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, ~~47,471,582~~47,481,930 shares as of ~~April 28,~~July 29, 2016.


	MARCH 31, 2016			DECEMBER 31, 2015			JUNE 30,			DECEMBER 31,
	MARCH 31, 2016			DECEMBER 31, 2015			2016			2015
ASSETS
Utility plant:
Gas plant	$	5,961,648		$	5,854,917		$	6,019,299		$	5,854,917
Less: accumulated depreciation		(2,110,238	)		(2,084,007	)		(2,134,661	)		(2,084,007	)
Acquisition adjustments, net		325			370			280			370
Construction work in progress		77,218			119,805			115,218			119,805

Net utility plant		3,928,953			3,891,085			4,000,136			3,891,085

Other property and investments		328,115			313,531			346,057			313,531

Current assets:
Cash and cash equivalents		60,809			35,997			12,126			35,997
Accounts receivable, net of allowances		271,314			314,512			263,855			314,512
Accrued utility revenue		45,100			74,700			32,500			74,700
Income taxes receivable, net		11,926			34,175			37,455			34,175
Deferred purchased gas costs		—			3,591			—			3,591
Prepaids and other current assets		81,079			95,199			85,826			95,199

Total current assets		470,228			558,174			431,762			558,174

Noncurrent assets:
Goodwill		132,774			126,145			144,086			126,145
Deferred income taxes		598			428			752			428
Deferred charges and other assets		455,340			469,322			444,047			469,322

Total noncurrent assets		588,712			595,895			588,885			595,895

Total assets	$	5,316,008		$	5,358,685		$	5,366,840		$	5,358,685

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 47,470,282 and 47,377,575 shares)	$	49,100		$	49,007
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 47,476,604 and 47,377,575 shares)							$	49,106		$	49,007
Additional paid-in capital		898,463			896,448			900,886			896,448
Accumulated other comprehensive income (loss), net		(48,386	)		(50,268	)		(47,195	)		(50,268	)
Retained earnings		753,105			699,221			741,148			699,221

Total Southwest Gas Corporation equity		1,652,282			1,594,408			1,643,945			1,594,408
Noncontrolling interest		(2,099	)		(2,083	)		(2,175	)		(2,083	)

Total equity		1,650,183			1,592,325			1,641,770			1,592,325
Redeemable noncontrolling interest		15,960			16,108			15,542			16,108
Long-term debt, less current maturities		1,388,968			1,551,204			1,427,805			1,551,204

Total capitalization		3,055,111			3,159,637			3,085,117			3,159,637

Current liabilities:
Current maturities of long-term debt		48,596			19,475			49,567			19,475
Short-term debt		—			18,000			—			18,000
Accounts payable		133,884			164,857			132,200			164,857
Customer deposits		72,903			72,631			72,814			72,631
Income taxes payable		8			940			7			940
Accrued general taxes		62,233			47,337			39,337			47,337
Accrued interest		21,814			16,173			15,849			16,173
Deferred purchased gas costs		100,987			45,601			126,299			45,601
Other current liabilities		137,642			150,031			146,648			150,031

Total current liabilities		578,067			535,045			582,721			535,045

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		789,961			769,445			817,855			769,445
Accumulated removal costs		304,000			303,000			306,000			303,000
Other deferred credits and other long-term liabilities		588,869			591,558			575,147			591,558

Total deferred income taxes and other credits		1,682,830			1,664,003			1,699,002			1,664,003

Total capitalization and liabilities	$	5,316,008		$	5,358,685		$	5,366,840		$	5,358,685


													THREE MONTHS ENDED						SIX MONTHS ENDED						TWELVE MONTHS ENDED
	THREE MONTHS ENDED MARCH 31,						TWELVE MONTHS ENDED MARCH 31,						JUNE 30,						JUNE 30,						JUNE 30,
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
Operating revenues:
Gas operating revenues	$	525,100		$	553,115		$	1,426,624		$	1,448,709		$	255,648		$	286,643		$	780,748		$	839,758		$	1,395,629		$	1,463,873
Construction revenues		206,148			181,105			1,034,029			798,822			292,100			251,961			498,248			433,066			1,074,168			869,109

Total operating revenues		731,248			734,220			2,460,653			2,247,531			547,748			538,604			1,278,996			1,272,824			2,469,797			2,332,982

Operating expenses:
Net cost of gas sold		213,600			253,762			523,647			567,741			71,416			109,015			285,016			362,777			486,048			578,771
Operations and maintenance		100,797			95,510			398,486			376,834			98,744			99,344			199,541			194,854			397,886			378,558
Depreciation and amortization		75,360			67,467			278,004			257,603			72,559			66,955			147,919			134,422			283,608			262,372
Taxes other than income taxes		14,013			12,997			50,409			48,793			12,987			12,414			27,000			25,411			50,982			50,242
Construction expenses		193,382			174,928			917,235			709,586			263,926			225,829			457,308			400,757			955,332			777,773

Total operating expenses		597,152			604,664			2,167,781			1,960,557			519,632			513,557			1,116,784			1,118,221			2,173,856			2,047,716

Operating income		134,096			129,556			292,872			286,974			28,116			25,047			162,212			154,603			295,941			285,266

Other income and (expenses):
Net interest deductions		(17,721	)		(17,977	)		(71,623	)		(72,527	)		(18,221	)		(17,717	)		(35,942	)		(35,694	)		(72,127	)		(72,939	)
Other income (deductions)		1,721			2,272			2,328			7,767			2,470			162			4,191			2,434			4,636			5,066

Total other income and (expenses)		(16,000	)		(15,705	)		(69,295	)		(64,760	)		(15,751	)		(17,555	)		(31,751	)		(33,260	)		(67,491	)		(67,873	)

Income before income taxes		118,096			113,851			223,577			222,214			12,365			7,492			130,461			121,343			228,450			217,393
Income tax expense		42,741			41,972			80,671			79,884			3,266			2,429			46,007			44,401			81,508			79,627

Net income		75,355			71,879			142,906			142,330			9,099			5,063			84,454			76,942			146,942			137,766
Net income (loss) attributable to noncontrolling interests		(91	)		(104	)		1,126			4			156			114			65			10			1,168			118

Net income attributable to Southwest Gas Corporation	$	75,446		$	71,983		$	141,780		$	142,326		$	8,943		$	4,949		$	84,389		$	76,932		$	145,774		$	137,648

Basic earnings per share	$	1.59		$	1.54		$	3.00		$	3.06		$	0.19		$	0.11		$	1.78		$	1.65		$	3.08		$	2.95

Diluted earnings per share	$	1.58		$	1.53		$	2.98		$	3.03		$	0.19		$	0.10		$	1.77		$	1.63		$	3.06		$	2.92

Dividends declared per share	$	0.450		$	0.405		$	1.665		$	1.500		$	0.450		$	0.405		$	0.900		$	0.810		$	1.710		$	1.540

Average number of common shares outstanding		47,437			46,612			47,196			46,537			47,473			46,869			47,455			46,741			47,347			46,628
Average shares outstanding (assuming dilution)		47,763			47,036			47,562			46,986			47,811			47,290			47,787			47,164			47,693			47,070


													THREE MONTHS ENDED						SIX MONTHS ENDED						TWELVE MONTHS ENDED
	THREE MONTHS ENDED MARCH 31,						TWELVE MONTHS ENDED MARCH 31,						JUNE 30,						JUNE 30,						JUNE 30,
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
Net income	$	75,355		$	71,879		$	142,906		$	142,330		$	9,099		$	5,063		$	84,454		$	76,942		$	146,942		$	137,766

Other comprehensive income (loss), net of tax
Defined benefit pension plans:
Net actuarial gain (loss)		—			—			(18,922	)		(107,661	)		—			—			—			—			(18,922	)		(107,661	)
Amortization of prior service cost		207			206			829			371			207			208			414			414			828			524
Amortization of net actuarial loss		4,196			5,330			20,182			16,330			4,194			5,328			8,390			10,658			19,048			17,992
Prior service cost		—			—			—			(4,130	)		—			—			—			—			—			(4,130	)
Regulatory adjustment		(3,796	)		(4,828	)		(2,468	)		85,373			(3,796	)		(4,828	)		(7,592	)		(9,656	)		(1,436	)		83,755

Net defined benefit pension plans		607			708			(379	)		(9,717	)		605			708			1,212			1,416			(482	)		(9,520	)

Forward-starting interest rate swaps:
Amounts reclassified into net income		519			519			2,073			2,074			519			518			1,038			1,037			2,074			2,073

Net forward-starting interest rate swaps		519			519			2,073			2,074			519			518			1,038			1,037			2,074			2,073

Foreign currency translation adjustments		782			(1,272	)		100			(1,931	)		70			209			852			(1,063	)		(39	)		(1,722	)

Total other comprehensive income (loss), net of tax		1,908			(45	)		1,794			(9,574	)		1,194			1,435			3,102			1,390			1,553			(9,169	)

Comprehensive income		77,263			71,834			144,700			132,756			10,293			6,498			87,556			78,332			148,495			128,597
Comprehensive income (loss) attributable to noncontrolling interests		(65	)		(147	)		1,129			(61	)		159			122			94			(25	)		1,166			61

Comprehensive income attributable to Southwest Gas Corporation	$	77,328		$	71,981		$	143,571		$	132,817		$	10,134		$	6,376		$	87,462		$	78,357		$	147,329		$	128,536


													SIX MONTHS ENDED						TWELVE MONTHS ENDED
	THREE MONTHS ENDED MARCH 31						TWELVE MONTHS ENDED MARCH 31						JUNE 30						JUNE 30
	2016			2015			2016			2015			2016			2015			2016			2015
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	75,355		$	71,879		$	142,906		$	142,330		$	84,454		$	76,942		$	146,942		$	137,766
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		75,360			67,467			278,004			257,603			147,919			134,422			283,608			262,372
Deferred income taxes		18,931			7,584			60,132			58,201			45,916			3,896			90,805			43,712
Changes in current assets and liabilities:
Accounts receivable, net of allowances		45,525			(31,850	)		37,525			(49,491	)		52,907			6,018			7,039			(33,662	)
Accrued utility revenue		29,600			29,500			(700	)		(300	)		42,200			42,100			(700	)		(200	)
Deferred purchased gas costs		58,977			59,423			129,120			47,063			84,289			111,021			102,834			103,906
Accounts payable		(35,126	)		(49,173	)		10,556			(24,031	)		(33,358	)		(38,471	)		1,622			11,704
Accrued taxes		36,298			49,782			(21,889	)		2,809			(12,121	)		7,614			(28,140	)		(1,158	)
Other current assets and liabilities		6,776			31,548			(6,472	)		18,405			5,793			5,163			18,930			(17,696	)
Gains on sale		(1,333	)		(1,526	)		(2,909	)		(5,268	)		(2,742	)		(2,563	)		(3,281	)		(4,597	)
Changes in undistributed stock compensation		1,394			462			3,846			5,674			3,514			1,512			4,916			5,719
AFUDC		(532	)		(396	)		(3,144	)		(1,893	)		(1,282	)		(1,133	)		(3,157	)		(2,104	)
Changes in other assets and deferred charges		(291	)		(13,336	)		(1,121	)		(23,934	)		223			(15,239	)		1,296			(21,821	)
Changes in other liabilities and deferred credits		1,719			876			11,706			(500	)		(2,502	)		2,954			5,407			(729	)

Net cash provided by operating activities		312,653			222,240			637,560			426,668			415,210			334,236			628,121			483,212

CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(112,561	)		(90,391	)		(510,170	)		(410,397	)		(264,872	)		(203,640	)		(549,232	)		(425,094	)
Acquisition of businesses, net of cash acquired		—			(9,261	)		—			(199,758	)		(17,000	)		(9,261	)		(17,000	)		(199,758	)
Restricted cash		—			—			785			1,233			—			785			—			18,667
Changes in customer advances		3,661			5,446			16,515			21,704			2,152			9,689			10,763			21,105
Miscellaneous inflows		1,126			2,835			6,645			10,853			4,126			4,892			7,588			9,443
Miscellaneous outflows		—			—			—			(1,400	)		—			—			—			(1,400	)

Net cash used in investing activities		(107,774	)		(91,371	)		(486,225	)		(577,765	)		(275,594	)		(197,535	)		(547,881	)		(577,037	)

CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		401			8,791			27,006			9,089			487			20,713			15,170			20,881
Dividends paid		(19,220	)		(17,023	)		(76,445	)		(67,955	)		(40,583	)		(36,001	)		(78,830	)		(69,960	)
Centuri distribution to redeemable noncontrolling interest		(99	)		—			(198	)		—			(99	)		—			(198	)		—
Issuance of long-term debt, net		49,375			50,295			134,896			318,498			96,128			93,165			138,779			344,674
Retirement of long-term debt		(42,312	)		(18,082	)		(212,203	)		(153,456	)		(52,966	)		(78,409	)		(162,530	)		(206,848	)
Change in credit facility and commercial paper		(150,000	)		(150,000	)		—			—			(147,500	)		(120,000	)		(27,500	)		30,000
Change in short-term debt		(18,000	)		(5,000	)		—			—			(18,000	)		(5,000	)		—			—
Principal payments on capital lease obligations		(313	)		(386	)		(1,347	)		(820	)		(835	)		(722	)		(1,533	)		(1,156	)
Other		142			(329	)		512			(1,066	)		(124	)		(534	)		451			(1,319	)

Net cash provided by (used in) financing activities		(180,026	)		(131,734	)		(127,779	)		104,290			(163,492	)		(126,788	)		(116,191	)		116,272

Effects of currency translation on cash and cash equivalents		(41	)		(688	)		(760	)		(546	)		5			(570	)		(832	)		(428	)

Change in cash and cash equivalents		24,812			(1,553	)		22,796			(47,353	)		(23,871	)		9,343			(36,783	)		22,019
Cash and cash equivalents at beginning of period		35,997			39,566			38,013			85,366			35,997			39,566			48,909			26,890

Cash and cash equivalents at end of period	$	60,809		$	38,013		$	60,809		$	38,013		$	12,126		$	48,909		$	12,126		$	48,909

Supplemental information:
Interest paid, net of amounts capitalized	$	10,593		$	10,497		$	66,719		$	65,575		$	33,224		$	34,213		$	65,634		$	67,978
Income taxes paid		2,136			2,101			43,260			26,110			4,737			28,479			19,483			40,480

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 higher during winter periods due to the seasonality incorporated in its regulatory rate structures. Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a 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”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd. ~~(“Link-Line”~~), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). The Company acquired ~~Link-Line,~~the businesses associated with NPL Canada, W.S. Nicholls, and Brigadier in October 2014. In May 2016, ~~the Link-Line name was changed to NPL Canada Ltd.~~Centuri acquired two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”). SeeAcquisition of Construction Services Businessesbelow for more information. 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 2015 Annual Report to Shareholders, which is incorporated by reference into the 2015 Form ~~10-K.~~10-K, and the first quarter 2016 Form 10-Q.

Prepaids and other current assets. Prepaids and other current assets includes gas pipe materials and operating supplies of ~~$27~~$29 million at ~~March 31,~~June 30, 2016 and $24 million at December 31, 2015 (carried at weighted average cost), and also includes natural gas stored underground and liquefied natural gas, in addition to prepaid assets.

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 ~~March 31,~~June 30, 2016 and December 31, 2015 also include two money market fund investments totaling approximately ~~$11.3 million~~$270,000 and $250,000, respectively, 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 ~~$900,000~~$2.5 million and ~~$700,000,~~$2 million, during the first ~~three~~six months of 2016 and 2015, respectively, were applied as contributions toward utility construction activity and represent non-cash investing activity. ~~In addition, approximately $2.3 million in proceeds from common stock sales during March 2015 associated with the Equity Shelf Program (see~~~~Note 5 – Common Stock)~~~~were received after March 31, 2015 and represented a non-cash financing activity in the prior year.~~

Goodwill. Goodwill is assessed each October for impairment (required annually by U.S. GAAP), or otherwise, if circumstances indicate impairment to the carrying value of goodwill may have occurred. No such circumstances indicating impairment ~~was~~were deemed to have occurred in the first ~~three~~six months of 2016. The business acquisition of ETTI was deemed an asset purchase for tax purposes. As a result, approximately $11 million in goodwill associated with ETTI is expected to be tax deductible.


(In thousands of dollars)	Natural Gas Operations		Construction Services		Consolidated		Natural Gas Operations		Construction Services		Consolidated
December 31, 2015	$	10,095	$	116,050	$	126,145	$	10,095	$	116,050	$	126,145
Additional goodwill from ETTI acquisition								—		10,726		10,726
Foreign currency translation adjustment		—		6,629		6,629		—		7,215		7,215

March 31, 2016	$	10,095	$	122,679	$	132,774
June 30, 2016							$	10,095	$	133,991	$	144,086

Acquisition of Construction Services Businesses.In May 2016, Centuri completed the acquisition of ETTI, which is based in Lisbon Falls, Maine, and has a primary focus on underground utility installation using horizontal directional drilling technology. The acquisition of ETTI will provide complimentary operational support to Brigadier and expand operations into Maine. Neither the acquisition itself nor the impacts to assets and operations are material to the construction services segment or the Company.

Assets acquired in the transaction were recorded at their acquisition date fair values. The final purchase accounting has not yet been completed. Further refinement could occur; however, no material changes are expected. The preliminary estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):

The purchase price consisted of $17 million in cash on the acquisition date with the remaining amount being deferred over four years.

Intercompany Transactions. Centuri recognizes revenues generated from contracts with Southwest (seeNote 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~~(thousands of dollars):


	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Centuri property and equipment	$	433		$	423		$	458,031		$	423,369
Centuri accumulated provision for depreciation and amortization		(216	)		(221	)		(225,539	)		(221,028	)
Net cash surrender value of COLI policies		100			99			102,233			99,276
Other property		11			13			11,332			11,914

Total	$	328		$	314		$	346,057		$	313,531

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						Twelve Months Ended						Three Months Ended						Six Months Ended						Twelve Months Ended
	March 31						March 31						June 30						June 30						June 30
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
Change in COLI policies	$	900		$	1,300		$	(900	)	$	5,700		$	2,200		$	—		$	3,100		$	1,300		$	1,300		$	3,400
Interest income		367			590			1,950			2,695			391			161			758			751			2,180			2,244
Equity AFUDC		532			396			3,144			1,894			750			737			1,282			1,133			3,157			2,104
Foreign transaction gain (loss)		(10	)		(327	)		(507	)		(505	)		(9	)		(245	)		(19	)		(572	)		(271	)		(750	)
Miscellaneous income and (expense)		(68	)		313			(1,359	)		(2,017	)		(862	)		(491	)		(930	)		(178	)		(1,730	)		(1,932	)

Total other income (deductions)	$	1,721		$	2,272		$	2,328		$	7,767		$	2,470		$	162		$	4,191		$	2,434		$	4,636		$	5,066

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 athe 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 July 2015, the FASB approved a one-year deferral of the effective date (annual periods beginning after December 15, 2017) and permitted entities to adopt one year earlier (i.e., the original effective date) if they choose. In March, April, and May of 2016, the FASB issued the updates “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing”, and “Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients”. The amendments in the first two updates, respectively, provide guidance when another party, along with the entity, is involved in providing a good or service to a customer, and clarification of identifying performance obligations and the licensing implementation guidance in Topic 606. The third update includes narrow-scope improvements to the guidance on collectability, noncash consideration, and completed contracts at transition. In addition, a practical expedient is provided for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The collective amendments do not change the core principle of the guidance in Topic 606. The Company plans to adopt ~~the update~~all of these updates 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~~these updates 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 not expected to have a material impact on the Company’s disclosures.

In January 2016, the FASB issued the update “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” in order to improve the recognition and measurement of financial instruments. The update makes targeted improvements to existing U.S. GAAP by: 1) requiring equity investments to be measured at fair value with changes in fair value recognized in net income; 2) requiring the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes; 3) requiring separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements; 4) eliminating the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; and 5) requiring a reporting entity to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in ~~the~~ instrument-specific credit risk when the organization has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. All entities can early adopt the provision to record fair value changes for financial liabilities under the fair value option resulting from instrument-specific credit risk in other comprehensive income. The Company is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

In February 2016, the FASB issued the update “Leases (Topic 842)”. Under the update, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Though companies have historically been required to make disclosures regarding leases and of contractual obligations, leases (with terms longer than a year) will no longer exist off-balance sheet. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. Early application is permitted. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2019. The Company is evaluating what impact this update might have on its consolidated financial statements and disclosures.

In March 2016, the FASB issued the update “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. The amendments relate to when another party, along with the entity, is involved in providing a good or service to a customer. Topic 606 Revenue from Contracts with Customers requires an entity to determine whether the nature of its promise is to provide that good or service to the

customer (i.e., the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (i.e., the entity is an agent). The amendments are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. The effective date and transition of these amendments is the same as the effective date and transition of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). 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 March 2016, the FASB issued the update~~ “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The update requires the recording of all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then recorded in the income statement. While the simplification will reduce some of the administrative complexities by eliminating the need to track a “windfall pool,” it will increase the volatility of income tax expense. The update also allows entities to withhold shares for the employee tax burden up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in a liability classification of the award (currently such withholding is limited to the employer’s minimum statutory withholding). The update clarifies that all cash payments made to taxing authorities on the employees’ behalf for withheld shares should be presented as financing activities on the statement of cash

flows. Also, the update requires all tax-related cash flows resulting from share-based payments be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company issues share-based payment awards to its employees and is evaluating the impacts this update might have on its consolidated financial statements and disclosures.

In ~~April~~June 2016, the FASB issued the update ~~“Revenue from Contracts with Customers~~“Financial Instruments—Credit Losses (Topic ~~606)~~326): ~~Identifying Performance Obligations and Licensing”~~Measurement of Credit Losses on Financial Instruments”. The update ~~clarifies~~amends guidance on reporting credit losses for financial assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, the ~~following aspects~~update eliminates the “probable” threshold for initial recognition of ~~Topic 606: (a) identifying performance obligations;~~credit losses in current U.S. GAAP and, ~~(b)~~instead, requires an entity to reflect its current estimate of all expected credit losses. The allowance for credit losses is a valuation account that is deducted from the ~~licensing implementation guidance. The amendments do not change the core principle~~amortized cost basis of the ~~guidance~~financial asset to present the net amount expected to be collected. For available for sale debt securities, credit losses should be measured in ~~Topic 606. Entities~~a manner similar to current U.S. GAAP, however the update will require that credit losses be presented as an allowance rather than as a write-down. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The update affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. All entities may ~~choose between two retrospective transition methods when applying the update. The Company plans to~~ adopt the amendments in this update atearlier as of the ~~required adoption date, which is for~~fiscal years beginning after December 15, 2018, including interim ~~and annual reporting~~ periods ~~commencing January 1, 2018. The transition methods and the adoption date are the same as~~within those ~~disclosed for the May 2014 Topic 606 update noted above.~~fiscal years. The Company is evaluating what impact, if any, this update might have on its 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.


	Qualified Retirement Plan												Qualified Retirement Plan
	Period Ended March 31,												Period Ended June 30,
	Three Months						Twelve Months						Three Months						Six Months						Twelve Months
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
(Thousands of dollars)
Service cost	$	5,709		$	6,280		$	24,552		$	22,300		$	5,708		$	6,281		$	11,417		$	12,561		$	23,979		$	23,241
Interest cost		11,506			11,058			44,677			43,637			11,507			11,057			23,013			22,115			45,127			43,834
Expected return on plan assets		(14,140	)		(14,452	)		(57,496	)		(54,458	)		(14,139	)		(14,452	)		(28,279	)		(28,904	)		(57,183	)		(55,575	)
Amortization of net actuarial loss		6,317			8,185			30,875			25,340			6,316			8,186			12,633			16,371			29,005			27,808

Net periodic benefit cost	$	9,392		$	11,071		$	42,608		$	36,819		$	9,392		$	11,072		$	18,784		$	22,143		$	40,928		$	39,308


	SERP												SERP
	Period Ended March 31,												Period Ended June 30,
	Three Months						Twelve Months						Three Months						Six Months						Twelve Months
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
(Thousands of dollars)
Service cost	$	82		$	80		$	322		$	299		$	83		$	80		$	165		$	160		$	325		$	306
Interest cost		465			423			1,737			1,732			465			424			930			847			1,778			1,720
Amortization of net actuarial loss		346			324			1,315			911			346			323			692			647			1,338			1,038

Net periodic benefit cost	$	893		$	827		$	3,374		$	2,942		$	894		$	827		$	1,787		$	1,654		$	3,441		$	3,064


	PBOP												PBOP
	Period Ended March 31,												Period Ended June 30,
	Three Months						Twelve Months						Three Months						Six Months						Twelve Months
	2016			2015			2016			2015			2016			2015			2016			2015			2016			2015
(Thousands of dollars)
Service cost	$	374		$	411		$	1,604		$	1,236		$	375		$	410		$	749		$	821		$	1,569		$	1,371
Interest cost		796			749			3,046			2,871			795			750			1,591			1,499			3,091			2,913
Expected return on plan assets		(788	)		(866	)		(3,386	)		(3,314	)		(787	)		(866	)		(1,575	)		(1,732	)		(3,307	)		(3,364	)
Amortization of prior service costs		334			333			1,336			599			334			334			668			667			1,336			845
Amortization of net actuarial loss		104			87			362			87			104			86			208			173			380			173

Net periodic benefit cost	$	820		$	714		$	2,962		$	1,479		$	821		$	714		$	1,641		$	1,428		$	3,069		$	1,938

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


		Natural Gas		Construction					Natural Gas			Construction
		Operations		Services			Total		Operations			Services			Total
Three months ended March 31, 2016
Three months ended June 30, 2016
Revenues from external customers		$	525,100	$	183,961		$	709,061	$	255,648		$	266,343		$	521,991
Intersegment revenues			—		22,187			22,187		—			25,757			25,757

Total		$	525,100	$	206,148		$	731,248	$	255,648		$	292,100		$	547,748
	��
Segment net income (loss)		$	77,583	$	(2,137	)	$	75,446
Segment net income									$	2,358		$	6,585		$	8,943

Three months ended March 31, 2015
Three months ended June 30, 2015
Revenues from external customers		$	553,115	$	161,089		$	714,204	$	286,643		$	229,112		$	515,755
Intersegment revenues			—		20,016			20,016		—			22,849			22,849

Total		$	553,115	$	181,105		$	734,220	$	286,643		$	251,961		$	538,604

Segment net income (loss)		$	78,921	$	(6,938	)	$	71,983	$	(657	)	$	5,606		$	4,949


		Natural Gas		Construction					Natural Gas			Construction
		Operations		Services			Total		Operations			Services			Total
Twelve months ended March 31, 2016
Six months ended June 30, 2016
Revenues from external customers		$	1,426,624	$	927,742		$	2,354,366	$	780,748		$	450,304		$	1,231,052
Intersegment revenues			—		106,287			106,287		—			47,944			47,944

Total		$	1,426,624	$	1,034,029		$	2,460,653	$	780,748		$	498,248		$	1,278,996

Segment net income		$	110,287	$	31,493		$	141,780	$	79,941		$	4,448		$	84,389

Twelve months ended March 31, 2015
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


									Natural Gas			Construction
									Operations			Services			Total
Twelve months ended June 30, 2016
Revenues from external customers		$	1,448,709	$	710,368		$	2,159,077	$	1,395,629		$	964,973		$	2,360,602
Intersegment revenues			—		88,454			88,454		—			109,195			109,195

Total		$	1,448,709	$	798,822		$	2,247,531	$	1,395,629		$	1,074,168		$	2,469,797

Segment net income		$	123,194	$	19,132		$	142,326	$	113,302		$	32,472		$	145,774

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

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 ~~April~~July 2016 through March 2018. Under such contracts, Southwest pays the counterparty a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):

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

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the three-, six-, and twelve-month periods ended ~~March 31,~~June 30, 2016 and 2015 and their location in the Condensed Consolidated Statements of Income:

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


Instrument	Location of Gain or (Loss) Recognized in Income on Derivative		Three Months Ended						Twelve Months Ended
			March 31						March 31
																Three Months Ended							Six Months Ended							Twelve Months Ended
															Location of Gain or (Loss)		June 30							June 30							June 30
Instrument		Location of Gain or (Loss) Recognized in Income on Derivative		2016			2015			2016			2015			Recognized in Income on Derivative		2016			2015				2016			2015				2016			2015
			$	(1,212	)	$	(2,114	)	$	(6,696	)	$	(10,467	)	Net cost of gas sold		$	5,537		$	707			$	4,325		$	(1,407	)		$	(1,866	)	$	(9,677	)
				1,212	*		2,114	*		6,696	*		10,467	*	Net cost of gas sold			(5,537	)*		(707	)*			(4,325	)*		1,407	*			1,866	*		9,677	*

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

No gains (losses) were recognized in net 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 planned issuance of debt. The first FSIRS terminated in December ~~2010. The~~2010, and the second, ~~FSIRS terminated~~ in March 2012. Losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) 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):


March 31, 2016 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
June 30, 2016 Instrument										Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Prepaids and other current assets	$	116	$	—		$	116		Deferred charges and other assets	$	481	$	—		$	481
Swaps	Other current liabilities		120		(2,523	)		(2,403	)	Prepaids and other current assets		3,100		(13	)		3,087
Swaps	Other deferred credits		—		(88	)		(88	)	Other current liabilities		133		(380	)		(247	)

Total		$	236	$	(2,611	)	$	(2,375	)		$	3,714	$	(393	)	$	3,321


December 31, 2015 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total			Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(4,267	)	$	(4,267	)	Other current liabilities	$	—	$	(4,267	)	$	(4,267	)
Swaps	Other deferred credits		4		(1,223	)		(1,219	)	Other deferred credits		4		(1,223	)		(1,219	)

Total		$	4	$	(5,490	)	$	(5,486	)		$	4	$	(5,490	)	$	(5,486	)

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 (in the settlement month) of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets. The Company had no outstanding collateral associated with the Swaps during either period shown in the above table.

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

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


					Three Months Ended		Six Months Ended		Twelve Months Ended
(Thousands of dollars)	Three Months Ended March 31, 2016		Twelve Months Ended March 31, 2016		June 30, 2016		June 30, 2016		June 30, 2016
Paid to counterparties	$	4,324	$	7,891	$	159	$	4,483	$	7,360

No amounts were received from counterparties during ~~either period~~any of the periods indicated above.

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

March 31, 2016

Instrument

Balance Sheet Location

Net Total

June 30, 2016
Instrument

Balance Sheet Location

Net Total

Swaps

Other current liabilities

(116

)

Other deferred credits

(481

)

Swaps

Prepaids and other current assets

2,403

Other current liabilities

(3,087

)

Swaps

Deferred charges and other assets

Prepaids and other current assets

247

December 31, 2015
Instrument

Balance Sheet Location

Net Total

Swaps

Prepaids and other current assets

4,267

Swaps

Deferred charges and other assets

1,219

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at ~~March 31,~~June 30, 2016 and December 31, 2015 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 measurement.

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:


(Thousands of dollars)	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Assets at fair value:
Prepaids and other current assets - Swaps	$	116		$	—		$	3,087		$	—

Deferred charges and other assets - Swaps								481			—
Liabilities at fair value:
Other current liabilities - Swaps		(2,403	)		(4,267	)		(247	)		(4,267	)
Other deferred credits - Swaps		(88	)		(1,219	)		—			(1,219	)

Net Assets (Liabilities)	$	(2,375	)	$	(5,486	)	$	3,321		$	(5,486	)

No financial assets or liabilities associated with the Swaps, which were 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 2015. Refer to Note 10 – Pension and Other Post Retirement Benefits in the 2015 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 and six months ~~ending March 31,~~ended June 30, 2016, the Company sold no shares through the continuous equity offering program. Since the start of the program in March 2015, the Company has sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds to the Company of $35,167,584, net of $355,228 in agent commissions. As of ~~March 31,~~June 30, 2016, the Company had up to $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 ~~three~~six months ended ~~March 31,~~June 30, 2016, the Company issued approximately ~~93,000~~99,000 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 ~~March 31,~~June 30, 2016 and December 31, 2015 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, senior notes, 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 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, 2016					December 31, 2015
	March 31, 2016					December 31, 2015					Carrying			Market		Carrying			Market
	Carrying Amount			Market Value		Carrying Amount			Market Value		Amount			Value		Amount			Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	132,708	$	125,000		$	130,273	$	125,000		$	132,663	$	125,000		$	130,273
Notes, 6.1%, due 2041		125,000			143,638		125,000			141,581		125,000			164,395		125,000			141,581
Notes, 3.875%, due 2022		250,000			265,240		250,000			253,600		250,000			260,813		250,000			253,600
Notes, 4.875%, due 2043		250,000			255,485		250,000			251,483		250,000			285,000		250,000			251,483
8% Series, due 2026		75,000			97,286		75,000			97,035		75,000			103,201		75,000			97,035
Medium-term notes, 7.59% series, due 2017		25,000			26,016		25,000			26,253		25,000			25,649		25,000			26,253
Medium-term notes, 7.78% series, due 2022		25,000			30,439		25,000			29,855		25,000	��		30,577		25,000			29,855
Medium-term notes, 7.92% series, due 2027		25,000			32,188		25,000			31,890		25,000			34,262		25,000			31,890
Medium-term notes, 6.76% series, due 2027		7,500			8,762		7,500			8,684		7,500			9,416		7,500			8,684
Unamortized discount and debt issuance costs		(6,017	)				(6,137	)				(5,894	)				(6,137	)

		901,483					901,363					901,606					901,363

Revolving credit facility and commercial paper		—			—		150,000			150,000		2,500			2,500		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:
4.85% 2005 Series A, due 2035		100,000			101,410		100,000			100,452		100,000			99,610		100,000			100,452
4.75% 2006 Series A, due 2036		24,855			25,084		24,855			25,130		24,855			25,025		24,855			25,130
Unamortized discount and debt issuance costs		(3,765	)				(3,946	)				(3,584	)				(3,946	)

		321,090					320,909					321,271					320,909

Centuri term loan facility		117,556			117,658		112,571			112,665		115,769			115,932		112,571			112,665
Unamortized debt issuance costs		(601	)				(692	)				(604	)				(692	)

		116,955					111,879					115,165					111,879

Centuri secured revolving credit facility		38,885			38,912		60,627			60,724		76,645			76,798		60,627			60,724
Centuri other debt obligations		59,151			58,963		25,901			26,059		60,185			62,310		25,901			26,059

		1,437,564					1,570,679					1,477,372					1,570,679
Less: current maturities		(48,596	)				(19,475	)				(49,567	)				(19,475	)

Long-term debt, less current maturities	$	1,388,968				$	1,551,204				$	1,427,805				$	1,551,204

In March 2016, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2020 and was extended to March 2021. The Company ~~will continue to use~~uses $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 ~~March 31,~~June 30, 2016, 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 ~~March 31,~~June 30, 2016, ~~no borrowings were~~$2.5 million was outstanding on ~~either~~ the ~~short-term or~~ long-term ~~portions~~portion of the credit ~~facility.~~facility; there were no borrowings outstanding on the short-term portion.

In June 2016, notices were sent to holders of Southwest’s $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) that such IDRBs would be redeemed at par plus accrued interest in July 2016. Sufficient borrowing capacity existed on the long-term portion of Southwest’s credit facility, which was used to fund the redemption. Therefore, the IDRBs redeemed in July 2016 continue to be presented as long-term obligations as of June 30, 2016.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. At ~~March 31,~~June 30, 2016, ~~$156~~$192 million in borrowings were outstanding on the Centuri facility. Centuri assets securing the facility at ~~March 31,~~June 30, 2016 totaled ~~$450~~$479 million.

In January 2016, Centuri entered into a $40 million equipment loan due in February 2021 under an existing master loan and security agreement.

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 ~~three~~six months ended ~~March 31,~~June 30, 2016.


	Southwest Gas Corporation Equity																					Southwest Gas Corporation Equity
							Accumulated												Redeemable									Accumulated												Redeemable
					Additional		Other						Non-						Noncontrolling							Additional		Other						Non-						Noncontrolling
	Common Stock				Paid-in		Comprehensive			Retained			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)			Shares		Amount		Capital		Income (Loss)			Earnings			Interest			Total			(Temporary Equity)
DECEMBER 31, 2015		47,377	$	49,007	$	896,448	$	(50,268	)	$	699,221		$	(2,083	)	$	1,592,325		$	16,108			47,377	$	49,007	$	896,448	$	(50,268	)	$	699,221		$	(2,083	)	$	1,592,325		$	16,108
Common stock issuances		93		93		2,015											2,108						99		99		4,438											4,537
Net income (loss)											75,446			(16	)		75,430			(75	)											84,389			(92	)		84,297			157
Redemption value adjustments																																653						653			(653	)
Foreign currency exchange translation adj.								756									756			26									823									823			29
Other comprehensive income (loss):
Net actuarial gain (loss) arising during period, less amortization of unamortized benefit plan cost, net of tax								607									607												1,212									1,212
Amounts reclassified to net income, net of tax (FSIRS)								519									519												1,038									1,038
Centuri distribution to redeemable noncontrolling interest																				(99	)																				(99	)
Dividends declared
Common: $0.45 per share											(21,562	)					(21,562	)
Common: $0.90 per share																																(43,115	)					(43,115	)

MARCH 31, 2016		47,470	$	49,100	$	898,463	$	(48,386	)	$	753,105		$	(2,099	)	$	1,650,183		$	15,960
JUNE 30, 2016																							47,476	$	49,106	$	900,886	$	(47,195	)	$	741,148		$	(2,175	)	$	1,641,770		$	15,542

The following information provides insight into amounts impacting Other Comprehensive Income (Loss), on both ~~before~~before- and after-tax bases, 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, as well as the Redeemable Noncontrolling Interest. See Note 4 – Derivatives and Fair Value Measurements for additional information on the FSIRS.

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


																						Three Months Ended												Three Months Ended
																						June 30, 2016												June 30, 2015
	Three Months Ended March 31, 2016									Three Months Ended March 31, 2015												Before-				Tax				Net-of-				Before-				Tax				Net-of-
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount				Tax (Expense) or Benefit (1)				Net-of- Tax Amount				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		$	(127	)	$	207		$	333				$	(127	)			$	206			$	334			$	(127	)		$	207			$	334			$	(126	)		$	208
Amortization of net actuarial (gain)/loss		6,767			(2,571	)		4,196			8,596				(3,266	)			5,330				6,766				(2,572	)			4,194				8,595				(3,267	)			5,328
Regulatory adjustment		(6,123	)		2,327			(3,796	)		(7,787	)			2,959				(4,828	)			(6,123	)			2,327				(3,796	)			(7,787	)			2,959				(4,828	)

Pension plans other comprehensive income (loss)		978			(371	)		607			1,142				(434	)			708				977				(372	)			605				1,142				(434	)			708

FSIRS (designated hedging activities):
Amounts reclassifed into net income		836			(317	)		519			836				(317	)			519				837				(318	)			519				836				(318	)			518

FSIRS other comprehensive income		836			(317	)		519			836				(317	)			519				837				(318	)			519				836				(318	)			518

Foreign currency translation adjustments:
Translation adjustments		782			—			782			(1,272	)			—				(1,272	)			70				—				70				209				—				209

Foreign currency other comprehensive income (loss)		782			—			782			(1,272	)			—				(1,272	)			70				—				70				209				—				209

Total other comprehensive income (loss)	$	2,596		$	(688	)	$	1,908		$	706			$	(751	)		$	(45	)		$	1,884			$	(690	)		$	1,194			$	2,187			$	(752	)		$	1,435


																						Six Months Ended												Six Months Ended
																						June 30, 2016												June 30, 2015
																						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																						$	668			$	(254	)		$	414			$	667			$	(253	)		$	414
Amortization of net actuarial (gain)/loss																							13,533				(5,143	)			8,390				17,191				(6,533	)			10,658
Regulatory adjustment																							(12,246	)			4,654				(7,592	)			(15,574	)			5,918				(9,656	)

Pension plans other comprehensive income (loss)																							1,955				(743	)			1,212				2,284				(868	)			1,416
FSIRS (designated hedging activities):
Amounts reclassifed into net income																							1,673				(635	)			1,038				1,672				(635	)			1,037

FSIRS other comprehensive income																							1,673				(635	)			1,038				1,672				(635	)			1,037
Foreign currency translation adjustments:
Translation adjustments																							852				—				852				(1,063	)			—				(1,063	)

Foreign currency other comprehensive income (loss)																							852				—				852				(1,063	)			—				(1,063	)

Total other comprehensive income (loss)																						$	4,480			$	(1,378	)		$	3,102			$	2,893			$	(1,503	)		$	1,390


																			Twelve Months Ended									Twelve Months Ended
	Twelve Months Ended March 31, 2016									Twelve Months Ended March 31, 2015									June 30, 2016									June 30, 2015
	Before-			Tax			Net-of-			Before-			Tax			Net-of-			Before-			Tax			Net-of-			Before-			Tax			Net-of-
	Tax			(Expense)			Tax			Tax			(Expense)			Tax			Tax			(Expense)			Tax			Tax			(Expense)			Tax
	Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount			Amount			or Benefit (1)			Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)
Amortization of prior service cost		1,336			(507	)		829			599			(228	)		371			1,336			(508	)		828			845			(321	)		524
Amortization of net actuarial (gain)/loss		32,552			(12,370	)		20,182			26,338			(10,008	)		16,330			30,723			(11,675	)		19,048			29,019			(11,027	)		17,992
Prior service cost		—			—			—			(6,661	)		2,531			(4,130	)		—			—			—			(6,661	)		2,531			(4,130	)
Regulatory adjustment		(3,982	)		1,514			(2,468	)		137,699			(52,326	)		85,373			(2,318	)		882			(1,436	)		135,089			(51,334	)		83,755

Pension plans other comprehensive income (loss)		(613	)		234			(379	)		(15,671	)		5,954			(9,717	)		(778	)		296			(482	)		(15,354	)		5,834			(9,520	)

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

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

Foreign currency translation adjustments:
Translation adjustments		100			—			100			(1,931	)		—			(1,931	)		(39	)		—			(39	)		(1,722	)		—			(1,722	)

Foreign currency other comprehensive income (loss)		100			—			100			(1,931	)		—			(1,931	)		(39	)		—			(39	)		(1,722	)		—			(1,722	)

Total other comprehensive income (loss)	$	2,831		$	(1,037	)	$	1,794		$	(14,257	)	$	4,683		$	(9,574	)	$	2,528		$	(975	)	$	1,553		$	(13,732	)	$	4,563		$	(9,169	)

Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, reported in Accumulated other comprehensive income (“AOCI”) at ~~March 31,~~June 30, 2016, 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:


	Defined Benefit Plans									FSIRS									Foreign Currency Items											Defined Benefit Plans									FSIRS									Foreign Currency Items
	Before-Tax			Tax (Expense) Benefit (4)			After- Tax			Before- Tax			Tax (Expense) Benefit			After-Tax			Before- Tax			Tax (Expense) Benefit (4)		After-Tax			AOCI			Before-Tax			Tax (Expense) Benefit (4)			After-Tax			Before-Tax			Tax (Expense) Benefit (4)			After-Tax			Before-Tax			Tax (Expense) Benefit		After-Tax			AOCI
Beginning Balance AOCI December 31, 2015	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)

Translation adjustments		—			—			—			—			—			—			782			—		782			782			—			—			—			—			—			—			852			—		852			852

Other comprehensive income before reclassifications		—			—			—			—			—			—			782			—		782			782			—			—			—			—			—			—			852			—		852			852
FSIRS amounts reclassified from AOCI (1)		—			—			—			836			(317	)		519			—			—		—			519			—			—			—			1,673			(635	)		1,038			—			—		—			1,038
Amortization of prior service cost (2)		334			(127	)		207			—			—			—			—			—		—			207			668			(254	)		414			—			—			—			—			—		—			414
Amortization of net actuarial loss (2)		6,767			(2,571	)		4,196			—			—			—			—			—		—			4,196			13,533			(5,143	)		8,390			—			—			—			—			—		—			8,390
Regulatory adjustment (3)		(6,123	)		2,327			(3,796	)		—			—			—			—			—		—			(3,796	)		(12,246	)		4,654			(7,592	)		—			—			—			—			—		—			(7,592	)

Net current period other comprehensive income (loss)		978			(371	)		607			836			(317	)		519			782			—		782			1,908			1,955			(743	)		1,212			1,673			(635	)		1,038			852			—		852			3,102
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			26			—		26			26			—			—			—			—			—			—			29			—		29			29

Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		978			(371	)		607			836			(317	)		519			756			—��		756			1,882			1,955			(743	)		1,212			1,673			(635	)		1,038			823			—		823			3,073

Ending Balance AOCI March 31, 2016	$	(56,682	)	$	21,540		$	(35,142	)	$	(18,508	)	$	7,033		$	(11,475	)	$	(1,769	)	$	—	$	(1,769	)	$	(48,386	)
Ending Balance AOCI June 30, 2016																														$	(55,705	)	$	21,168		$	(34,537	)	$	(17,671	)	$	6,715		$	(10,956	)	$	(1,702	)	$	—	$	(1,702	)	$	(47,195	)

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


	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Net actuarial (loss) gain	$	(428,502	)	$	(435,269	)	$	(421,736	)	$	(435,269	)
Prior service cost		(6,704	)		(7,038	)		(6,370	)		(7,038	)
Less: amount recognized in regulatory assets		378,524			384,647			372,401			384,647

Recognized in AOCI	$	(56,682	)	$	(57,660	)	$	(55,705	)	$	(57,660	)

In conjunction with the acquisition of the Canadian construction businesses in October 2014, the previous owners of the acquired companies currently hold a 3.4% equity interest in Centuri. The previous owners are able to exit their investment retained by requiring the purchase of a portion of their interest commencing 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 beginning in July 2022. Due to the ability of the noncontrolling parties to redeem their interest for cash, their interest is presented on the Company’s Condensed Consolidated Balance Sheet at ~~March 31,~~June 30, 2016 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity). The following depicts changes to the balance of the redeemable noncontrolling interest between the indicated periods.


	Redeemable Noncontrolling Interest			Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2015	$	16,108		$	16,108
Net income (loss) attributable to redeemable noncontrolling interest		(75	)		157
Foreign currency exchange translation adjustment		26			29
Centuri distribution to redeemable noncontrolling interest		(99	)		(99	)
Adjustment to redemption value					(653	)

Balance, March 31, 2016	$	15,960
Balance, June 30, 2016				$	15,542

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 ~~March 31,~~June 30, 2016, Southwest had ~~1,964,000~~1,962,000 residential, commercial, industrial, and other natural gas customers, of which ~~1,049,000~~1,047,000 customers were located in Arizona, ~~723,000~~724,000 in Nevada, and ~~192,000~~191,000 in California. Residential and commercial customers represented over 99% of the total customer base. During the twelve months ended ~~March 31,~~June 30, 2016, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 3% from other sales customers, and 12% from transportation customers. These general composition 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. The demand for natural gas is seasonal, with greater demand in the colder winter months and decreased demand in the warmer summer months. 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 Group, Inc. (“Centuri” or the “construction services” segment) 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. In October 2014, the Company acquired three privately held construction businesses, primarily based in Canada. The financial information contained herein only includes the results of the acquired entities since October 2014. Centuri operates in 20 major markets in the United States (primarily ~~under the NPL name)~~as NPL) and in 2 major markets in Canada ~~(under the~~(as NPL Canada, formerly Link-Line Contractors Ltd., and W.S. ~~Nicholls names)~~Nicholls). In May 2016, Centuri completed the ~~Link-Line name was changed to NPL Canada Ltd.~~acquisition of two privately held, affiliated construction businesses by means of asset purchase. Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”) are based in Lisbon Falls, Maine, with a primary focus on underground utility installation using horizontal directional drilling technology. See theAcquisition of Construction Services Businessessection ofNote 1 – Nature of Operations and Basis of Presentation for more information. 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 2015 Annual Report to Shareholders, which is incorporated by reference into the 2015 Form ~~10-K.~~10-K, and the first quarter 2016 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 ~~82%~~83% 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 March 31,										Period Ended June 30,
	Three Months						Twelve Months				Three Months					Six Months					Twelve Months
	2016			2015			2016		2015		2016		2015			2016		2015			2016		2015
	(In thousands, except per share amounts)										(In thousands, except per share amounts)
Contribution to net income
Contribution to net income (loss)
Natural gas operations	$	77,583		$	78,921		$	110,287	$	123,194	$	2,358	$	(657	)	$	79,941	$	78,264		$	113,302	$	120,739
Construction services		(2,137	)		(6,938	)		31,493		19,132		6,585		5,606			4,448		(1,332	)		32,472		16,909

Net income	$	75,446		$	71,983		$	141,780	$	142,326	$	8,943	$	4,949		$	84,389	$	76,932		$	145,774	$	137,648

Average number of common shares outstanding		47,437			46,612			47,196		46,537		47,473		46,869			47,455		46,741			47,347		46,628

Basic earnings per share
Consolidated	$	1.59		$	1.54		$	3.00	$	3.06	$	0.19	$	0.11		$	1.78	$	1.65		$	3.08	$	2.95

Natural Gas Operations
Operating margin	$	311,500		$	299,353		$	902,977	$	880,968	$	184,232	$	177,628		$	495,732	$	476,981		$	909,581	$	885,102

~~Customer Growth.~~Southwest completed 24,000 first-time meter sets, but realized 26,000 net new customers over the last twelve months, an increase of 1.3%. 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 2016.


					Three Months Ended
	Three Months Ended March 31,				June 30,
	2016		2015		2016			2015
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	525,100	$	553,115	$	255,648		$	286,643
Net cost of gas sold		213,600		253,762		71,416			109,015

Operating margin		311,500		299,353		184,232			177,628
Operations and maintenance expense		100,797		95,510		98,744			99,344
Depreciation and amortization		60,745		53,675		57,232			52,912
Taxes other than income taxes		14,013		12,997		12,987			12,414

Operating income		135,945		137,171		15,269			12,958
Other income (deductions)		1,755		2,602		2,436			312
Net interest deductions		16,230		16,096		16,561			15,749

Income before income taxes		121,470		123,677
Income tax expense		43,887		44,756
Income (loss) before income taxes						1,144			(2,479	)
Income tax expense (benefit)						(1,214	)		(1,822	)

Contribution to consolidated net income	$	77,583	$	78,921
Contribution to consolidated net income (loss)					$	2,358		$	(657	)

The contribution to consolidated net income from natural gas operations ~~decreased $1.3~~increased $3 million between the ~~first~~second quarters of 2016 and 2015. The ~~decline~~improvement was primarily due to higher operating ~~expenses,~~margin and other income, partially offset by ~~an increase in~~higher operating ~~margin.~~expenses, predominantly related to increased depreciation and amortization.

Operating margin increased ~~$12~~approximately $7 million between quarters. ~~New customers contributed $3 million in operating margin during the first quarter of 2016.~~ Combined rate relief in the California jurisdiction and Paiute Pipeline Company (seeRates and Regulatory Proceedings) provided $3$2 million in operating margin. Operating margin attributable to the Nevada conservation and energy efficiency (“CEE”) surcharge, which was implemented in January 2016, was $4$2 million. Amounts collected through the surcharge do not impact net income as they also result in an increase in associated amortization expense (discussed below and inRates and Regulatory Proceedings). New customers contributed $2 million in operating margin during the second quarter of 2016, as approximately 24,000 net new customers were added during the last twelve months. Operating margin associated with infrastructure replacement mechanisms and customers outside the decoupling mechanisms, ~~and~~as well as other miscellaneous revenues, collectively increased $2$1 million.

Operations and maintenance expense ~~increased $5.3 million,~~decreased $600,000, or 6%1%, between quarters ~~due primarily to~~as lower pension costs and a reduction in legal claims and expenses offset general cost ~~increases and the timing and scope of pipeline facility maintenance services. In addition, expenses for pipeline integrity management and damage prevention programs increased $1.6 million.~~increases.

Depreciation and amortization expense increased ~~$7.1~~$4.3 million, or ~~13%~~8%, between quarters. Of the increase, approximately $4.3 million is attributable to amortization related to the recovery of regulatory assets (primarily due to amortization accompanying the recovery of Nevada conservation and energy efficiency programs noted above, and associated with Arizona integrity management and California energy efficiency programs). Additionally, averageAverage gas plant in service for the current quarter increased ~~$308~~$338 million, or 6%, compared to the corresponding quarter a year ago. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business, which collectively resulted in increased depreciation expense. In addition, approximately $1.1 million of the increase is attributable to the collective impacts of amortization related to the recovery of regulatory assets.

Taxes other than income taxes increased ~~$1 million,~~$573,000, or 8%5%, between quarters primarily due to higher property taxes associated with net plant additions.

Other income, which principally includes returns on company-owned life insurance (“COLI”) policies and non-utility expenses, ~~decreased $847,000~~increased $2.1 million between quarters. The current quarter reflects ~~$900,000~~$2.2 million of COLI-related income associated with COLI policy cash surrender value increases and recognized net death benefits, while the prior-year quarter reflected ~~$1.3 million of~~no COLI-related income. ~~Interest income decreased $223,000~~

Net interest deductions increased $812,000 between quarters, primarily due to ~~changes~~higher interest expense associated with PGA balances, partially offset by reductions associated with the redemption of debt ($31.2 million 5% 2004 Series B IDRBs in ~~over-~~May 2015 and ~~under-collected PGA balances.~~$20 million 5.25% 2003 Series D IDRBs in September 2015).

The contribution to consolidated net income from natural gas operations increased $1.7 million between the first six months of 2016 and 2015. The improvement was primarily due to higher operating margin and other income, partially offset by an increase in operating expenses, notably depreciation and amortization.

Operating margin increased $19 million between the six-month periods. Operating margin attributable to the Nevada CEE surcharge, which was implemented in January 2016, provided $6 million of the increase. Amounts collected through the surcharge do not impact net income as they also result in an increase in associated amortization expense. New customers contributed $5 million in operating margin during the first six months of 2016. Combined rate relief in the California jurisdiction and Paiute Pipeline Company provided $5 million in operating margin. Operating margin associated with infrastructure replacement mechanisms and customers outside the decoupling mechanisms, as well as other miscellaneous revenues, collectively increased $3 million.

Operations and maintenance expense increased $4.7 million, or 2%, between periods primarily due to increased expenses for pipeline integrity management and damage prevention programs (collectively, $2.3 million) and general cost increases, partially offset by a decline in pension expense.

Depreciation and amortization expense increased $11.4 million, or 11%, between periods. Average gas plant in service for the current period increased $320 million, or 6%, compared to the corresponding period a year ago. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business, which collectively resulted in increased depreciation expense. In addition, approximately $5.4 million of the increase is attributable to amortization related to the recovery of regulatory assets, notably the amortization accompanying the recovery of Nevada CEE costs indicated above.

Taxes other than income taxes increased $1.6 million, or 6%, between periods primarily due to higher property taxes associated with net plant additions.

Other income increased $1.3 million between periods. The current period reflects $3.1 million of COLI-related income associated with cash surrender value increases and recognized net death benefits, while the prior-year period reflected $1.3 million of COLI-related income. Interest income decreased $372,000 between periods primarily due to changes in over- and under-collected PGA balances.

Net interest deductions increased $946,000 between periods primarily due to higher interest expense associated with PGA balances, offset by reductions associated with the redemption of debt ($31.2 million 5% 2004 Series B IDRBs in May 2015 and $20 million 5.25% 2003 Series D IDRBs in September 2015).


					Twelve Months Ended
	Twelve Months Ended March 31,				June 30,
	2016		2015		2016		2015
	(Thousands of dollars)				(Thousands of dollars)
Gas operating revenues	$	1,426,624	$	1,448,709	$	1,395,629	$	1,463,873
Net cost of gas sold		523,647		567,741		486,048		578,771

Operating margin		902,977		880,968		909,581		885,102
Operations and maintenance expense		398,486		376,834		397,886		378,558
Depreciation and amortization		220,525		206,336		224,845		208,724
Taxes other than income taxes		50,409		48,793		50,982		50,242

Operating income		233,557		249,005		235,868		247,578
Other income (deductions)		1,445		8,155		3,569		5,619
Net interest deductions		64,229		67,168		65,041		65,858

Income before income taxes		170,773		189,992		174,396		187,339
Income tax expense		60,486		66,798		61,094		66,600

Contribution to consolidated net income	$	110,287	$	123,194	$	113,302	$	120,739

Contribution to consolidated net income from natural gas operations decreased ~~by $12.9~~$7.4 million between the twelve-month periods of 2016 and 2015. The decrease was primarily due to an increase in operating expenses and a ~~decrease~~decline in other income, partially offset by improved operating ~~margin and lower net interest deductions.~~margin.

Operating margin increased ~~$22~~$24 million between periods including $8 million attributable to customer growth and a combined $6$7 million of rate relief in the California jurisdiction and Paiute Pipeline Company. Operating margin attributable to the Nevada ~~conservation and energy efficiency~~CEE surcharge implemented in January 2016 was $4$6 million (a corresponding increase is reflected in amortization expense). Operating margin associated with infrastructure replacement mechanisms and customers outside the decoupling mechanisms, ~~and~~as well as other miscellaneous revenues, collectively improved $4$3 million.

Operations and maintenance expense increased ~~$21.7~~$19.3 million, or 6%5%, between periods primarily due to general cost increases and higher employee-related ~~expenses including~~medical and pension ~~costs (approximately $5 million of which resulted in increased expense), and higher legal claims and expenses.~~costs. In addition, expenses for pipeline integrity management and damage prevention programs collectively increased ~~(collectively, $4.7 million).~~$4.4 million.

Depreciation and amortization expense increased ~~$14.2~~$16.1 million, or 7%8%, between periods. Of the increase, approximately $6 million is attributable to amortization related to the recovery of regulatory assets (primarily due to amortization accompanying the recovery of Nevada conservation and energy efficiency programs noted above, and associated with Arizona integrity management and California energy efficiency programs). Additionally, averageAverage gas plant in service for the current period increased ~~$281~~$295 million, or 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, which collectively resulted in increased depreciation expense. In addition, approximately $6.4 million of the increase is attributable to amortization related to the recovery of regulatory assets, notably, amortization accompanying the recovery of Nevada CEE costs indicated above.

Taxes other than income taxes increased ~~$1.6 million~~$740,000 between periods primarily due to higher property taxes ~~principally related to~~associated with net plant additions.

Other income decreased ~~$6.7~~$2.1 million between the twelve-month periods of 2016 and 2015. The current period reflects a ~~$900,000 decrease~~$1.3 million increase in income associated with COLI policy cash surrender values and recognized net ~~of recognized~~ death benefits, while the prior-year period included ~~$5.7~~$3.4 million of COLI-related income.

Net interest deductions decreased ~~$2.9 million~~$817,000 between periods. The decrease primarily resulted from the redemptions of $65 million 5.25% 2004 Series A IDRBs in November 2014, $31.2 million 5.00% 2004 Series B IDRBs in May 2015, and $20 million 5.25% 2003 Series D IDRBs in September ~~2015.~~2015, partially offset by higher interest expense associated with PGA balances.


												Three Months Ended					Six Months Ended					Twelve Months Ended
	Three Months Ended March 31,						Twelve Months Ended March 31,					June 30,					June 30,					June 30,
	2016			2015			2016		2015			2016		2015			2016		2015			2016		2015
(Thousands of dollars)

Construction revenues	$	206,148		$	181,105		$	1,034,029	$	798,822		$	292,100	$	251,961		$	498,248	$	433,066		$	1,074,168	$	869,109
Operating expenses:
Construction expenses		193,382			174,928			917,235		709,586			263,926		225,829			457,308		400,757			955,332		777,773
Depreciation and amortization		14,615			13,792			57,479		51,267			15,327		14,043			29,942		27,835			58,763		53,648

Operating income (loss)		(1,849	)		(7,615	)		59,315		37,969
Operating income													12,847		12,089			10,998		4,474			60,073		37,688
Other income (deductions)		(34	)		(330	)		883		(388	)		34		(150	)		—		(480	)		1,067		(553	)
Net interest deductions		1,491			1,881			7,394		5,359			1,660		1,968			3,151		3,849			7,086		7,081

Income (loss) before income taxes		(3,374	)		(9,826	)		52,804		32,222
Income tax expense (benefit)		(1,146	)		(2,784	)		20,185		13,086
Income before income taxes													11,221		9,971			7,847		145			54,054		30,054
Income tax expense													4,480		4,251			3,334		1,467			20,414		13,027

Net income (loss)		(2,228	)		(7,042	)		32,619		19,136			6,741		5,720			4,513		(1,322	)		33,640		17,027
Net income (loss) attributable to noncontrolling interests		(91	)		(104	)		1,126		4
Net income attributable to noncontrolling interests													156		114			65		10			1,168		118

Contribution to consolidated net income (loss) attributable to Centuri	$	(2,137	)	$	(6,938	)	$	31,493	$	19,132		$	6,585	$	5,606		$	4,448	$	(1,332	)	$	32,472	$	16,909

In October 2014, construction services operations were expanded by the acquisition of the ~~Link-Line~~Canadian group of companies. In May 2016, Centuri acquired ETTI. Line items in the tables above reflect the results of the acquired companies only since the acquisition ~~date.~~dates.

Quarterly Analysis.Net income contribution for the current quarter improved ~~$4.8 million~~$979,000 compared to the ~~first~~second quarter of 2015. Additional pipe replacement work and lower interest expense positively impacted net income, partially offset by increases in depreciation and amortization. ~~The prior-year quarter included a $5.6 million pretax loss reserve on an industrial project in Canada.~~

Revenues increased ~~$25~~$40.1 million, or ~~14%~~16%, in the ~~first~~second quarter of 2016 when compared to the prior-year quarter, primarily due to additional pipe replacement work. In addition, incremental work ~~that~~ was ~~able to be~~ completed as a result of favorable weather conditions in several operating areas. The majority of the revenue increase was from the existing base of utility customers and their expanded pipe replacement programs. The newly acquired ETTI provided $1.1 million in revenue.

Construction expenses increased ~~$18.5~~$38.1 million, or ~~11%~~17%, between quarters, due to the ~~incremental work and~~ additional pipe replacement work and incremental work noted above. ~~However, the increase overall was mitigated by construction expenses of the prior-year quarter that were impacted by the $5.6 million loss reserve on the Canadian project.~~ Gains on sale of equipment (reflected as an offset to construction expenses) were approximately ~~$1.3~~$1.4 million and ~~$1.5~~$1 million for the ~~first~~second quarters of 2016 and 2015, respectively. Depreciation and amortization expense increased ~~$823,000~~$1.3 million between quarters due to depreciation on additional equipment purchased to support the growing volume of work being performed ($1.9 million), partially offset by a decline in the amortization of certain finite-lived intangible assets recognized from the October 2014 ~~acquisition.~~acquisition ($600,000).

Net interest deductions decreased ~~$390,000~~$308,000 between quarters. The decrease was due primarily to a decline in outstanding borrowings for the comparative periods associated with the $300 million secured revolving credit and term loan facility.

Six-Month Analysis.Net income contribution for the first six months of 2016 improved $5.8 million compared to the same period of 2015. Additional pipe replacement work and lower interest expense positively impacted net income, partially offset by increases in depreciation and amortization. The prior-year period included a $7.6 million pretax loss reserve on an industrial project in Canada.

Revenues increased $65.2 million, or 15%, in the first six months of 2016 when compared to the prior-year period, primarily due to additional pipe replacement work and incremental work that was able to be completed as a result of favorable weather conditions in several operating areas during the first six months of 2016.

Construction expenses increased $56.6 million, or 14%, between periods, due to the additional pipe replacement work and incremental work noted above. Gains on sale of equipment (reflected as an offset to construction expenses) were approximately $2.7 million and $2.6 million for the first six months of 2016 and 2015, respectively. Depreciation and amortization expense increased $2.1 million between periods due to depreciation on additional equipment purchased to support the growing volume of work being performed ($3.3 million), partially offset by a decline in the amortization of certain finite-lived intangible assets recognized from the October 2014 acquisition ($1.2 million).

Net interest deductions decreased $698,000 between periods. The decrease was due primarily to a decline in outstanding borrowings between comparative periods associated with the $300 million secured revolving credit and term loan facility.

Twelve-Month Analysis. Contribution to consolidated net income from construction services for the twelve-month period ended ~~March 31,~~June 30, 2016 increased ~~$12.4~~$15.6 million compared to the same period of 2015. The improvement ~~was primarily due to~~includes increased pipe replacement work, partially offset by increases in depreciation and ~~amortization and higher interest expense.~~amortization. The prior-year period reflects the $7.6 million pretax loss reserve on an industrial project in Canada, while the current period includes an approximate $4 million pretax favorable settlement related to the project.

Revenues increased ~~$235.2~~$205.1 million, or ~~29%~~24%, in the current twelve-month period compared to the same period of 2015 primarily due to additional pipe replacement work in the current period and to higher revenues from the acquired companies ~~($72.5 million).~~in Canada. Favorable weather conditions in several operating areas during the first ~~quarter~~half of 2016 and the fourth quarter of 2015 provided an extended construction season. 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 both the twelve months ended ~~March 31,~~June 30, 2016 and 2015, revenues from replacement work provided over 60% of total revenues.

Construction expenses increased ~~$207.6~~$177.6 million, or ~~29%~~23% between periods, due to additional pipe replacement work during the twelve months ended ~~March 31,~~June 30, 2016 and higher construction costs associated with the acquired Canadian companies. ~~General and administrative expense (included in construction expenses) increased $11.7 million.~~ Gains on sale of equipment (reflected as an offset to construction expenses) were ~~$2.9~~$3.3 million and ~~$5.3~~$4.6 million for the twelve-month periods of 2016 and 2015, respectively. Depreciation and amortization expense increased ~~$6.2~~$5.1 million between the current and prior-year periods due to ~~the amortization on finite-lived intangible assets recognized from the acquisition, incremental depreciation from the acquired companies, and~~ increased depreciation for additional equipment purchased to support growth in the volume of work being ~~performed.~~

~~Net interest deductions increased $2 million between periods. The increase was primarily due to outstanding borrowings~~performed and incremental depreciation from the acquired Canadian companies, partially offset by lower amortization ~~of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with~~on finite-lived intangible assets recognized from the acquisition.

Arizona General Rate Case.Southwest filed a general rate application with the Arizona Corporation Commission (“ACC”) in May 2016 requesting an increase in authorized annual operating revenues of approximately $32 million, or 4.2%, to reflect current levels of expense and requested returns, in addition to reflecting capital investments made by Southwest since June 2010. The application requests an overall rate of return of 7.82% on an original cost rate base of $1.336 billion, a 10.25% return on common equity, and a capital structure utilizing 52% common equity. The filing includes a depreciation study ~~which~~that supports a proposal to reduce currently effective depreciation expense by approximately $42 million, which is considered in the overall requested amount. This expense reduction coupled with the requested revenue increase, results in a net annual operating income increase request of $74 million. The Company is also seeking to continue the current Customer-Owned Yard Line (“COYL”) program approved in its last general rate case and to expand this mechanism to include other non-revenue producing projects such as the replacement of vintage steel pipe, while utilizing the same cost recovery methodology. Southwest is also requesting a property tax tracker and to maintain the current decoupled rate design. A procedural order has been issued; with hearings, if necessary, scheduled for February 2017. New rates are expected to be in place by May 2017.

COYL Program. The Company received approval, in connection with its previous Arizona general rate case, to implement a program to conduct leak surveys, and if leaks were present, to replace and relocate service lines and meters for approximately 100,000 Arizona customers whose meters were set off from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously responsible for the cost of maintaining these lines and were subject to the immediate cessation of natural gas service if low-pressure leaks

occurred. Effective June 2013, the ACC authorized a surcharge to recover the costs of depreciation and pre-tax return on the costs incurred to replace and relocate service lines and meters. The surcharge is revised annually as the program progresses. In 2014, the Company received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. In the most recent annual COYL filing made in February 2016, the Company requested to increase the annual surcharge revenue from $2.5 million to $3.7 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total capital expenditures of $23.1 million, $13.4 million of which was incurred during 2014 and 2015. In May 2016, the ACC issued a decision approving the surcharge application, effective in June 2016.

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, to be 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). In December 2014, Southwest received an order from the ACC granting pre-approval of Southwest’s application to construct the LNG facility and the deferral of costs, limited to $50 million. Absent further consideration in the current general rate case, the authorization to defer costs expires on November 1, 2017 (from which point, expenditures incurred would not otherwise be eligible for deferral) and also

requires any unquantified cost savings to be deferred. 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. The Company purchased the site for the facility in October 2015 and is ~~preparing~~in the ~~construction requirements bid package~~Request for Proposal (“RFP”) process, with the proposals due from potential ~~contractors.~~contractors in September 2016. The contract to construct the facility is currently expected to be in place in the second half of 2016 and construction is expected to take approximately two to three years to complete. The Company included a proposal for the ratemaking treatment of facility costs as part of its current Arizona rate case filing.

California Attrition Filing. In November 2015, Southwest made its annual post-test year (“PTY”) attrition filing with the California Public Utilities Commission (“CPUC”), requesting annual revenue increases of $1.8 million in southern California, $499,000 in northern California, and $249,000 for South Lake Tahoe. This filing was approved in December 2015 and rates were made effective in January 2016. The CPUC also approved an adjustment to recover costs associated with replacing 7.1 miles of transmission pipeline and installing a remote control shut-off valve. This adjustment is expected to result in an annualized margin increase of $1.7 million during 2016.

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. In June 2015, Southwest filed its Gas Infrastructure Replacement (“GIR”) Advance Application with the PUCN proposing $43.5 million of accelerated pipe replacements for 2016 (subject to the GIR mechanism). Once completed, the annualized revenue requirement associated with the accelerated replacement is estimated at $4.2 million.This mechanism has been in place since that time. In October 2015, the PUCN approved ~~the~~a GIR Advance Application, granting Southwest the authority to replace ~~the~~ $43.5 million of infrastructure under the GIR ~~mechanism. Also in October 2015,~~mechanism and management filed a separate rate application to reset the GIR surcharge, based upon project costs deferred through August 2015. In December 2015, the PUCN approved new rates, effective in January 2016, which are expected to result in approximately $4 million in annualized revenues. For 2016, the annualized revenue requirement associated with the accelerated pipe replacement approved in 2015 to be completed during 2016 is estimated at $4.2 million. In June 2016, Southwest filed a GIR Advance Application with the PUCN for projects expected to be completed during 2017. This filing proposed approximately $60 million of accelerated pipe replacement to include early vintage plastic, early vintage steel, and a COYL program with an annualized revenue requirement estimated at approximately $5 million. The COYL program, while not large in magnitude, represents the first of its kind in Nevada, modeled after the program in place in Southwest’s Arizona jurisdiction for several years. Management currently expects a decision, associated with these endeavors, during the fourth quarter of 2016.

Conservation and Energy Efficiency. In June 2015, Southwest requested recovery of energy efficiency and conservation development and implementation costs, including promotions and incentives for various programs, as originally approved for deferral by the PUCN effective November 2009. While recovery of these costs was approved as part of the most recent general rate case made effective May 2012, amounts incurred subsequent to the effective date continued to be deferred. Approved rates became effective January 2016 and are currently expected to result in

annualized margin increases of $2 million in northern Nevada and $8.7 million in southern Nevada, and also include amounts representing expected program expenditures for 2016. There is, however, no anticipated impact to net income overall from these recoveries as the amounts collected through customer rates ~~will~~are also be reflected as higher amortization expense.

General Rate Case.Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary of Southwest, filed a general rate case with the FERC in February 2014. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case. In February 2015, the FERC issued a letter order approving the settlement as filed. Tariff ~~charges~~changes 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. The settlement implies an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed to file a rate case no earlier than May 2016 and no later than May 2019.

Elko County Expansion Project.Paiute previously requested to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area, in order to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. 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 the project was placed in service in January 2016 as authorized by the FERC. Rates to begin recovering the cost of the project were implemented in January 2016 and are expected to result in $6 million in revenue annually. The total cost of this project iswas estimated at approximately $35 million, and total costs, including ~~remaining~~ costs associated with site restoration along the construction ~~corridor.~~

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 ~~March 31,~~June 30, 2016, over-collections in all jurisdictions resulted in a liability of ~~$101~~$126.3 million on the Company’s condensed consolidated balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during the first ~~three~~six months of 2016, resulting in additional overrecoveries since December 31, 2015. Tariff rates have been adjusted in all jurisdictions during this period. 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~~(thousands of dollars):


	March 31, 2016			December 31, 2015			March 31, 2015			June 30, 2016			December 31, 2015			June 30, 2015
Arizona	$	(24.7	)	$	(3.5	)	$	25.1		$	(33,941	)	$	(3,537	)	$	3,487
Northern Nevada		(12.6	)		(2.3	)		0.2			(14,380	)		(2,311	)		(5,521	)
Southern Nevada		(63.4	)		(39.8	)		(0.4	)		(75,440	)		(39,753	)		(21,695	)
California		(0.3	)		3.6			3.2			(2,538	)		3,591			264

	$	(101.0	)	$	(42.0	)	$	28.1		$	(126,299	)	$	(42,010	)	$	(23,465	)

In 2015, the Board of Directors (“Board”) of the Company authorized management to evaluate and pursue a holding company reorganization to provide further separation between regulated and unregulated businesses, and to provide additional financing flexibility. Following the holding company reorganization, Centuri and Southwest Gas would each be subsidiaries of the new publicly traded parent holding company but Centuri would no longer be a subsidiary of Southwest Gas. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization will remain at the Southwest Gas utility entity. Regulatory applications for preapproval of the reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May of 2016, respectively. The reorganization is also subject to consents from various third parties and final Board approval. Subject to such conditions, the reorganization could become effective inas early as the ~~second half~~fourth quarter of 2016. In this event, each outstanding share of Southwest Gas common stock would automatically convert into a share of stock in the holding company, on a one-for-one basis.

Cash on hand and cash flows from operations in the past twelve months have generally 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. Certain pipe replacement work was accelerated during these years to take advantage of bonus depreciation tax incentives and to fortify system integrity and ~~reliability.~~reliability, largely supported by favorable regulatory mechanisms. In addition, in March 2015, the Company filed an automatic shelf registration statement for the offer and sale of up to $100 million of its common stock for general corporate purposes and for the noted investment activities, refer toNote 5 – Common Stock and the discussion below. 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 ~~$90.4~~$81 million in the first ~~three~~six months of 2016 as compared to the same period of 2015. The improvement in operating cash flows ~~was primarily attributable to~~included temporary increases ~~attributable to~~in working capital components ~~overall.~~overall and an increase in net income. For instance, the timing of both billing and collecting accounts receivable balances favorably impacted the current ~~quarter, but had the opposite impact in~~period and, to a much smaller degree, the prior-year ~~quarter.~~period. Additionally, new and updated surcharges for decoupling mechanisms, conservation and energy efficiency and gas infrastructure programs improved cash flows during the first ~~quarter~~six months of 2016. Refer toResults of Natural Gas Operations andRates and Regulatory Proceedings.

Investing Cash Flows.Cash used in consolidated investing activities increased ~~$16.4~~$78.1 million in the first ~~three~~six months of 2016 as compared to the same period of 2015. 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 addition, the current period included outflows of $17 million to facilitate the acquisition of ETTI in the construction services segment (see theAcquired Construction Services Businesses section ofNote 1 – Nature of Operations and Basis of Presentation for more information). In association with the earlier acquisition of construction services businesses in Canada, a $9 million working capital adjustment related to a contractual true-up period was paid in the first quarter of 2015.

Financing Cash Flows.Net cash used in consolidated financing activities increased ~~$48.3~~$36.7 million in the first ~~three~~six months of 2016 as compared to the same period of 2015. The long-term debt issuance amounts and retirements of long-term debt during this period are attributable to Centuri’s borrowing and repayment activity. Southwest also issued stock under its Equity Shelf Program in the ~~prior-year quarter.~~first six months of 2015. SeeNote 5 – Common Stock, and discussion below. Dividends paid increased in the first ~~quarter~~six months of 2016 as compared to the ~~first quarter~~same period of 2015 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding. ~~The majority of Centuri’s borrowings during the twelve months ended March 31, 2015 were associated with the acquisition of construction services businesses noted previously.~~

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 ~~March 31,~~June 30, 2016, construction expenditures for the natural gas operations segment were ~~$444~~$475 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 ~~$533~~$540 million during this time, which provided ~~sufficient~~the majority of the 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, 2018 will be between $1.4 billion and $1.6 billion. Of this amount, approximately $460 million is expected to be incurred in the full year 2016. Southwest plans to continue, as appropriate, to request regulatory support to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). This includes the recent request in Nevada to complete $60 million in accelerated replacement projects in 2017 and a future request in California to initiate new programs, ~~and~~as well as a request included in the current Arizona general rate case to expand existing or initiate new programs. If successful, significant replacement activities are expected to continue well beyond the next few years. See alsoRates and Regulatory Proceedings for discussion of Nevada infrastructure, Arizona COYL, and an LNG facility. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 65% to 75% of the funding necessary for the gas ~~operations~~operations’ total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

During the ~~three~~six months ended ~~March 31,~~June 30, 2016, the Company issued approximately ~~93,000~~99,000 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 ~~$549,000~~$671,000 from the issuance of shares of common stock through the Stock Incentive Plan.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (“PATH Act”) was enacted, extending the 50% bonus depreciation tax deduction for qualified property acquired or constructed and placed in-service during 2015 (and additional years as noted below) as well as other tax deductions, credits, and incentives. The bonus depreciation tax deduction will be phased out over five years. The PATH Act provides for a 50% bonus depreciation tax deduction in 2015 through 2017, 40% in 2018, 30% in 2019, and no bonus deduction after 2019. ~~Based on forecasted qualifying construction expenditures,~~ Southwest estimates the bonus depreciation provision of the PATH Act will defer the payment of ~~approximately~~more than $55 million of federal income taxes for 2016.

The actual amount will be dependent upon the ultimate level of qualifying expenditures.

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 2016, the Board increased the quarterly dividend from 40.5 cents to 45 cents per share, effective with the June 2016 payment. The Board’s policy is to target a dividend payout ratio that allows the Company to maintain its strong credit ratings and effectively fund its rate base growth and is consistent with the local distribution company peer group average. The timing and amount of any increases will be based on the Board’s continual 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~~recovery/refunding 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 ~~March 31,~~June 30, 2016, the combined balance in the PGA accounts totaled an over-collection of ~~$101~~$126.3 million. SeePGA Filingsfor more information.

In March 2016, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020 and was extended to March 2021. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. The maximum amount outstanding on the credit facility (including a commercial paper program) during the first ~~quarter~~six months of 2016 was $68 million. At ~~March 31,~~June 30, 2016, ~~no borrowings were~~$2.5 million was outstanding on ~~either~~ the ~~short-term or~~ long-term ~~portions~~portion of the credit ~~facility.~~facility; 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 ~~March 31,~~June 30, 2016, no borrowings were outstanding under this program.

In June 2016, notices were sent to holders of Southwest’s $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) that such IDRBs would be redeemed at par plus accrued interest in July 2016. Sufficient capacity existed on the long-term portion of Southwest’s credit facility, which was used to fund the redemption. Therefore, the IDRBs redeemed in July 2016 continue to be presented as long-term obligations as of June 30, 2016.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. The term loan facility portion had an initial limit of approximately $150 million, which was reached in 2014 and is in the process of being repaid. No further borrowing is permitted under this portion of the facility. The secured revolving credit facility portion also has a limit of $150 million; amounts borrowed and repaid under this portion of the facility are available to be re-borrowed. The maximum amount outstanding on the credit facility during the first ~~quarter~~six months of 2016 was ~~$173~~$192 million, ~~including $113~~at which point $116 million was outstanding on the term loan facility. At ~~March 31,~~June 30, 2016, ~~$38.9~~$76.6 million was outstanding on the Centuri secured revolving credit facility. At ~~March 31,~~June 30, 2016, there was approximately ~~$99~~$60 million, net of letters of credit, available under the line of credit.

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

Earnings are defined as the sum of pretax income plus fixed charges. Fixed charges consist of all interest expense including capitalized interest, one-third of rent expense (which approximates the interest component of such expense), and net amortized debt costs.

This quarterly report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this quarterly report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote,” “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest savings, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, bonus depreciation tax deductions, amount and timing for completion of estimated future construction expenditures, including the LNG facility in southern Arizona, ~~and the cost of the Paiute expansion in Elko County, Nevada,~~ forecasted operating cash flows and results of operations, net earnings impacts from gas infrastructure replacement surcharges, funding sources of cash requirements, amounts generally expected to be reflected in 2016 or future period revenues from regulatory rate proceedings including the Arizona general rate case, rates and surcharges, PGA, and other rate adjustments, sufficiency of working capital and current credit facilities, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity and the intent and ability to issue the remaining capacity under the Equity Shelf Program, future dividend increases, pension and post-retirement benefits, certain benefits of tax acts, the effect of any rate changes or regulatory proceedings, infrastructure replacement mechanisms and the COYL program or ability to receive approval for an expansion of the program, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, the impact of certain legal proceedings, the success in securing remaining approvals of the proposed holding company structure or timing of the related reorganization, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, variability in volume of gas or transportation service sold to customers, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, results of Centuri bid work, impacts of structural and management changes at Centuri, Centuri construction expenses, differences between actual and originally expected outcomes of Centuri bid or other fixed-price construction agreements, and ability to successfully procure new work, acquisitions and management’s plans related thereto, competition, our ability to raise capital in external financings, our ability to continue to remain within the ratios and other limits subject to our debt covenants, and ongoing evaluations in regard to goodwill and other intangible assets. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating expenses will continue in future periods. For additional information on the risks associated with the Company’s business, seeItem1A. Risk Factors andItem 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report onForm 10-K for the year ended December 31, 2015.

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

SeeItem 7A. Quantitative and Qualitative Disclosures about Market Risk in the Company’s 2015 Annual Report on Form 10-K filed with the SEC. No material changes have occurred related to the Company’s disclosures about market risk.

The Company has established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and benefits of controls must be considered relative to their costs. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected.

Based on the most recent evaluation, as of ~~March 31,~~June 30, 2016, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.

In January 2016, the Company implemented a financial systems modernization project which resulted in a material change in internal controls over financial reporting. This project involved replacing or changing several financial systems previously used by the natural gas operations segment, including the replacement of the general ledger system, updating the payroll/human resources module, and adding substantial functionality in the area of supply chain processes. The new/updated systems were used in administering to and preparing first quarter 2016 financial information. Management monitored developments related to the financial systems modernization project, including working with the project team and management of affected departments to ensure control impacts were identified and documented, in order to assist in evaluating impacts to internal control. Pre-implementation testing and post-implementation reviews were conducted by management to ensure that internal controls surrounding the implementation process, application controls, and closing process were properly designed to prevent material financial statement errors. Such procedures included the review of required documents, user acceptance testing, change management procedures, assessment of access controls, data migration processes and month-end reconciliations.

There have been no ~~other~~ changes in the Company’s internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the ~~first~~second quarter of 2016 that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.

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

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

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


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

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


	Acquisition Date
Property, plant and equipment	$	4.3
Intangible assets		2.9
Goodwill		10.7

Total assets acquired	$	17.9


	March 31, 2016		December 31, 2015
Centuri accounts receivable for services provided to Southwest	$	11,089	$	10,006


	June 30, 2016		December 31, 2015
Centuri accounts receivable for services provided to Southwest	$	12,819	$	10,006


SOUTHWEST GAS CORPORATION		Form 10-Q
~~March 31,~~June 30, 2016


~~SOUTHWEST GAS CORPORATION~~		~~Form 10-Q~~
~~March 31, 2016~~


	March 31, 2016		December 31, 2015
Contract notional amounts		8,076		7,407


	For the Twelve Months Ended
	March 31, 2016		December 31, 2015
Ratio of earnings to fixed charges		3.46		3.43



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

Exhibit 10.01	-	~~Southwest Gas Corporation – Amendment No. 3 to Revolving Credit Agreement.~~Restricted Stock/Unit Plan, as amended and restated. Incorporated herein by reference to ~~Exhibit 10.1~~Appendix A to ~~Form 8-K~~the Proxy Statement dated March ~~28,~~31, 2016, File No. 1-07850.

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 ~~March 31,~~June 30, 2016, 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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company