (loss)											76,932			58			76,990			(48	)															72,198				80				72,278				454
Redemption value adjustments											658						658			(658	)						5,777									961								6,738				(6,738	)
Foreign currency exchange translation adj.								(1,028	)								(1,028	)		(35	)										(1,518	)											(1,518	)			(55	)
Other comprehensive income (loss):
Net actuarial gain (loss) arising during period, less amortization of unamortized benefit plan cost, net of tax								1,416									1,416													2,124												2,124
Amounts reclassified to net income,net of tax (FSIRS)								1,037									1,037
Amounts reclassified to net income, net of tax (FSIRS)																														1,556												1,556
Dividends declared
Common: $0.81 per share											(38,466	)					(38,466	)
Common: $1.215 per share																																		(57,831		)							(57,831	)

JUNE 30, 2015		47,042	$	48,672	$	873,622	$	(48,750	)	$	678,288		$	(2,199	)	$	1,549,633		$	19,301
SEPTEMBER 30, 2015																							47,375	$	49,005	$	894,625		$	(48,013	)		$	654,492			$	(2,177	)		$	1,547,932			$	13,703

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.


																			Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
																			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 prior service cost																			$	1,001		$	(380	)	$	621		$	266		$	(101	)	$	165
Amortization of net actuarial (gain)/loss																				25,786			(9,799	)		15,987			17,742			(6,742	)	$	11,000
Regulatory adjustment																				(23,361	)		8,877			(14,484	)		(15,533	)		5,903			(9,630	)

Pension plans other comprehensive income (loss)																				3,426			(1,302	)		2,124			2,475			(940	)		1,535

FSIRS (designated hedging activities):
Amounts reclassifed into net income																				2,508			(952	)		1,556			2,509			(954	)		1,555

FSIRS other comprehensive income																				2,508			(952	)		1,556			2,509			(954	)		1,555

Foreign currency translation adjustments:
Translation adjustments																				(1,573	)		—			(1,573	)		—			—			—

Foreign currency other comprehensive income (loss)																				(1,573	)		—			(1,573	)		—			—			—

Total other comprehensive income (loss)																			$	4,361		$	(2,254	)	$	2,107		$	4,984		$	(1,894	)	$	3,090
	Twelve Months Ended June 30, 2015									Twelve Months Ended June 30, 2014
	Before-			Tax			Net-of-			Before-			Tax			Net-of-
	Tax			(Expense)			Tax			Tax			(Expense)			Tax			Twelve Months Ended September 30, 2015									Twelve Months Ended September 30, 2014
	Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount			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:
Net actuarial gain/(loss)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214
Net actuarial gain (loss)																			$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214
Amortization of prior service cost		845			(321	)		524			355			(134	)		221			1,090			(414	)		676			355			(134	)		221
Amortization of net actuarial (gain)/loss		29,019			(11,027	)		17,992			28,915			(10,988	)		17,927			31,700			(12,046	)		19,654			26,285			(9,988	)		16,297
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			(6,661	)		2,531			(4,130	)		—			—			—
Regulatory adjustment		135,089			(51,334	)		83,755			(118,817	)		45,150			(73,667	)		132,480			(50,343	)		82,137			(116,412	)		44,236			(72,176	)

Pension plans other comprehensive income (loss)		(15,354	)		5,834			(9,520	)		10,798			(4,103	)		6,695			(15,037	)		5,713			(9,324	)		10,573			(4,017	)		6,556

FSIRS (designated hedging activities):
Amounts reclassifed into net income		3,344			(1,271	)		2,073			3,345			(1,271	)		2,074
Amounts reclassified into net income																				3,344			(1,270	)		2,074			3,345			(1,271	)		2,074

FSIRS other comprehensive income (loss)		3,344			(1,271	)		2,073			3,345			(1,271	)		2,074			3,344			(1,270	)		2,074			3,345			(1,271	)		2,074

Foreign currency translation adjustments:
Translation adjustments		(1,722	)		—			(1,722	)		—			—			—			(2,232	)		—			(2,232	)		—			—			—

Foreign currency other comprehensive income (loss)		(1,722	)		—			(1,722	)		—			—			—			(2,232	)		—			(2,232	)		—			—			—

Total other comprehensive income (loss)	$	(13,732	)	$	4,563		$	(9,169	)	$	14,143		$	(5,374	)	$	8,769		$	(13,925	)	$	4,443		$	(9,482	)	$	13,918		$	(5,288	)	$	8,630

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, 2015, will be reclassified into interest expense within the next 12 months, as the related interest payments on long-term debt occur.

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


AOCI - Rollforward (Thousands of dollars)
AOCI—Rollforward																														AOCI—Rollforward
(Thousands of dollars)																														(Thousands of dollars)
	Defined Benefit Plans									FSIRS									Foreign Currency Items												Defined Benefit Plans									FSIRS									Foreign Currency Items
	Before- Tax			Tax (Expense) Benefit			After- Tax			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			Before-Tax			Tax (Expense) Benefit		After-Tax			AOCI
Beginning Balance AOCI December 31, 2014	$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)		$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)

Translation adjustments		—			—			—			—			—			—			(1,063	)		—		(1,063	)		(1,063	)			—			—			—			—			—			—			(1,573	)		—		(1,573	)		(1,573	)

Other comprehensive income before reclassifications		—			—			—			—			—			—			(1,063	)		—		(1,063	)		(1,063	)			—			—			—			—			—			—			(1,573	)		—		(1,573	)		(1,573	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			1,672			(635	)		1,037			—			—		—			1,037				—			—			—			2,508			(952	)		1,556			—			—		—			1,556
Amortization of prior service cost (2)		667			(253	)		414			—			—			—			—			—		—			414				1,001			(380	)		621			—			—			—			—			—		—			621
Amortization of net actuarial loss (2)		17,191			(6,533	)		10,658			—			—			—			—			—		—			10,658				25,786			(9,799	)		15,987			—			—			—			—			—		—			15,987
Regulatory adjustment (3)		(15,574	)		5,918			(9,656	)		—			—			—			—			—		—			(9,656	)			(23,361	)		8,877			(14,484	)		—			—			—			—			—		—			(14,484	)

Net current period other comprehensive income (loss)		2,284			(868	)		1,416			1,672			(635	)		1,037			(1,063	)		—		(1,063	)		1,390				3,426			(1,302	)		2,124			2,508			(952	)		1,556			(1,573	)		—		(1,573	)		2,107
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(35	)		—		(35	)		(35	)			—			—			—			—			—			—			(55	)		—		(55	)		(55	)

Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		2,284			(868	)		1,416			1,672			(635	)		1,037			(1,028	)		—		(1,028	)		1,425				3,426			(1,302	)		2,124			2,508			(952	)		1,556			(1,518	)		—		(1,518	)		2,162

Ending Balance AOCI June 30, 2015	$	(54,927	)	$	20,872		$	(34,055	)	$	(21,016	)	$	7,986		$	(13,030	)	$	(1,665	)	$	—	$	(1,665	)	$	(48,750	)
Ending Balance AOCI September 30, 2015																															$	(53,785	)	$	20,438		$	(33,347	)	$	(20,180	)	$	7,669		$	(12,511	)	$	(2,155	)	$	—	$	(2,155	)	$	(48,013	)

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


Amounts Recognized in AOCI (Before Tax) (Thousands of dollars)
Amounts Recognized in AOCI (Before Tax)
(Thousands of dollars)
	June 30, 2015			December 31, 2014			September 30, 2015			December 31, 2014
Net actuarial (loss) gain	$	(421,940	)	$	(439,131	)	$	(413,345	)	$	(439,131	)
Prior service cost		(7,706	)		(8,373	)		(7,372	)		(8,373	)
Less: amount recognized in regulatory assets		374,719			390,293			366,932			390,293

Recognized in AOCI	$	(54,927	)	$	(57,211	)	$	(53,785	)	$	(57,211	)

In October 2014, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses. See the Company’s 2014 Form 10-K and the first quarter 2015 Form 10-Q for additional information about this acquisition.

Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed as incurred. The Company’s allocation of the purchase price was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included 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 types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. While refinements were made to the estimated fair values of assets acquired and liabilities assumed during the first quarter of 2015, no subsequent adjustments were made to ~~the~~ acquisition-date ~~values during the second quarter of 2015.~~values. The final purchase accounting has ~~not yet~~ been completed. Further refinement could occur; however, no material changes are expected. The revised preliminary estimated fair values of assets acquired and liabilities assumed as of October 1, 2014, are as follows (in millions of dollars):

~~The Company incurred and expensed acquisition costs of $5 million for the twelve months ended June 30, 2015. No acquisition costs were incurred during the six months ended June 30, 2015.~~

The preliminary allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill, which is generally not deductible for tax purposes, consists of the value associated with the assembled workforce and consolidation of operations. The business of Brigadier was acquired via asset purchase. Therefore, the $4.9 million of tax-basis goodwill assigned to Brigadier is expected to be deductible for tax purposes. All other goodwill associated with the acquisition is not deductible for tax purposes.

At the close of the acquisition discussed above, previous owners of the acquired companies retained an approximate 10% equity interest in the ~~Canadian businesses that were acquired.~~Canadian-specific businesses. The agreement, associated with ~~the~~that approximate 10% equity interest, ~~of the sellers, provides~~provided special dividend rights which ~~entitle~~entitled the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri, and subject to certain conditions, such interests ~~may~~could become exchangeable for a 3.4% equity interest in Centuri. In ~~June 2015,~~consideration of the underlying exchange rights of the original agreement, earnings attribution by Centuri to the previous owners ~~notified~~has also occurred in an amount equivalent to 3.4% of Centuri ~~of their intent to exchange their full equity interest in the Canadian businesses for an equity interest in Centuri, in accordance with the agreement. The exchange is anticipated to be completed in~~earnings since October 2014. During the third quarter of ~~2015. Additionally,~~2015, the sellers formally exercised their exchange rights under the terms of that original agreement. No new rights were conveyed to the noncontrolling parties as a result of the exchange and no new consideration was involved. The ability of the sellers to redeem their holdings for cash at specified dates remains intact. The previous owners may exit their investment retained by requiring the purchase of a portion of their interest commencing ~~October 2016~~July 2017 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election ~~after~~beginning in July 2022. Due to the continued ability of the noncontrolling parties to redeem their interest for cash, their interest continues to be presented on the Company’s Condensed Consolidated Balance Sheet at September ~~2021.~~

~~The Company has determined that this~~30, 2015 as a Redeemable noncontrolling interest, is a ~~redeemable noncontrolling interest and,~~category of mezzanine equity (temporary equity), in accordance with SEC ~~guidance,~~guidance. However, that interest, previously associated with the Canadian businesses, is ~~classified as mezzanine equity (temporary equity)~~now formally an interest in ~~the Consolidated Balance Sheets.~~ Centuri.

Significant changes in the value of the redeemable noncontrolling interest are recognized as they occur, and the carrying value is adjusted as necessary at each reporting date. ~~The~~Guidance by the SEC indicates that downward adjustments in the value of redeemable noncontrolling interests are only permitted to the extent that upward adjustments in value were previously recognized. A floor for the noncontrolling interest was originally set at the acquisition date (in October 2014). However, U.S. GAAP generally views changes in ownership interest, where the parent retains its controlling interest, as an equity transaction, whereby the carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. In connection with the exchange rights being exercised during the third quarter, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized, due in part to the exchange option no longer being subject to probability estimates. In light of the U.S. GAAP requirement to adjust the carrying amount, a new floor has been set for the redeemable noncontrolling interest at the exchange date, with a corresponding adjustment (approximately $6 million) made to additional paid in capital of the Company. Future adjustments to the redemption value ~~in 2015 impacted retained earnings, but did~~are not ~~impact net income.~~permitted below the new floor. The following depicts impacts to the balance of the redeemable noncontrolling interest between the indicated periods.

The redemption value of the redeemable noncontrolling interest ~~is based on a Monte Carlo simulation method. First,~~utilizes a market approach ~~was utilized~~ to determine a construction services enterprise ~~value as of the acquisition date.~~value. Potential guideline ~~publicly-traded~~publicly traded companies ~~were~~have been identified by using a selection criteria, including actively traded equities, their financial solvency, and other factors. Once the guideline companies ~~were~~are determined, enterprise value ~~was~~is calculated using a weighted approach of projected earnings before interest expense and taxes (“EBIT”) and earnings before interest expense, taxes, and depreciation and amortization expense (“EBITDA”). After an estimated fair value ~~was~~is determined, it is multiplied by 3.4%. A discount is then applied due to limitations of the nonpublic noncontrolling interest being valued. Prior to the exchange rights being exercised in the third quarter of 2015, a Monte Carlo simulation methodology was used to assign a value to the redeemable noncontrolling interest of the sellers. Other assumptions used in this analysis included dividends, probability of events, and a discount due to lack of control (the sellers do not influence operations). This method is employed no less frequently than annually.interest. Each quarter, market changes in the guideline companies are considered and the weighted approach to projected EBIT and EBITDA, in relation to the guideline companies, is re-evaluated to determine if value changes are necessary at each quarterly reporting date.

~~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, 2015, Southwest had 1,938,000 residential, commercial, industrial, and other natural gas customers, of which ~~1,036,000~~1,035,000 customers were located in Arizona, 713,000 in Nevada, and ~~189,000~~190,000 in California. Residential and commercial customers represented over 99% of the total customer base. During the twelve months ended ~~June~~September 30, 2015, 55% of operating margin was earned in Arizona, 34% in Nevada, and 11% 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 (including impacts of infrastructure trackers) 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.

Centuri Construction ~~Co.~~Group, Inc. (“Centuri” 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, and develops industrial construction solutions. Centuri operates in 20 major markets in the United States (primarily under the NPL name) and in 2 major markets in Canada (under the Link-Line and W.S. Nicholls names). 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 recent bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the U.S. 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. This is expected in both the U.S. and Canadian markets. In certain circumstances, such as with large bid contracts (especially those of a longer duration), or unit-price contracts with revenue caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid.

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 2014 Annual Report to Shareholders, which is incorporated by reference into the 2014 Form 10-K, and the first and second quarter 2015 reports on Form 10-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 ~~87%~~85% 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
	2015			2014		2015			2014		2015		2014		2015			2014			2015		2014		2015		2014
	(In thousands, except per share amounts)														(In thousands, except per share amounts)
Contribution to net income (loss)
Natural gas operations	$	(657	)	$	1,798	$	78,264		$	74,397	$	120,739	$	117,310	$	(18,939	)	$	(11,452	)	$	59,325	$	62,945	$	113,252	$	117,797
Construction services		5,606			7,829		(1,332	)		6,013		16,909		17,539		14,205			13,422			12,873		19,435		17,692		21,886

Net income	$	4,949		$	9,627	$	76,932		$	80,410	$	137,648	$	134,849
Net income (loss)															$	(4,734	)	$	1,970		$	72,198	$	82,380	$	130,944	$	139,683

Average number of common shares outstanding		46,869			46,502		46,741			46,471		46,628		46,407		47,102			46,513			46,863		46,485		46,777		46,451

Basic earnings per share
Basic earnings (loss) per share
Consolidated	$	0.11		$	0.21	$	1.65		$	1.73	$	2.95	$	2.91	$	(0.10	)	$	0.04		$	1.54	$	1.77	$	2.80	$	3.01

Natural Gas Operations Operating margin	$	177,628		$	173,494	$	476,981		$	468,610	$	885,102	$	870,290
Natural Gas Operations
Operating margin															$	155,152		$	153,040		$	632,133	$	621,650	$	887,214	$	876,045

Customer Growth.Southwest completed 22,000 first-time meter sets, but realized ~~28,000~~26,000 net new customers over the last twelve months, an increase of ~~1.5%~~1.4%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for the full year 2015.

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~~$235 million at ~~June~~September 30, 2015. 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 ~~$101~~$97.3 million at ~~June~~September 30, 2015 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. 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 the movements in the broader stock and bond markets. As indicated in Note 1 of the Notes to Consolidated Financial Statements, ~~changes in~~ cash surrender values of COLI policies (including incremental death benefits) ~~were $1.3~~decreased $3.9 million in the ~~first six months~~third quarter of 2015 and ~~$3.4 million~~decreased $200,000 in the twelve months ended ~~June~~September 30, 2015. These decreases are due to declines in the equity markets during the third quarter and during the last twelve months. Management ~~currently~~generally expects average returns of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized.

Liquidity.Southwest believes its liquidity position is sufficient. Southwest has a $300 million credit facility maturing in March 2020. The facility is provided through a consortium of eight major banking institutions. The maximum amount outstanding on the credit facility (including a commercial paper program) during the ~~second~~third quarter of 2015 was ~~$56 million. In May 2015,~~$97 million, which was also the ~~Company redeemed the $31.2 million 5.00% 2004 Series B IDRBs using cash on hand and the credit facility to fund the redemption. At June 30, 2015, $30 million was~~amount outstanding on the long-term portion of the credit facility (including ~~$25~~$50 million under the commercial paper program). at September 30, 2015. No borrowings were outstanding on the short-term portion of the credit facility. Southwest has no significant debt maturities prior to 2017. In September 2015, the Company redeemed the $20 million 5.25% 2003 Series D IDRBs primarily using cash on hand and borrowings under its $300 million credit facility.

~~Construction Services~~Centuri has a $300 million secured revolving credit and term loan facility maturing in October 2019. The facility is provided through a consortium of six banking institutions and consists of a $150 million term loan and a revolving line of credit of $150 million. The maximum amount outstanding on the credit facility during the ~~second~~third quarter of 2015 was ~~$276~~$225 million. At ~~June~~September 30, 2015, there was approximately ~~$34~~$47 million, net of letters of credit, available under the line of ~~credit, and $65 million in available capacity overall.~~credit.

The contribution to consolidated net income from natural gas operations decreased $2.5 million in the second quarter of 2015 compared to the second quarter of 2014. The decline was primarily due to an increase in operating expenses and a decrease in other income, partially offset by an increase in operating margin and a decrease in net interest deductions.

Operating margin increased $4$2 million between quarters. New customers contributed $2$1 million in operating margin during the ~~second~~third quarter of 2015, as approximately ~~28,000~~26,000 net new customers were added during the last twelve months. A combined $1 million of rate relief in the California jurisdiction and Paiute Pipeline Company (seeRates and Regulatory Proceedings) ~~contributed to~~provided the ~~increase. The remaining increase~~remainder of ~~$1 million in operating margin was associated with customers outside~~ the ~~decoupling mechanisms and higher other miscellaneous revenues.~~increase.

Operations and maintenance expense increased ~~$1.7~~$6.7 million, or 2%7%, between ~~quarters. General cost increases~~quarters and ~~higher~~included the impacts of a $3.2 million increase in employee pension ~~expense during~~and medical costs. Higher employee counts to effectively provide service to the ~~current quarter were partially offset by approximately $500,000 in rent expense in~~Company’s growing customer base and rising general costs also contributed to the ~~prior-year quarter associated with a portion of the corporate headquarters complex that the Company subsequently purchased in July 2014.~~increase.

Depreciation and amortization expense increased ~~$2.4~~$2.1 million, or 5%4%, between quarters. Average gas plant in service for the current quarter increased ~~$279~~$264 million, or 5%, 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. ~~Lower depreciation rates in California were offset by increased amortization associated with California energy efficiency programs and Nevada Gas Infrastructure Replacement (“GIR”) programs.~~

~~Taxes other than income taxes increased $1.4 million between quarters primarily due to higher property taxes in Arizona.~~

Other income, which principally includes returns on COLI policies and non-utility expenses, decreased ~~$2.5~~$4 million between quarters. The current quarter reflects ~~no recognized~~a $3.9 million decline in COLI-related income, while the prior-year quarter ~~included $2.3 million in COLI-related income, which exceeded management expectations.~~reflected COLI policy cash surrender value decreases of $300,000 (net of death benefits recognized).

Net interest deductions decreased ~~$1.3 million~~$900,000 between quarters. The decrease primarily resulted from the redemptions of $65 million 5.25% 2004 Series A IDRBs in November 2014 and $31.2 million 5.00% 2004 Series B IDRBs in May ~~2015. In addition,~~2015 and lower interest expense on variable rate IDRBs, ~~was lower in the current period compared to the same period of the prior year.~~partially offset by increased interest expense on PGA balances.


	Six Months Ended June 30,				Nine Months Ended September 30,
	2015		2014		2015			2014
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	839,758	$	757,972	$	1,059,178		$	983,999
Net cost of gas sold		362,777		289,362		427,045			362,349

Operating margin		476,981		468,610		632,133			621,650
Operations and maintenance expense		194,854		200,028		294,956			293,417
Depreciation and amortization		106,587		102,007		159,259			152,540
Taxes other than income taxes		25,411		22,421		37,063			34,256

Operating income		150,129		144,154		140,855			141,437
Other income (deductions)		2,914		4,460		(611	)		4,902
Net interest deductions		31,845		34,286		48,104			51,445

Income before income taxes		121,198		114,328		92,140			94,894
Income tax expense		42,934		39,931		32,815			31,949

Contribution to consolidated net income	$	78,264	$	74,397	$	59,325		$	62,945

The contribution to consolidated net income from natural gas operations ~~increased $3.9~~decreased $3.6 million in the first ~~six~~nine months of 2015 compared to the first ~~six~~nine months of 2014. The ~~improvement~~decline was primarily due to ~~an increase in operating margin and a decrease in net interest deductions, partially offset by~~ an increase in operating expenses and a decrease in other ~~income.~~income, partially offset by improved operating margin and a decline in net interest deductions.

Operating margin increased $8$10 million between the ~~six-month~~nine-month periods. New customers contributed $5$6 million in operating margin during the first ~~six~~nine months of 2015. A combined $3$4 million of rate relief in the California jurisdiction and Paiute Pipeline Company (seeRates and Regulatory Proceedings) ~~also contributed to~~provided the remainder of the increase.

Operations and maintenance expense ~~decreased $5.2~~increased $1.5 million between ~~periods. Legal~~periods, due primarily to general cost increases and higher pension expense during the current nine-month period. These increases were partially offset by certain expenses that were higher in the prior-year period, ~~were approximately $5.3 million higher than the current-year period primarily due to~~including a $5 million legal accrual in the first quarter of ~~2014. The prior-year period also included approximately~~2014 and $1.1 million in rent expense associated with a portion of the corporate headquarters complex that the Company subsequently purchased in July 2014. ~~Partially offsetting these decreases were general cost increases and higher pension expense during the current six-month period.~~

Depreciation and amortization expense increased ~~$4.6~~$6.7 million, or 4%, between periods. Average gas plant in service for the current period increased ~~$282~~$275 million, or 5%, 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. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in California.

Taxes other than income taxes increased $3$2.8 million between periods primarily due to higher property taxes in Arizona.

Other income decreased ~~$1.5~~$5.5 million between periods. The current period reflects COLI policy cash surrender value ~~increases~~decreases of ~~$1.3~~$2.6 million, while the prior-year period included ~~$3.2~~$2.9 million in COLI-related income.

Net interest deductions decreased ~~$2.4~~$3.3 million between periods. The decrease primarily resulted from the redemptions of $65 million 5.25% 2004 Series A IDRBs in November 2014 and $31.2 million 5.00% 2004 Series B IDRBs in May ~~2015. In addition,~~2015 and lower interest expense on variable rate IDRBs, ~~was lower in the current period compared to the same period of the prior year.~~partially offset by increased interest expense on PGA balances.


	Twelve Months Ended June 30,				Twelve Months Ended September 30,
	2015		2014		2015		2014
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	1,463,873	$	1,325,657	$	1,457,266	$	1,356,653
Net cost of gas sold		578,771		455,367		570,052		480,608

Operating margin		885,102		870,290		887,214		876,045
Operations and maintenance expense		378,558		392,920		385,271		390,328
Depreciation and amortization		208,724		199,790		210,863		201,896
Taxes other than income taxes		50,242		45,104		50,059		45,786

Operating income		247,578		232,476		241,021		238,035
Other income (deductions)		5,619		11,210		1,652		8,989
Net interest deductions		65,858		66,277		64,958		68,656

Income before income taxes		187,339		177,409		177,715		178,368
Income tax expense		66,600		60,099		64,463		60,571

Contribution to consolidated net income	$	120,739	$	117,310	$	113,252	$	117,797

Contribution to consolidated net income from natural gas operations ~~increased~~decreased by ~~$3.4~~$4.5 million between the twelve-month periods of 2015 and 2014. The ~~improvement~~decline was primarily due to an increase in operating ~~margin, partially offset by~~expenses and a decrease in other ~~income.~~income, partially offset by improved operating margin and lower net interest deductions.

Operating margin increased ~~$15~~$11 million between periods including a combined $9$5 million of rate relief in the California jurisdiction and Paiute Pipeline Company (seeRates and Regulatory Proceedings). Customer growth provided $8 million of the increase. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues declined by $2 million.

Operations and maintenance expense decreased ~~$14.4~~$5.1 million ~~or 4%,~~ between periods. Legal expenses in the prior-year period ~~(including~~were higher than the current-year period primarily due to a $5 million legal accrual in the first quarter of ~~2014) were $5.6 million higher than the current-year period.~~2014. Rent expense associated with the corporate headquarters complex declined ~~$2.2~~$1.6 million between periods. ~~General~~Partially offsetting these decreases were general cost increases ~~in the current period were more than offset by reductions in other costs including impacts of lower employee counts.~~and higher employee-related expenses.

Depreciation and amortization expense increased ~~$8.9~~$9 million, or 4%. Average gas plant in service for the current period increased ~~$297~~$288 million, or 6%5%, as compared to the prior 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 depreciation rate decreases ~~resulting from the most recent California general rate case decision.~~in California.

Taxes other than income taxes increased ~~$5.1~~$4.3 million between periods primarily due to higher property taxes in Arizona, ~~and Nevada,~~ principally related to net plant additions.

Other income decreased ~~$5.6~~$7.3 million between the twelve-month periods of 2015 and 2014. The current period reflects ~~$3.4 million of income associated with~~a $200,000 decline in COLI policy cash surrender ~~value increases,~~values, while the prior-year period included ~~$10~~$7.2 million of COLI-related ~~income. Interest~~ income ~~increased approximately $900,000 between periods primarily due to changes in over- and under-collected PGA balances (see~~~~PGA Filings~~ ~~for more information).~~including net death benefits recognized.

Net interest deductions decreased ~~$419,000~~$3.7 million between periods. The decrease primarily resulted from the redemptions of $65 million 5.25% 2004 Series A IDRBs in November 2014 and $31.2 million 5.00% 2004 Series B IDRBs in May ~~2015. The decrease was substantially~~2015 and lower interest expense on variable rate IDRBs, partially offset by ~~an increase in~~increased interest ~~deductions due to the issuance of $250 million of long-term debt in the fourth quarter of 2013.~~expense on PGA balances.


	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,
	2015			2014		2015			2014			2015			2014			2015			2014			2015			2014			2015			2014
(Thousands of dollars)
Construction revenues	$	251,961		$	181,674	$	433,066		$	303,577		$	869,109		$	661,595		$	285,976		$	206,448		$	719,042		$	510,025		$	948,637		$	675,728
Operating expenses:
Construction expenses		225,829			157,642		400,757			270,841			777,773			588,737			246,755			173,937			647,512			444,778			850,591			595,093
Depreciation and amortization		14,043			11,662		27,835			23,070			53,648			44,601			13,804			11,504			41,639			34,574			55,948			45,788

Operating income		12,089			12,370		4,474			9,666			37,688			28,257			25,417			21,007			29,891			30,673			42,098			34,847
Other income (deductions)		(150	)		15		(480	)		15			(553	)		44			(135	)		(2	)		(615	)		13			(686	)		37
Net interest deductions		1,968			246		3,849			538			7,081			1,079			2,142			262			5,991			800			8,961			1,024

Income before income taxes		9,971			12,139		145			9,143			30,054			27,222			23,140			20,743			23,285			29,886			32,451			33,860
Income tax expense (benefit)		4,251			4,310		1,467			3,216			13,027			10,076
Income tax expense																			8,411			7,364			9,878			10,580			14,074			12,217

Net income (loss)		5,720			7,829		(1,322	)		5,927			17,027			17,146
Net income																			14,729			13,379			13,407			19,306			18,377			21,643
Net income (loss) attributable to noncontrolling interests		114			—		10			(86	)		118			(393	)		524			(43	)		534			(129	)		685			(243	)

Contribution to consolidated net income (loss) attributable to Centuri	$	5,606		$	7,829	$	(1,332	)	$	6,013		$	16,909		$	17,539
Contribution to consolidated net income attributable to Centuri																		$	14,205		$	13,422		$	12,873		$	19,435		$	17,692		$	21,886

In October 2014, construction services operations were expanded by the acquisition of the Link-Line group of companies. Line items in the tables above reflect the results of the acquired companies only since the acquisition date.

Quarterly Analysis.Net income contribution for the current quarter increased $783,000 compared to the same period of 2014. The improvement was primarily due to additional pipe replacement work, partially offset by increases in depreciation and amortization and higher interest expense.

Revenues increased $79.5 million, or 39%, in the third quarter of 2015 when compared to the prior year period, due to the inclusion of revenues of the recently acquired companies ($41.4 million) and additional pipe replacement work. Governmental-mandated pipeline safety-related programs have resulted in many utilities undertaking multi-year distribution pipe replacement projects. NPL successfully bid on pipe replacement projects with its utility customers throughout the United States.

Construction expenses increased $72.8 million, or 42%, between quarters, due to costs associated with operations of the acquired companies ($39.2 million) and the additional pipe replacement work. Gains on sale of equipment (reflected as an offset to construction expenses) were approximately $450,000 and $1.5 million for the third quarters of 2015 and 2014, respectively. Depreciation and amortization expense increased $2.3 million between quarters due to amortization of finite-lived intangible assets recognized from the acquisition ($740,000) and incremental depreciation from the acquired companies ($1.3 million).

Net interest deductions were $2.1 million in the third quarter of 2015 compared to $262,000 in the third quarter of 2014. The increase was due primarily to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the acquisition of theLink-Line group of companies.

Nine-Month Analysis.Contribution to consolidated net income for the current ~~quarter~~nine-month period decreased ~~$2.2~~$6.6 million compared to the same period of 2014. The decline was primarily due to increases in depreciation and amortization, ~~and~~ higher interest ~~expense. An~~expense, and a $7.7 million loss reserve recorded on a construction project, partially offset by an increase in ~~construction revenues less construction expenses (gross profit) partially offset the decrease.~~pipe replacement work.

Revenues increased ~~$70.3~~$209 million, or ~~39%~~41%, in the current nine-month period when compared to the ~~second quarter~~same period of 2014, due in large part to revenues of the recently acquired companies ($~~37.9~~121.6 million) and additional pipe replacement ~~work at NPL.~~work. Construction expenses increased ~~$68.2~~$202.7 million, or ~~43%~~46%, between ~~quarters,~~periods, primarily due to ~~costs~~the operations associated with ~~operations of~~ the acquired companies ($~~38.2~~126.4 million) and the additional pipe replacement work noted above.

During the first ~~quarter~~half of 2015, construction expenses were impacted by a loss reserve of ~~$5.6~~$7.6 million recorded on an industrial construction project in Canada. In the ~~second~~third quarter of 2015, the loss reserve was increased by ~~$2 million~~$100,000 for a total of ~~$7.6~~$7.7 million. Delays in delivery of critical equipment to the job site resulted in production inefficiencies and an increase in total project costs. ~~The second quarter was also impacted by items necessary to be completed or corrected after initial construction (punch list) which continued to be addressed, and by change order adjustments.~~ Work commenced on this project in March 2015 and ~~is substantially complete. Other change orders previously submitted are being negotiated which may reduce~~was completed in the ~~estimated loss reserve in future periods.~~third quarter. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. ~~The final net profit~~Additional change orders previously submitted are being negotiated which may reduce the estimated loss reserve. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. Mediation is scheduled to occur in mid-November. Management cannot estimate the amount or ~~loss on this project may not be known until~~likelihood of a favorable resolution in mediation. If unsuccessful, Centuri will consider other options to resolve the ~~third quarter of 2015 or later.~~open change orders.

Gains on sale of equipment (reflected as an offset to construction expenses) were $1$3 million and $1.7 million for the second quarters of 2015 and 2014, respectively. Depreciation and amortization expense increased $2.4 million between quarters due to amortization of finite-lived intangible assets recognized from the acquisition ($1.4 million) and additional equipment purchases to support the growth in the volume of work being performed.

Net interest deductions were $2 million in the second quarter of 2015 compared to $246,000 in the second quarter of 2014. The increase was due primarily to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the acquisition of the businesses indicated earlier.

~~Six-Month Analysis.~~Contribution to consolidated net income for the current six-month period decreased $7.3 million compared to the same period of 2014. The decline was primarily due to increases in depreciation and amortization, higher interest expense, and the $7.6 million loss reserve recorded on a construction project disclosed in the~~Quarterly Analysis~~ ~~above.~~

Revenues increased $129.5 million, or 43%, when compared to the first six months of 2014, due in large part to revenues of the recently acquired companies ($80.2 million) and additional pipe replacement work at NPL. Construction expenses increased $130 million, or 48%, between periods, primarily due to the operations associated with the acquired companies ($87.2 million) and the additional pipe replacement work noted above. During the current period, construction expenses included a loss reserve of $7.6 million recorded on the construction project discussed in the~~Quarterly Analysis. Gains on sale of equipment (reflected as an offset to construction expenses) were $2.6 million and $4.1~~$5.7 million for the first ~~six~~nine months of 2015 and 2014, respectively. Depreciation and amortization expense increased ~~$4.8~~$7.1 million between periods due to amortization of finite-lived intangible assets ($~~2.7~~3.5 million) and ~~additional equipment purchases to support~~incremental depreciation from the ~~growth in the volume of work being performed.~~acquired companies ($3.6 million).

Net interest deductions were ~~$3.8~~$6 million in the first ~~six~~nine months of 2015 compared to ~~$538,000~~$800,000 in the first ~~six~~nine months of 2014. The increase was due primarily to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the acquisition.

Twelve-Month Analysis. Contribution to consolidated net income from construction services for the twelve-month period ended ~~June~~September 30, 2015 declined ~~$630,000~~$4.2 million compared to the same period of 2014. The decrease was primarily due to increases in depreciation and amortization and higher interest expense. An increase in ~~construction revenues less construction expenses (gross profit) substantially~~pipe replacement work partially offset the decrease.

Revenues increased ~~$207.5~~$272.9 million, or ~~31%~~40%, in the current twelve-month period compared to the same period of 2014 primarily due to additional pipe replacement work in the current period and the inclusion of revenues of the acquired companies ($~~134.5~~175.9 million) beginning in the fourth quarter of 2014. During the past several years, the construction services segment has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For the twelve months ended September 30, 2015 and 2014, revenues from replacement work were 68% and 70%, respectively, of total revenues.

Construction expenses increased ~~$189~~$255.5 million, or ~~32%~~43%, due to additional pipe replacement work ~~at NPL~~ during the twelve months ended ~~June~~September 30, 2015 and construction costs associated with the acquired companies ($~~136.6~~175.8 million). During the current period, construction expenses included athe loss reserve of ~~$7.6~~$7.7 million recorded on the construction project discussed in the~~Quarterly~~Nine-Month Analysis.above. General and administrative expense (included in construction expenses) increased ~~$15.3~~$15.6 million including ~~$8.3~~$14.2 million from the recently acquired companies and acquisition costs ($5 million). Offsetting these increases was approximately $4 million in the prior period associated with a legal settlement. Gains on sale of equipment (reflected as an offset to construction expenses) were ~~$4.6~~$3.5 million and $6$6.8 million for the ~~twelve month~~twelve-month periods of 2015 and 2014, respectively. Depreciation and amortization expense increased $9$10.2 million between the current and prior-year periods due to the amortization on finite-lived intangible assets recognized from the acquisition ($~~4.3~~5 million) and ~~additional equipment purchased to support growth in~~incremental depreciation from the ~~volume of work being performed.~~acquired companies ($4.8 million).

Net interest deductions were ~~$7.1~~$9 million for the twelve-month period ended ~~June~~September 30, 2015 compared to ~~$1.1~~$1 million for the corresponding period in 2014. The increase was due in large part to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the ~~recent~~ acquisition.

During the past several years, the construction services segment has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For the twelve months ended June 30, 2015 and 2014, revenues from replacement work were 65% and 70%, respectively, of total revenues. Governmental-mandated pipeline safety-related programs have resulted in many utilities undertaking multi-year distribution pipe replacement projects. Centuri continues to successfully bid on pipe replacement projects throughout the United States and Canada.

Customer-Owned Yardline (“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 offer to replace and relocate service lines and meters for approximately 100,000 Arizona customers whose meters are set off from the customer’s home, which is not a traditional configuration. Customers with this configuration are responsible for the cost of maintaining these lines and are subject to the immediate cessation of natural gas service if low-pressure leaks occur. To facilitate this program, the Company was authorized to collect estimated leak survey

costs in rates commencing in 2012. As a result of the leak survey and replacement efforts to date, the Company has determined that there are approximately ~~88,000~~84,500 remaining active COYL customers in Southwest’s Arizona service territory. Effective June 2013, the Arizona Corporation Commission (“ACC”) authorized a surcharge 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 general rate case. The surcharge is revised annually as the program progresses, with the undepreciated plant balance to be incorporated in rate base at the time of the next Arizona general rate case. In January 2014, the Company received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs, which was subsequently revised effective June 2014. Resources continue to be focused on contacting customers within replacement project areas to participate in the Phase II meter relocation. In February 2015, the Company filed to increase the surcharge revenue from $1.5 million to $2.5 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total ~~amounts spent to date~~capital expenditures of $16 million, $6.3 million of which was incurred during 2014. In May 2015, the ACC issued a decision approving the surcharge application, effective in June 2015.

~~Proposed~~ LNG (“Liquefied Natural Gas”) 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. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, operated by Southwest and connected directly to its distribution system. 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.~~. In December 2014, Southwest received an order from the ACC (“Order”) granting pre-approval of Southwest’s application to construct the LNG facility and the deferral of costs, up to $50 million. The authorization to defer costs expires November 1, 2017 (from which point, expenditures incurred would not be eligible for deferral) and also requires any unquantified cost savings to be deferred. ~~These deferred costs and benefits will be evaluated in a future rate proceeding.~~ Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. ~~Construction progress reports are required every six months until completion, beginning twelve months following~~The Company purchased the ~~issuance~~site for the facility in October 2015 and is preparing the construction requirements bid package for potential contractors. The contract to construct the facility is currently expected to be in place near the end of the ~~decision. Completion~~first quarter of ~~the siting requirements for flammable vapor dispersion is also a condition of approval for the facility. Construction~~2016 and construction is expected to ~~be completed by year-end 2017.~~take approximately two to three years to complete. The Company anticipates including a proposal for the ratemaking treatment of facility costs as part of its next Arizona rate case filing.

Infrastructure Replacement Mechanisms. In January 2014, the Public Utilities Commission of Nevada (“PUCN”) approved final rules for a mechanism to defer and recover certain costs associated with accelerated replacement of non-revenue producing infrastructure. The regulations provide 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 also allows Southwest to develop rates to recover the associated amounts in a future general rate case proceeding, at which time the plant will be “rolled into” rate base. Southwest made a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying early vintage plastic pipe (“EVPP”) and vintage steel pipe (“VSP”) projects for replacement beginning in January 2015. In October 2014, the PUCN approved EVPP replacement expenditures of $14.4 million for 2015. In June 2015, Southwest filed its GIR Advance Application with the PUCN ~~associated with replacement work at an estimated cost of $64 million,~~proposing $43.5 million of ~~which are proposed to be allocated to~~ accelerated pipe replacements (subject to the GIR mechanism)~~, resulting in an estimated~~. Once completed, the annualized revenue requirement ofassociated with the accelerated replacement is estimated at $4.6 million. ~~Management currently expects a decision, associated with these projects, during~~In October 2015, the ~~fourth quarter~~PUCN approved the GIR Advance Application, granting Southwest the authority to replace the $43.5 million of ~~2015. Also during~~infrastructure under the ~~fourth quarter of~~GIR mechanism. In October 2015, management ~~expects to file~~filed a rate application ~~associated with~~to reset the ~~estimated $14.4 million~~GIR surcharge to reflect annualized revenues of ~~projects preapproved in 2014.~~$4.5 million. The rate filing ~~will be~~was based upon projects placed in service by August 2015, with rates anticipated to be made effective in January 2016.

Expansion and Economic Development Legislation.In February 2015, legislation (“SB 151”) was introduced in Nevada to require the PUCN to adopt regulations authorizing natural gas utilities to expand their infrastructure consistent with a program of economic development. This includes providing natural gas service to unserved and underserved areas in Nevada, as well as attracting and retaining utility customers and accommodating the expansion of existing business customers. SB 151 was signed into law in May 2015. Draft regulations are being reviewed by the Legislative Council Bureau and final regulations are expected to be approved by the PUCN by the end of the year.

General Rate Case.Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary of Southwest, 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. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case. In October 2014, Paiute requested, and was granted, the authority to place the settlement rates into effect on an interim basis effective September 2014. In February 2015, the FERC issued a letter order approving the settlement as filed. Tariff charges in compliance with the settlement were filed in March 2015. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement resulted in an annual revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. ~~This increase is based on~~The settlement implies 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.

Elko County Expansion Project.During the second and third quarters of 2013, Paiute 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 is targeted to be in service by the end of 2015. 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. A preliminarily favorable environmental assessment of the proposed project was issued by the FERC in January 2015. In May 2015, the FERC issued an order authorizing a Certificate of Public Convenience and Necessity to Paiute to construct and operate the Elko County Expansion Project, and subsequently provided a formal Notice to Proceed. Construction began in the second quarter of 2015 and is progressing. The cost to complete this project has ~~begun, as the pipeline corridor~~been estimated at approximately $35 million and is ~~being readied for construction and pipe is beginning~~targeted to be ~~transported to~~in service by the ~~site for welding.~~end of 2015.

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, 2015, under-collections in ~~Arizona and~~ California resulted in an asset of ~~$3.7 million~~$815,000 and over-collections in Arizona and northern and southern Nevada collectively resulted in a liability of ~~$27.2~~$44.7 million on the Company’s consolidated balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during the first nine months of 2015. Tariff rates have been adjusted in all jurisdictions during this period. The gas cost rates for southern Nevada were further reduced in October to reduce the over-collected balance. 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 consolidated income statement components. These 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, 2015			December 31, 2014		June 30, 2014		September 30, 2015			December 31, 2014		September 30, 2014
Arizona	$	3.5		$	48.4	$	47.9	$	(6.0	)	$	48.4	$	44.3
Northern Nevada		(5.5	)		10.2		3.7		(4.3	)		10.2		6.7
Southern Nevada		(21.7	)		20.4		24.5		(34.4	)		20.4		21.7
California		0.2			8.6		4.3		0.8			8.6		5.6

	$	(23.5	)	$	87.6	$	80.4	$	(43.9	)	$	87.6	$	78.3

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). 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 minimize interest costs.

Operating Cash Flows. Cash flows provided by consolidated operating activities increased ~~$136.8~~$150.5 million in the first ~~six~~nine months of 2015 as compared to the same period of 2014. The improvement in operating cash flows was primarily attributable to temporary increases in cash flows from working capital components overall (notably the collection of deferred purchased gas costs).

Investing Cash Flows. Cash used in consolidated investing activities increased ~~$21.4~~$48.8 million in the first ~~six~~nine months of 2015 as compared to the same period of 2014. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by Centuri due to the increased replacement construction work of its customers. In association with the acquisition of construction services businesses, a $9 million working capital adjustment related to a contractual true-up period was made in the

first quarter of 2015. ~~In addition, the prior period included cash outflows restricted for the completion of the purchase of the corporate headquarters office complex which was in escrow at June 2014.~~

Financing Cash Flows. Net cash used in consolidated financing activities increased ~~$91.2~~$105.3 million in the first ~~six~~nine months of 2015 as compared to 2014. Repayments of long-term amounts outstanding on Southwest’s revolving credit and commercial paper facility were ~~$120 million and $10~~$53 million in the current period, and borrowings under the facility were $40 million in the prior-year ~~periods, respectively.~~period. An additional $5 million was repaid on the short-term portion of Southwest’s revolving credit facility in the current period. Repayment of long-term debt in the first ~~six~~nine months of 2015 included the repayment of the $31.2 million 5.00% 2004 Series B and $20 million 5.25% 2003 Series D IDRBs. The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under Centuri’s ~~line of credit.~~secured credit facility. The majority of Centuri’s borrowings during the twelve months ended ~~June~~September 30, 2015 are associated with the acquisition of construction services businesses noted previously. Southwest also issued approximately ~~$21~~$35 million in stock under its Equity Shelf Program. See alsoNote 5 – Common Stock, and the discussion below. Dividends paid increased in the first ~~six~~nine months of 2015 as compared to the first ~~six~~nine months of 2014 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, 2015, construction expenditures for the natural gas operations segment were ~~$378~~$384 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant. Cash flows from operating activities of Southwest were ~~$449~~$458 million during this time, which provided sufficient funding for construction expenditures and dividend requirements of the natural gas operations segment.

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2017 will be approximately $1.3 billion. Of this amount, approximately $445 million are expected to

be incurred in calendar year 2015. 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. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 75% 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.

In May 2015, the Company redeemed at par the $31.2 million 5.00% 2004 Series B IDRBs originally due in 2033. The Company facilitated the redemption primarily from cash on hand and borrowings under its $300 million credit facility. In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated the redemption primarily from cash on hand and borrowings under its $300 million credit facility.

In March 2015, the Company filed with the SEC a shelf registration statement which includes a prospectus detailing the Company’s plans to sell up to $100 million of the Company’s common stock over a period of time. In March 2015, the Company entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC relating to this issuance and sale of shares of the Company’s common stock (“Equity Shelf Program”). Sales of the shares will continue to be made at market prices prevailing at the time of sale. Net proceeds from the sale of shares of common stock under the Equity Shelf Program ~~will be used~~are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

During the ~~six~~nine months ended ~~June~~September 30, 2015, ~~372,509~~645,225 shares were issued in at-the-market offerings at an average price of ~~$55.74~~$55.05 per share with gross proceeds of ~~$20.8~~$35.5 million, agent commissions of ~~$208,000,~~$355,000, and net proceeds of ~~$20.6~~$35.2 million. SeeNote 5 – Common Stock for more information.

During the ~~six~~nine months ended ~~June~~September 30, 2015, the Company issued approximately ~~145,000~~207,000 additional shares of common stock collectively through the Restricted Stock/Unit Plan, the Management Incentive Plan, and the Stock Incentive

Plan. The Company raised approximately ~~$537,000~~$741,000 from the issuance of shares of common stock through the Stock Incentive Plan.

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 2015, the Board increased the quarterly dividend from 36.5 cents to 40.5 cents per share, effective with the June 2015 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 defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At ~~June~~September 30, 2015, the combined balance in the PGA accounts totaled an over-collection of ~~$23.5~~$43.9 million. SeePGA Filingsfor more information.

The Company has a $300 million revolving credit facility that is scheduled to expire in March 2020. 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, 2015, ~~$30~~$97 million was outstanding on the long-term portion of the credit facility (including ~~$25~~$50 million under the commercial paper program); there were no borrowings outstanding on the short-term portion. 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 operations and other types of external financing.

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, 2015, ~~$25~~$50 million was outstanding under this program.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. At ~~June~~September 30, 2015, ~~$235~~$209 million was outstanding on the Centuri secured credit facility.

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:


5241 Spring Mountain Road
Post Office Box 98510
Las Vegas, Nevada		89193-8510
(Address of principal executive offices)		(Zip Code)


	June 30, 2015		December 31, 2014
Contract notional amounts		7,838		5,105


	September 30, 2015		December 31, 2014
Contract notional amounts		8,192		5,105


	For the Twelve Months Ended
	June 30, 2015		December 31, 2014
Ratio of earnings to fixed charges		3.49		3.58


(In thousands of dollars)	Natural Gas Operations		Construction Services			Consolidated
December 31, 2014	$	10,095	$	133,065		$	143,160
Acquisition date adjustment		—		1,380			1,380
Foreign currency translation adjustment		—		(6,283	)		(6,283	)

June 30, 2015	$	10,095	$	128,162		$	138,257


	June 30, 2015		December 31, 2014
Centuri accounts receivable for services provided to Southwest	$	10,531	$	9,169


	Qualified Retirement Plan
	Period Ended June 30,
	Three Months						Six Months						Twelve Montls
	2015			2014			2015			2014			2015			2014
(Thousands of dollars)
Service cost	$	6,281		$	5,340		$	12,561		$	10,680		$	23,241		$	22,208
Interest cost		11,057			10,860			22,115			21,721			43,834			40,525
Expected return on plan assets		(14,452	)		(13,335	)		(28,904	)		(26,671	)		(55,575	)		(51,591	)
Amortization of net actuarial loss		8,186			5,718			16,371			11,436			27,808			27,566

Net periodic benefit cost	$	11,072		$	8,583		$	22,143		$	17,166		$	39,308		$	38,708


	SERP
	Period Ended June 30,
	Three Months						Six Months						Twelve Montls
	2015			2014			2015			2014			2015			2014
(Thousands of dollars)
Service cost	$	80		$	73		$	160		$	146		$	306		$	332
Interest cost		424			436			847			872			1,720			1,640
Amortization of net actuarial loss		323			196			647			392			1,038			877

Net periodic benefit cost	$	827		$	705		$	1,654		$	1,410		$	3,064		$	2,849


	PBOP
	Period Ended June 30,
	Three Months						Six Months						Twelve Montls
	2015			2014			2015			2014			2015			2014
(Thousands of dollars)
Service cost	$	410		$	275		$	821		$	551		$	1,371		$	1,161
Interest cost		750			708			1,499			1,415			2,913			2,656
Expected return on plan assets		(866	)		(816	)		(1,732	)		(1,632	)		(3,364	)		(3,044	)
Amortization of prior service costs		334			88			667			177			845			355
Amortization of net actuarial loss		86			—			173			—			173			472

Net periodic benefit cost	$	714		$	255		$	1,428		$	511		$	1,938		$	1,600


	Natural Gas Operations			Construction Services			Total
Three months ended June 30, 2015
Revenues from external customers	$	286,643		$	229,112		$	515,755
Intersegment revenues		—			22,849			22,849

Total	$	286,643		$	251,961		$	538,604

Segment net income (loss)	$	(657	)	$	5,606		$	4,949


Three months ended June 30, 2014
Revenues from external customers	$	271,479		$	156,966		$	428,445
Intersegment revenues		—			24,708			24,708

Total	$	271,479		$	181,674		$	453,153

Segment net income	$	1,798		$	7,829		$	9,627


	Natural Gas Operations			Construction Services			Total
Six months ended June 30, 2015
Revenues from external customers	$	839,758		$	390,201		$	1,229,959
Intersegment revenues		—			42,865			42,865

Total	$	839,758		$	433,066		$	1,272,824

Segment net income (loss)	$	78,264		$	(1,332	)	$	76,932


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


	Natural Gas Operations			Construction Services			Total
Twelve months ended June 30, 2015
Revenues from external customers	$	1,463,873		$	782,514		$	2,246,387
Intersegment revenues		—			86,595			86,595

Total	$	1,463,873		$	869,109		$	2,332,982

Segment net income	$	120,739		$	16,909		$	137,648


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


Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Thousands of dollars)
	Three Months Ended									Three Months Ended
	June 30, 2015									June 30, 2014
	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 prior service cost	$	334		$	(126	)	$	208		$	88		$	(33	)	$	55
Amortization of net actuarial (gain)/loss		8,595			(3,267	)		5,328			5,914			(2,248	)		3,666
Regulatory adjustment		(7,787	)		2,959			(4,828	)		(5,177	)		1,967			(3,210	)

Pension plans other comprehensive income (loss)		1,142			(434	)		708			825			(314	)		511

FSIRS (designated hedging activities):
Amounts reclassifed into net income		836			(318	)		518			837			(318	)		519

FSIRS other comprehensive income		836			(318	)		518			837			(318	)		519

Foreign currency translation adjustments:
Translation adjustments		209			—			209			—			—			—

Foreign currency other comprehensive income (loss)		209			—			209			—			—			—

Total other comprehensive income (loss)	$	2,187		$	(752	)	$	1,435		$	1,662		$	(632	)	$	1,030


Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss)
(Thousands of dollars)
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	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 prior service cost	$	334		$	(127	)	$	207		$	89		$	(34	)	$	55
Amortization of net actuarial (gain)/loss		8,595			(3,266	)		5,329			5,914			(2,247	)		3,667
Regulatory adjustment		(7,787	)		2,959			(4,828	)		(5,178	)		1,968			(3,210	)

Pension plans other comprehensive income (loss)		1,142			(434	)		708			825			(313	)		512

FSIRS (designated hedging activities):
Amounts reclassified into net income		836			(317	)		519			836			(318	)		518

FSIRS other comprehensive income		836			(317	)		519			836			(318	)		518

Foreign currency translation adjustments:
Translation adjustments		(510	)		—			(510	)		—			—			—

Foreign currency other comprehensive income (loss)		(510	)		—			(510	)		—			—			—

Total other comprehensive income (loss)	$	1,468		$	(751	)	$	717		$	1,661		$	(631	)	$	1,030


	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	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 prior service cost	$	667		$	(253	)	$	414		$	177		$	(67	)	$	110
Amortization of net actuarial (gain)/loss		17,191			(6,533	)		10,658			11,828			(4,495	)		7,333
Regulatory adjustment		(15,574	)		5,918			(9,656	)		(10,355	)		3,935			(6,420	)

Pension plans other comprehensive income (loss)		2,284			(868	)		1,416			1, 650			(627	)		1,023

FSIRS (designated hedging activities):
Amounts reclassifed into net income		1,672			(635	)		1,037			1,673			(636	)		1,037

FSIRS other comprehensive income		1,672			(635	)		1,037			1,673			(636	)		1,037

Foreign currency translation adjustments:
Translation adjustments		(1,063	)		—			(1,063	)		—			—			—

Foreign currency other comprehensive income (loss)		(1,063	)		—			(1,063	)		—			—			—

Total other comprehensive income (loss)	$	2,893		$	(1,503	)	$	1,390		$	3,323		$	(1,263	)	$	2,060


	Revised Acquisition Date
Cash, cash equivalents, and restricted cash	$	3
Contracts receivable and other receivables		62
Property, plant and equipment		17
Other assets		15
Intangible assets		52
Goodwill		131

Total assets acquired		280
Current liabilities		40
Deferred income tax - long-term		17
Other long-term liabilities		4

Net assets acquired	$	219


	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2014	$	20,042
Net income (loss) attributable to redeemable noncontrolling interest		(48	)
Foreign currency exchange translation adjustment		(35	)
Adjustment to redemption value		(658	)

Balance, June 30, 2015	$	19,301


	For the Twelve Months Ended
	September 30,		December 31,
	2015		2014
Ratio of earnings to fixed charges		3.32		3.58


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, 2015, 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, 2015~~

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company