Edgar Filing: SOUTHWEST GAS CORP

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Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION

(Exact name of registrant as specified in its charter)


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

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

Registrant’s telephone number, including area code: (702) 876-7237

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Common Stock, $1 Par Value, 46,512,597 shares as of July 29, 2014.


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

PART I—FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

(Unaudited)


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

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

Other property and investments		267,763			260,871

Restricted cash		16,649			—

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

Total current assets		410,491			494,672

Deferred charges and other assets		322,111			323,523

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

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

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

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

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

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

Total current liabilities		382,612			434,164

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

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

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

The accompanying notes are an integral part of these statements.


		2


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

(Unaudited)


	THREE MONTHS ENDED JUNE 30,						SIX MONTHS ENDED JUNE 30,						TWELVE MONTHS ENDED JUNE 30,
	2014			2013			2014			2013			2014			2013
Operating revenues:
Gas operating revenues	$	271,479		$	238,869		$	757,972		$	732,469		$	1,325,657		$	1,267,567
Construction revenues		181,674			172,705			303,577			292,610			661,595			617,877

Total operating revenues		453,153			411,574			1,061,549			1,025,079			1,987,252			1,885,444

Operating expenses:
Net cost of gas sold		97,985			69,388			289,362			269,996			455,367			414,892
Operations and maintenance		97,620			94,935			200,028			192,022			392,920			374,267
Depreciation and amortization		62,186			58,570			125,077			117,503			244,391			231,225
Taxes other than income taxes		10,965			11,073			22,421			22,868			45,104			44,131
Construction expenses		157,642			148,700			270,841			255,388			588,737			532,106

Total operating expenses		426,398			382,666			907,729			857,777			1,726,519			1,596,621

Operating income		26,755			28,908			153,820			167,302			260,733			288,823

Other income and (expenses):
Net interest deductions		(17,305	)		(15,290	)		(34,824	)		(31,168	)		(67,356	)		(63,777	)
Other income (deductions)		2,863			1,452			4,475			5,521			11,254			6,994

Total other income and (expenses)		(14,442	)		(13,838	)		(30,349	)		(25,647	)		(56,102	)		(56,783	)

Income before income taxes		12,313			15,070			123,471			141,655			204,631			232,040
Income tax expense		2,686			5,003			43,147			50,914			70,175			83,607

Net income		9,627			10,067			80,324			90,741			134,456			148,433
Net income (loss) attributable to noncontrolling interest		—			(41	)		(86	)		(140	)		(393	)		(536	)

Net income attributable to Southwest Gas Corporation	$	9,627		$	10,108		$	80,410		$	90,881		$	134,849		$	148,969

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

Diluted earnings per share	$	0.21		$	0.22		$	1.71		$	1.95		$	2.88		$	3.19

Dividends declared per share	$	0.365		$	0.330		$	0.730		$	0.660		$	1.390		$	1.250

Average number of common shares outstanding		46,502			46,331			46,471			46,291			46,407			46,214
Average shares outstanding (assuming dilution)		46,948			46,757			46,910			46,704			46,860			46,654

The accompanying notes are an integral part of these statements.


		3


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

(Unaudited)


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

Other comprehensive income (loss), net of tax
Defined benefit pension plans:
Net actuarial gain (loss)		—			—			—			—			62,214			(46,409	)
Amortization of prior service cost		55			54			110			109			221			109
Amortization of transition obligation		—			—			—			—			—			270
Amortization of net actuarial loss		3,666			5,298			7,333			10,596			17,927			18,530
Prior service cost		—			—			—			—			—			(1,502	)
Regulatory adjustment		(3,210	)		(4,702	)		(6,420	)		(9,404	)		(73,667	)		24,366

Net defined benefit pension plans		511			650			1,023			1,301			6,695			(4,636	)

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

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

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

Comprehensive income		10,657			11,236			82,384			93,079			143,225			145,871
Comprehensive income (loss) attributable to noncontrolling interest		—			(41	)		(86	)		(140	)		(393	)		(536	)

Comprehensive income attributable to Southwest Gas Corporation	$	10,657		$	11,277		$	82,470		$	93,219		$	143,618		$	146,407

The accompanying notes are an integral part of these statements.


		4


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

(Unaudited)


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

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

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

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

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

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

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

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

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

The accompanying notes are an integral part of these statements.


		5


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Note 1 – Nature of Operations and Basis of Presentation

Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. All of Southwest’s service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on operating margin. The timing and amount of rate relief can materially impact results of operations. Natural gas sales are seasonal, peaking during the winter months; therefore, results of operations for interim periods are not necessarily indicative of results for a full year. Natural gas purchases and the timing of related recoveries can materially impact liquidity. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. Typically, NPL revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating revenues typically improve as more favorable weather conditions occur during the summer and fall months.

Basis of Presentation. The condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. The preparation of the condensed consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the opinion of management, all adjustments, consisting of normal recurring items and estimates necessary for a fair presentation of results for the interim periods, have been made. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the 2013 Annual Report to Shareholders, which is incorporated by reference into the 2013 Form 10-K, and the first quarter 2014 Form 10-Q.

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

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

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


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

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.


		6


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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


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

Total	$	268		$	261

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


	Three Months Ended						Six Months Ended					Twelve Months Ended
	June 30						June 30					June 30
	2014			2013			2014		2013			2014			2013
Change in COLI policies	$	2,300		$	1,800		$	3,200	$	5,600		$	10,000		$	8,900
Interest income		612			144			1,109		264			1,306			683
Pipe replacement costs		—			(36	)		—		(121	)		(11	)		(1,759	)
Miscellaneous income and (expense)		(49	)		(456	)		166		(222	)		(41	)		(830	)

Total other income (deductions)	$	2,863		$	1,452		$	4,475	$	5,521		$	11,254		$	6,994

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work. The replacement program work subject to non-recoverability was substantially completed in 2012.

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

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

Note 2 – Components of Net Periodic Benefit Cost

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


		7


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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
	Period Ended June 30,
	Three Months						Six Months						Twelve Months
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	5,340		$	5,764		$	10,680		$	11,528		$	22,208		$	21,688
Interest cost		10,860			9,402			21,721			18,803			40,525			37,936
Expected return on plan assets		(13,335	)		(12,460	)		(26,671	)		(24,920	)		(51,591	)		(47,810	)
Amortization of net actuarial loss		5,718			8,065			11,436			16,131			27,566			28,072

Net periodic benefit cost	$	8,583		$	10,771		$	17,166		$	21,542		$	38,708		$	39,886


	SERP
	Period Ended June 30,
	Three Months						Six Months						Twelve Months
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	73		$	93		$	146		$	187		$	332		$	324
Interest cost		436			384			872			767			1,640			1,582
Amortization of net actuarial loss		196			243			392			486			877			827

Net periodic benefit cost	$	705		$	720		$	1,410		$	1,440		$	2,849		$	2,733


	PBOP
	Period Ended June 30,
	Three Months						Six Months						Twelve Months
(Thousands of dollars)	2014			2013			2014			2013			2014			2013
Service cost	$	275		$	305		$	551		$	610		$	1,161		$	1,098
Interest cost		708			621			1,415			1,241			2,656			2,515
Expected return on plan assets		(816	)		(706	)		(1,632	)		(1,412	)		(3,044	)		(2,614	)
Amortization of prior service cost		88			88			177			177			355			177
Amortization of transition obligation		—			—			—			—			—			434
Amortization of net actuarial loss		—			237			—			473			472			988

Net periodic benefit cost	$	255		$	545		$	511		$	1,089		$	1,600		$	2,598

Note 3 – Segment Information

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


	Natural Gas Operations		Construction Services		Total
Three months ended June 30, 2014
Revenues from external customers	$	271,479	$	156,966	$	428,445
Intersegment revenues		—		24,708		24,708

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

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

Three months ended June 30, 2013
Revenues from external customers	$	238,869	$	150,434	$	389,303
Intersegment revenues		—		22,271		22,271

Total	$	238,869	$	172,705	$	411,574

Segment net income	$	1,964	$	8,144	$	10,108


		8


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014


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

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

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

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

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

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


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

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

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

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

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

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

Note 4 – Derivatives and Fair Value Measurements

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

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (up to approximately 35%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from July 2014 through March 2016. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):


		9


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014


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

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 June 30, 2014 and 2013 and their location in the Condensed Consolidated Statements of Income (thousands of dollars):

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

(Thousands of dollars)


		Three Months Ended						Six Months Ended						Twelve Months Ended
Instrument	Location of Gain or (Loss) Recognized in Income on Derivative	June 30						June 30						June 30
Instrument		2014			2013			2014			2013			2014			2013
Swaps	Net cost of gas sold	$	(83	)	$	(7,669	)	$	5,907		$	(2,593	)	$	9,476		$	(2,885	)
Swaps	Net cost of gas sold		83	*		7,669	*		(5,907	)*		2,593	*		(9,476	)*		2,885	*

Total		$	—		$	—		$	—		$	—		$	—		$	—

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

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

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

Fair values of derivatives not designated as hedging instruments:


June 30, 2014		Asset Derivatives		Liability Derivatives			Net Total
Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	483	$	—		$	483
Swaps	Prepaids and other current assets		1,884		(140	)		1,744

Total		$	2,367	$	(140	)	$	2,227


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

Total		$	1,444	$	(623	)	$	821

The estimated fair values of the natural gas derivatives were determined using future natural gas index prices (as more fully described below). The Company has master netting arrangements with each counterparty that provide for the net settlement of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets. The Company had no outstanding collateral associated with the Swaps during either period shown in the above table.

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under


		10


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. Neither changes in fair value, nor settled amounts, of Swaps have a direct effect on earnings or other comprehensive income.

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


(Thousands of dollars)	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014		Twelve Months Ended June 30, 2014
Paid to counterparties	$	—	$	15	$	2,291

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

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


June 30, 2014 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(483	)
Swaps	Other current liabilities		(1,744	)

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

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at June 30, 2014 and December 31, 2013 using New York Mercantile Exchange (“NYMEX”) futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

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

Level 2 - Significant other observable inputs


(Thousands of dollars)	June 30, 2014		December 31, 2013
Assets at fair value:
Prepaids and other current assets - Swaps	$	1,744	$	801
Deferred charges and other assets - Swaps		483		180

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

Net Assets (Liabilities)	$	2,227	$	821

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


		11


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Note 5 – Long-Term Debt

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


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

		902,106					901,940

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

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

		438,345					438,279

NPL credit facility		12,529			12,529		—			—
NPL other debt obligations		36,687			36,851		42,213			42,119

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

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

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


		12


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

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

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

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


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

JUNE 30, 2014		46,503	$	48,133	$	844,851	$	(39,638	)	$	613,760		$	(2,214	)	$	1,464,892

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


		13


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

(Thousands of dollars)


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

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

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

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

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


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

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

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

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

Total other comprehensive income (loss)	$	3,323		$	(1,263	)	$	2,060		$	3,772		$	(1,434	)	$	2,338


	Twelve Months Ended June 30, 2014									Twelve Months Ended June 30, 2013
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(134	)		221			177			(68	)		109
Amortization of transition obligation		—			—			—			434			(164	)		270
Amortization of net actuarial (gain)/loss		28,915			(10,988	)		17,927			29,887			(11,357	)		18,530
Prior service cost		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		(118,817	)		45,150			(73,667	)		39,300			(14,934	)		24,366

Pension plans other comprehensive income (loss)		10,798			(4,103	)		6,695			(7,478	)		2,842			(4,636	)

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

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

Total other comprehensive income (loss)	$	14,143		$	(5,374	)	$	8,769		$	(4,133	)	$	1,571		$	(2,562	)

Tax amounts are calculated using a 38% rate.

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


		14


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

AOCI - Rollforward

(Thousands of dollars)


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

Other comprehensive income before reclassifications		—			—			—			—			—			—			—
FSIRS amounts reclassified from AOCI (1)		—			—			—			1,673			(636	)		1,037			1,037
Amortization of prior service cost (2)		177			(67	)		110			—			—			—			110
Amortization of net actuarial loss (2)		11,828			(4,495	)		7,333			—			—			—			7,333
Regulatory adjustment (3)		(10,355	)		3,935			(6,420	)		—			—			—			(6,420	)

Net current period other comprehensive income (loss)		1,650			(627	)		1,023			1,673			(636	)		1,037			2,060

Ending Balance AOCI June 30, 2014	$	(39,573	)	$	15,038		$	(24,535	)	$	(24,360	)	$	9,257		$	(15,103	)	$	(39,638	)

(1)	The FSIRS reclassification amounts are included in the Net interest deductions line item on the Condensed Consolidated Statements of Income.

(2)	These AOCI components are included in the computation of net periodic benefit cost (see Note 2 – Components of Net Periodic Benefit Cost for additional details).

(3)	The regulatory adjustment represents the portion of the activity above that is expected to be recovered through rates in the future (the related regulatory asset is included in the Deferred charges and other assets line item on the Condensed Consolidated Balance Sheets).

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:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)


	June 30, 2014			December 31, 2013
Net actuarial (loss) gain	$	(277,313	)	$	(289,141	)
Prior service cost		(1,890	)		(2,067	)
Less: amount recognized in regulatory assets		239,630			249,985

Recognized in AOCI	$	(39,573	)	$	(41,223	)

Note 7 – Purchase of Corporate Headquarters Office Complex

In July 2014, the Company purchased for $16.5 million a portion of its corporate headquarters office complex in Las Vegas that it had previously leased. With the closing of the purchase, the lease terminated. At June 30, 2014, the purchase price plus related closing costs and fees were being held in escrow until the purchase was consummated. This amount is shown as restricted cash on the condensed consolidated balance sheet at June 30, 2014.


		15


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Southwest is the largest distributor of natural gas in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas for customers in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

As of June 30, 2014, Southwest had 1,910,000 residential, commercial, industrial, and other natural gas customers, of which 1,023,000 customers were located in Arizona, 699,000 in Nevada, and 188,000 in California. Residential and commercial customers represented over 99% of the total customer base. During the twelve months ended June 30, 2014, 56% of operating margin was earned in Arizona, 34% in Nevada, and 10% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting changes in operating margin are general rate relief and customer growth. All of Southwest’s service territories have decoupled rate structures, which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of weather variability and conservation on margin, allowing the Company to aggressively pursue energy efficiency initiatives.

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

This Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and the notes thereto, as well as MD&A included in the 2013 Annual Report to Shareholders, which is incorporated by reference into the 2013 Form 10-K, and the first quarter 2014 Form 10-Q.


		16


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations. As needed, certain items are covered in greater detail in later sections of management’s discussion and analysis. As reflected in the table below, the natural gas operations segment accounted for an average of 84% 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.

Summary Operating Results


	Period Ended June 30,
	Three Months				Six Months				Twelve Months
	2014		2013		2014		2013		2014		2013
	(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	1,798	$	1,964	$	74,397	$	81,256	$	117,310	$	121,877
Construction services		7,829		8,144		6,013		9,625		17,539		27,092

Net income	$	9,627	$	10,108	$	80,410	$	90,881	$	134,849	$	148,969

Average number of common shares outstanding		46,502		46,331		46,471		46,291		46,407		46,214

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

Natural Gas Operations
Operating margin	$	173,494	$	169,481	$	468,610	$	462,473	$	870,290	$	852,675

2nd Quarter 2014 Overview

Natural gas operations highlights include the following:

•

Operating margin increased $4 million, or 2%, compared to the prior-year quarter

•

Operating expenses increased $5.4 million, or 3%, compared to the prior-year quarter

•

Other income increased $1.4 million between quarters

•

Net financing costs increased $2.2 million compared to the prior-year quarter

•

Decision reached in the California general rate case

Construction services highlights include the following:

•

Revenues increased $9 million, or 5%, compared to the prior-year quarter

•

Construction expenses increased $8.9 million, or 6%, compared to the prior-year quarter

•

Contribution to net income decreased $315,000 between quarters


		17


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

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

Company-Owned Life Insurance (“COLI”). Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $240 million at June 30, 2014. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $96.2 million at June 30, 2014 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration and purchase additional policies as necessary. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with movements in the broader stock and bond markets. As indicated in Note 1 of the Notes to Condensed Consolidated Financial Statements, cash surrender values of COLI policies increased $2.3 million in the second quarter of 2014, $3.2 million in the first six months of 2014, and $10 million (including incremental death benefits) during the twelve months ended June 30, 2014. Management currently expects average returns of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized, although in any given period, losses are possible.

Liquidity. Southwest believes its liquidity position is solid. Southwest has a $300 million credit facility maturing in March 2019. The facility is provided through a consortium of eight major banking institutions. No borrowings were outstanding on the credit facility (including a commercial paper program) at any time during the second quarter of 2014. At June 30, 2014, no borrowings were outstanding on the long-term or short-term portions of the credit facility. Southwest has no significant debt maturities prior to 2017.


		18


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Results of Natural Gas Operations

Quarterly Analysis


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

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

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

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

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

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

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

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

Depreciation and amortization expense increased $2.8 million, or 6% between quarters. Average gas plant in service for the current quarter increased $290 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.

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

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

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


		19


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Six-Month Analysis


	Six Months Ended June 30,
	2014		2013
	(Thousands of dollars)
Gas operating revenues	$	757,972	$	732,469
Net cost of gas sold		289,362		269,996

Operating margin		468,610		462,473
Operations and maintenance expense		200,028		192,022
Depreciation and amortization		102,007		96,065
Taxes other than income taxes		22,421		22,868

Operating income		144,154		151,518
Other income (deductions)		4,460		5,511
Net interest deductions		34,286		30,564

Income before income taxes		114,328		126,465
Income tax expense		39,931		45,209

Contribution to consolidated net income	$	74,397	$	81,256

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

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

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

Depreciation and amortization expense increased $5.9 million, or 6% between periods. Average gas plant in service for the current period increased $279 million, or 6%, compared to the corresponding period a year ago. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Amortization associated with the recovery of regulatory assets increased approximately $1 million.

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

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


		20


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Twelve-Month Analysis


	Twelve Months Ended June 30,
	2014		2013
	(Thousands of dollars)
Gas operating revenues	$	1,325,657	$	1,267,567
Net cost of gas sold		455,367		414,892

Operating margin		870,290		852,675
Operations and maintenance expense		392,920		374,267
Depreciation and amortization		199,790		189,435
Taxes other than income taxes		45,104		44,131

Operating income		232,476		244,842
Other income (deductions)		11,210		6,990
Net interest deductions		66,277		62,518

Income before income taxes		177,409		189,314
Income tax expense		60,099		67,437

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

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

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

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

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

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

Other income increased $4.2 million between the twelve-month periods of 2014 and 2013. The current period reflects a $10 million increase in COLI policy cash surrender values including net death benefits recognized, while the prior twelve-month period reflected a $8.9 million increase in COLI-related income and net death benefits recognized. In addition, Arizona non-recoverable pipe replacement costs were $1.7 million lower in the current twelve-month period as this pipe replacement activity was substantially completed in 2012.

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


		21


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Outlook for 2014 – 2nd Quarter Update

Operating margin for 2014 is expected to be favorably influenced by customer growth similar to 2013. Rate relief from the California rate case decision, effective June 2014, is expected to provide approximately $5 million of incremental margin in the second half of 2014 (see Rates and Regulatory Proceedings).

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

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

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

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

Results of Construction Services

Results of Construction Services


	Three Months Ended June 30,					Six Months Ended June 30,						Twelve Months Ended June 30,
	2014		2013			2014			2013			2014			2013
(Thousands of dollars)
Construction revenues	$	181,674	$	172,705		$	303,577		$	292,610		$	661,595		$	617,877
Operating expenses:
Construction expenses		157,642		148,700			270,841			255,388			588,737			532,106
Depreciation and amortization		11,662		10,824			23,070			21,438			44,601			41,790

Operating income		12,370		13,181			9,666			15,784			28,257			43,981
Other income (deductions)		15		4			15			10			44			4
Net interest deductions		246		404			538			604			1,079			1,259

Income before income taxes		12,139		12,781			9,143			15,190			27,222			42,726
Income tax expense		4,310		4,678			3,216			5,705			10,076			16,170

Net income		7,829		8,103			5,927			9,485			17,146			26,556
Net income (loss) attributable to noncontrolling interest		—		(41	)		(86	)		(140	)		(393	)		(536	)

Contribution to consolidated net income attributable to NPL	$	7,829	$	8,144		$	6,013		$	9,625		$	17,539		$	27,092

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

Revenues increased $9 million when compared to the second quarter of 2013 primarily due to incremental work with several customers and progress on delayed work from the first quarter. Construction expenses increased $8.9 million between quarters, primarily due to the above revenue growth. Depreciation expense increased $838,000 due to new equipment purchases. Gains on sale of equipment (reflected as an offset to construction expenses) were $1.7 million and $1.5 million for the second quarters of 2014 and 2013, respectively.

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


		22


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

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

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

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

Outlook for 2014 – 2nd Quarter Update

NPL’s revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Typically, revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. The current low interest rate environment, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on NPL’s revenues.

Management has an improved infrastructure in place on which to grow the business and is seeking to increase revenues by approximately 5% to 8% annually on average over the long term. Ultimately, revenues are subject to the timing and amount of work awarded to NPL by its utility customers. As noted above, extreme winter weather conditions during the first quarter of 2014 hindered normal construction work in the Midwest and East Coast operating areas. Weather conditions improved in the second quarter of 2014 and NPL is moving forward in an expedited manner to complete delayed work available under blanket contracts. Management remains cautiously optimistic that NPL earnings for the full year 2014 will be consistent with, or exceed, 2013 results.


		23


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

Rates and Regulatory Proceedings

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

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

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

Separately, in March 2013, Southwest submitted a petition to the PUCN requesting authority to defer certain costs associated with the proposed accelerated 2013 replacement of certain EVPP to coincide with bonus depreciation tax relief extended by The American Taxpayer Relief Act of 2012. In June 2013, a stipulation (the “Stipulation”), which provided regulatory asset treatment for specific infrastructure replacement projects occurring during 2013 in the amount of $2 million in northern Nevada and approximately $13.6 million in southern Nevada, was reached by all parties and was approved by the PUCN. While the above-noted infrastructure replacement regulation was being finalized, the Company submitted a filing to the PUCN in November 2013 requesting authority to replace $18.9 million of EVPP in 2014; the PUCN approved the request in January 2014. The new rules (noted in the preceding paragraph above) enabled the Company to make a filing in May 2014 identifying projects for replacement beginning in January 2015.

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

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


		24


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

balance to be incorporated in base rates at the time of the next Arizona general rate case. In November 2013, the Company filed a request to modify or clarify the COYL provision to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. This request was approved by the ACC in January 2014, and requires that these replacements be coordinated with the Company’s other pipeline replacement projects and that the Company will prioritize leaking COYLs over non-leaking COYLs. A revised surcharge request, filed in February 2014, which proposed to increase COYL cost recovery to approximately $1.5 million annually was approved effective June 2014 (through an updated surcharge of $0.00231 per therm). Approximately 98% of COYL customers were contacted for testing through June 2014. Through these efforts, approximately 5,000 relocations have been completed or are in progress.

Proposed LNG Facility. In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. Such an LNG facility would be designed to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system) not to exceed $55 million. The proposed LNG facility would provide a local storage option, operated by Southwest and connected directly to its distribution system, providing greater flexibility to serve customers. An ACC decision is expected to occur during 2014. If approved, construction is expected to be complete within approximately 24 to 30 months following ACC approval.

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

Paiute Pipeline Company filed a general rate case with the FERC in February 2014. The filing fulfilled an obligation from the settlement agreement reached in the 2009 Paiute general rate case. The application requested an increase in operating revenues of approximately $9 million, and included a proposed change in rate design, which would compensate Paiute with a higher return if shippers desire to maintain shorter-lived contracts and, therefore, would incent shippers to sign longer term service agreements. A final decision has not been rendered and the parties to the case are in settlement discussions. In accordance with FERC requirements, new rates will go into effect in September 2014 (based on contracts then in effect), subject to refund, if a settlement among the parties has not been approved by the FERC by that time, and hearings would then be conducted in early 2015. Paiute’s previous general rate case was filed in 2009.

PGA Filings

The rate schedules in all of Southwest’s service territories contain provisions that permit adjustments to rates as the cost of purchased gas changes. These deferred energy provisions and purchased gas adjustment clauses are collectively referred to as “PGA” clauses. Differences between gas costs recovered from customers and amounts paid for gas by Southwest result in over- or under-collections. At June 30, 2014, under-collections in all three states resulted in an asset of $80.4 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).


		25


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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


	June 30, 2014		December 31, 2013		June 30, 2013
Arizona	$	47.9	$	3.2	$	(16.0	)
Northern Nevada		3.7		4.4		(3.8	)
Southern Nevada		24.5		4.1		(8.8	)
California		4.3		6.5		—

	$	80.4	$	18.2	$	(28.6	)

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

Capital Resources and Liquidity

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

Cash Flows

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

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

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

The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources.

Gas Segment Construction Expenditures, Debt Maturities, and Financing

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


		26


SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

and provided approximately 70% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and existing credit facilities.

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2016 will be approximately $1.1 billion. Of this amount, it is expected that approximately $375 million will be incurred in 2014. Southwest plans to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). Significant replacement activities are expected to continue during the next several years. See also Rates and Regulatory Proceedings for discussion of Nevada infrastructure, Arizona COYL, a proposed LNG facility, and planned Paiute expansion. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 85% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

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

Dividend Policy

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

Liquidity

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

On an interim basis, Southwest generally defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At June 30, 2014, the combined balance in the PGA accounts totaled an under-collection of $80.4 million. See PGA Filings for more information.

The Company has a $300 million revolving credit facility that was scheduled to expire in March 2017. In March 2014, the credit facility expiration was extended by two years to March 2019. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. At June 30, 2014, no borrowings were outstanding on either the long-term or short-term portions of the credit facility. 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


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SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

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

NPL has a $75 million credit facility that is scheduled to expire in June 2015. At June 30, 2014, $12.5 million was outstanding on the NPL credit facility.

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


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

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.

Legal Accrual

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers would be responsible for amounts up to the policy limits. For the policy year August 2013 to July 2014, these liability insurance policies require Southwest to be responsible for the first $1 million dollars (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. At any given time the Company is involved in various legal matters. Through an assessment process, the Company may determine that certain costs are likely to be incurred in the future related to specific legal matters. In these circumstances and in accordance with accounting policies, the Company will make an accrual. In the first quarter of 2014, the Company recorded a $5 million accrual (the maximum self-insured retention plus aggregate for the policy year) in connection with an incident.

Forward-Looking Statements

This quarterly report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this quarterly report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote”, “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest expense, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, amount and timing for completion of estimated future construction expenditures, including the planned LNG facility in southern Arizona and the proposed Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, incremental operating margin in 2014, operating expense increases in 2014, funding sources of cash requirements, sufficiency of working capital and current credit facility, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, NPL’s projected financial performance and related market growth potential, pension and post-retirement benefits, the effect of any rate changes or regulatory proceedings, including the Paiute Pipeline Company general rate case filing,


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SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

infrastructure replacement mechanisms and the COYL programs, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, results of NPL bid work, impacts of structural and management changes at NPL, NPL construction expenses, NPL’s ability to expedite projects delayed by weather, differences between actual and originally expected outcomes of NPL bid or other fixed-price construction agreements, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.

CONTROLS AND PROCEDURES

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

Based on the most recent evaluation, as of June 30, 2014, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.

There have been no changes in the Company’s internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the second quarter of 2014 that have materially affected, or are likely to materially affect, the Company’s internal controls over financial reporting.


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SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

ITEMS

1A. through 3. None.

ITEM 4.

MINE SAFETY DISCLOSURES Not applicable.

ITEM 5.

OTHER INFORMATION None.

ITEM 6.

EXHIBITS

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


Exhibit 12.01	-	Computation of Ratios of Earnings to Fixed Charges.

Exhibit 31.01	-	Section 302 Certifications.

Exhibit 32.01	-	Section 906 Certifications.

Exhibit 101	-	The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, formatted in Extensible Business Reporting Language (“XBRL”): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Income, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) the Notes to the Condensed Consolidated Financial Statements.


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SOUTHWEST GAS CORPORATION		Form 10-Q
June 30, 2014

SIGNATURES

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


				Southwest Gas Corporation
				(Registrant)

Date: August 6, 2014

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


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