Exhibit 13.01

Consolidated Selected Financial Statistics

Year Ended December 31,	2016			2015			2014			2013			2012
(Thousands of dollars, except per share amounts)
Operating revenues	$	2,460,490		$	2,463,625		$	2,121,707		$	1,950,782		$	1,927,778
Operating expenses		2,164,776			2,175,293			1,837,224			1,676,567			1,656,254
Operating income	$	295,714		$	288,332		$	284,483		$	274,215		$	271,524
Net income attributable to Southwest
Gas Corporation	$	152,041		$	138,317		$	141,126		$	145,320		$	133,331
Total assets at year end	$	5,581,126		$	5,358,685		$	5,208,297		$	4,565,174		$	4,488,057
Capitalization at year end
Total equity	$	1,661,273		$	1,592,325		$	1,486,266		$	1,412,395		$	1,308,498
Redeemable noncontrolling interest		22,590			16,108			20,042			—			—
Long-term debt, excluding current maturities		1,549,983			1,551,204			1,631,374			1,381,327			1,268,373
	$	3,233,846		$	3,159,637		$	3,137,682		$	2,793,722		$	2,576,871
Current maturities of long-term debt	$	50,101		$	19,475		$	19,192		$	11,105		$	50,137
Common stock data
Common equity percentage of capitalization		51.4	%		50.4	%		47.4	%		50.6	%		50.8	%
Return on average common equity		9.3	%		8.9	%		9.7	%		10.6	%		10.4	%
Basic earnings per share	$	3.20		$	2.94		$	3.04		$	3.14		$	2.89
Diluted earnings per share	$	3.18		$	2.92		$	3.01		$	3.11		$	2.86
Dividends declared per share	$	1.80		$	1.62		$	1.46		$	1.32		$	1.18
Payout ratio		56	%		55	%		48	%		42	%		41	%
Book value per share at year end	$	35.03		$	33.65		$	32.03		$	30.51		$	28.39
Market value per share at year end	$	76.62		$	55.16		$	61.81		$	55.91		$	42.41
Market value to book value per share		219	%		164	%		193	%		183	%		149	%
Common shares outstanding at year end (000)		47,482			47,378			46,523			46,356			46,148
Number of common shareholders at year end		13,619			14,153			14,749			15,359			16,028
Ratio of earnings to fixed charges		3.46			3.43			3.58			3.90			3.61

Southwest Gas Corporation 14

Natural Gas Operations

Year Ended December 31,	2016			2015			2014			2013			2012
(Thousands of dollars)
Operating revenue	$	1,321,412		$	1,454,639		$	1,382,087		$	1,300,154		$	1,321,728
Net cost of gas sold		397,121			563,809			505,356			436,001			479,602
Operating margin		924,291			890,830			876,731			864,153			842,126
Expenses
Operations and maintenance		401,724			393,199			383,732			384,914			369,979
Depreciation and amortization		233,463			213,455			204,144			193,848			186,035
Taxes other than income taxes		52,376			49,393			47,252			45,551			41,728
Operating income	$	236,728		$	234,783		$	241,603		$	239,840		$	244,384
Contribution to consolidated net income	$	119,423		$	111,625		$	116,872		$	124,169		$	116,619
Total assets at year end	$	5,001,756		$	4,822,845		$	4,652,307		$	4,272,029		$	4,204,948
Net gas plant at year end	$	4,131,971		$	3,891,085		$	3,658,383		$	3,486,108		$	3,343,794
Construction expenditures and property additions	$	457,120		$	438,289		$	350,025		$	314,578		$	308,951
Cash flow, net
From operating activities	$	507,224		$	497,500		$	288,534		$	265,290		$	344,441
From (used in) investing activities		(446,238	)		(416,727	)		(328,645	)		(304,189	)		(296,886	)
From (used in) financing activities		(63,339	)		(74,159	)		23,413			44,947			(43,453	)
Net change in cash	$	(2,353	)	$	6,614		$	(16,698	)	$	6,048		$	4,102
Total throughput (thousands of therms)
Residential		684,626			655,421			617,377			741,327			655,046
Small commercial		294,525			285,118			276,582			298,045			270,665
Large commercial		90,949			92,284			94,391			102,761			116,582
Industrial/Other		30,275			30,973			32,374			50,210			47,830
Transportation		970,561			1,035,707			906,691			1,037,916			998,095
Total throughput		2,070,936			2,099,503			1,927,415			2,230,259			2,088,218
Weighted average cost of gas purchased ($/therm)	$	0.37		$	0.44		$	0.55		$	0.42		$	0.42
Customers at year end		1,984,000			1,956,000			1,930,000			1,904,000			1,876,000
Employees at year end		2,247			2,219			2,196			2,220			2,245
Customer to employee ratio		883			881			879			858			836
Degree days – actual		1,613			1,512			1,416			1,918			1,740
Degree days – ten-year average		1,771			1,792			1,816			1,876			1,866

Southwest Gas Corporation 15

Management’s Discussion and Analysis of Financial Condition and Results of Operations

About Southwest Gas Corporation

In 2015, the Board of Directors (“Board”) of Southwest Gas Corporation authorized management to evaluate and pursue a holding company reorganization to provide further separation between regulated and unregulated businesses, and to provide additional financing flexibility. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company; whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of the reorganization were filed with the Arizona Corporation Commission (“ACC”), the California Public Utilities Commission (“CPUC”), and the Public Utilities Commission of Nevada (“PUCN”) in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The reorganization, which was approved by the Board in December 2016, became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016.

The Company consists 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 December 31, 2016, Southwest had 1,984,000 residential, commercial, industrial, and other natural gas customers, of which 1,058,000 customers were located in Arizona, 733,000 in Nevada, and 193,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2016, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 85% of its operating margin (gas operating revenues less the net cost of gas sold) from residential and small commercial customers, 3% from other sales customers, and 12% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting changes in operating margin are general rate relief (including the impact of

Southwest Gas Corporation 16

infrastructure trackers) and customer growth. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), 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 Southwest to pursue energy efficiency initiatives.

Centuri is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operates in 20 major markets in the United States (primarily as NPL) and in 2 major markets in Canada (as NPL Canada (formerly Link-Line Contractors Ltd.), and W.S. Nicholls). 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, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented or modified pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with recent bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the U.S. Generally, revenues are lowest during the first quarter of the year due to less favorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. This is expected in both the U.S. and Canadian markets. In certain circumstances, such as with large bid contracts (especially those of a longer duration), or unit-price contracts with revenue caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and 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 81% of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

Summary Operating Results

Year ended December 31,	2016		2015		2014
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	119,423	$	111,625	$	116,872
Construction services		32,618		26,692		24,254
Consolidated	$	152,041	$	138,317	$	141,126
Average number of common shares outstanding		47,469		46,992		46,494
Basic earnings per share
Consolidated	$	3.20	$	2.94	$	3.04
Natural Gas Operations
Gas operating revenues	$	1,321,412	$	1,454,639	$	1,382,087
Net cost of gas sold		397,121		563,809		505,356
Operating margin	$	924,291	$	890,830	$	876,731

Southwest Gas Corporation 17

2016 Overview

Consolidated results for 2016 increased compared to 2015 as improvements were experienced in both operating segments. Basic earnings per share were $3.20 in 2016 compared to basic earnings per share of $2.94 in 2015.

Natural gas operations highlights include the following:

• 28,000 net new customers (1.4% growth rate)

• Operating margin increased $33 million, or 4%, compared to the prior year

• Net financing costs increased $3 million between 2016 and 2015

• COLI income was $7.4 million in 2016 compared to a loss of $500,000 in 2015

• Redeemed $100 million of 4.85% and $24.9 million of 4.75% IDRBs

• Issued $300 million of 3.8% senior notes

• Credit facility expiration date extended one year to March 2021

• Settlement reached among several parties in Arizona general rate case (regulatory approval pending)

• Holding company reorganization became effective in January 2017

Construction services highlights include the following:

• Revenues in 2016 increased $130 million, or 13%, compared to 2015

• Construction expenses increased $126 million, or 14%, compared to 2015

• Contribution to net income increased $6 million compared to 2015

• Acquisition of ETTI construction businesses in May 2016

• Hired Paul Daily as CEO of Centuri

Results of Natural Gas Operations

Year Ended December 31,	2016		2015		2014
(Thousands of dollars)
Gas operating revenues	$	1,321,412	$	1,454,639	$	1,382,087
Net cost of gas sold		397,121		563,809		505,356
Operating margin		924,291		890,830		876,731
Operations and maintenance expense		401,724		393,199		383,732
Depreciation and amortization		233,463		213,455		204,144
Taxes other than income taxes		52,376		49,393		47,252
Operating income		236,728		234,783		241,603
Other income (deductions)		8,276		2,292		7,165
Net interest deductions		66,997		64,095		68,299
Income before income taxes		178,007		172,980		180,469
Income tax expense		58,584		61,355		63,597
Contribution to consolidated net income	$	119,423	$	111,625	$	116,872

2016 vs. 2015

The contribution to consolidated net income from natural gas operations increased $7.8 million between 2016 and 2015. The improvement was primarily due to an increase in operating margin and other income, partially offset by an increase in operating expenses and net interest deductions.

Operating margin increased $33 million between years. Combined rate relief in the California jurisdiction and Paiute Pipeline Company provided $10 million in operating margin (see Rates and Regulatory Proceedings). New

Southwest Gas Corporation 18

customers contributed $8 million in operating margin. The Nevada Conservation and Energy Efficiency (“CEE”) surcharge, which was implemented in January 2016, provided $11 million of the increase. Amounts collected through the surcharge do not impact net income as they also result in an increase in associated amortization expense. Infrastructure replacement mechanisms and customers outside the decoupling mechanisms, as well as other miscellaneous revenues, collectively provided $4 million of operating margin.

Operations and maintenance expense increased $8.5 million, or 2%, between 2016 and 2015 due primarily to general cost increases and higher employee medical costs, partially offset by a decline in pension expense. Higher expenses for pipeline integrity management and damage prevention programs accounted for $2.6 million of the increase.

Depreciation and amortization expense increased $20 million, or 9%. Average gas plant in service for the current year increased $341 million, or 6%, as compared to the prior year. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new infrastructure, which collectively resulted in increased depreciation expense. Amortizations associated with the recovery of regulatory assets increased approximately $7.1 million overall, notably due to amortization accompanying the recovery of Nevada CEE costs indicated above.

Taxes other than income taxes increased $3 million, or 6%, between 2016 and 2015 primarily due to higher property taxes associated with net plant additions.

Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, increased $6 million between 2016 and 2015. The current year reflects $7.4 million of COLI-related income associated with cash surrender value increases and recognized net death benefits, while the prior-year period reflected a COLI-related loss of $500,000.

Net interest deductions increased $2.9 million between 2016 and 2015, primarily due to higher interest expense associated with deferred purchased gas adjustment (“PGA”) balances and the issuance of $300 million of senior notes. The increase was substantially offset by reductions associated with the redemption of debt ($20 million of 5.25% 2003 Series D IDRBs in September 2015, $100 million of 4.85% 2005 Series A IDRBs in July 2016, and $24.9 million of 4.75% 2006 Series A in September 2016).

The effective income tax rates in both 2016 and 2015 were impacted by COLI results, which are not subject to tax. Additionally, the Company claimed a federal income tax credit, which resulted in a recognized benefit of approximately $1.7 million during 2016.

2015 vs. 2014

The contribution to consolidated net income from natural gas operations decreased $5.2 million between 2015 and 2014. The decline was primarily due to an increase in operating expenses and a decrease in other income, partially offset by improved operating margin and a decline in net interest deductions.

Operating margin increased $14 million between 2015 and 2014. New customers contributed $8 million in operating margin during 2015. Combined rate relief in the California jurisdiction and Paiute Pipeline Company provided $5 million of the increase. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues increased by $1 million between these years.

Southwest Gas Corporation 19

Operations and maintenance expense increased $9.5 million, or 2%, between years due primarily to general cost increases and higher employee-related expenses, including pension expense, in 2015. These increases were partially offset by certain expenses that were higher in 2014, including a $5 million legal accrual in 2014 and $1.1 million in rent expense (associated with a previously leased corporate headquarters complex).

Depreciation and amortization expense increased $9.3 million, or 5% between 2015 and 2014. Average gas plant in service increased $276 million, or 5%, between these years. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new infrastructure, which collectively resulted in increased depreciation expense. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in California. Amortizations associated with the recovery of regulatory assets increased approximately $2.4 million overall (primarily due to Arizona integrity management and California energy efficiency programs).

Taxes other than income taxes increased $2.1 million, or 5%, between 2015 and 2014 primarily due to higher property taxes associated with net plant additions.

Other income decreased $4.9 million between 2015 and 2014. Cash surrender values of COLI policies decreased $500,000 in 2015, while COLI-related income was $5.3 million in 2014.

Net interest deductions decreased $4.2 million between years. The decrease primarily resulted from the redemptions of $65 million of 5.25% Series A IDRBs in November 2014, $31.2 million of 5.00% 2004 Series B IDRBs in May 2015, and $20 million of 5.25% 2003 Series D IDRBs in September 2015, partially offset by increased interest expense on PGA balances.

Results of Construction Services

Year Ended December 31,	2016		2015		2014
(Thousands of dollars)
Construction revenues	$	1,139,078	$	1,008,986	$	739,620
Operating expenses:
Construction expenses		1,024,423		898,781		647,857
Depreciation and amortization		55,669		56,656		48,883
Operating income		58,986		53,549		42,880
Other income (deductions)		1,193		587		(58	)
Net interest deductions		6,663		7,784		3,770
Income before income taxes		53,516		46,352		39,052
Income tax expense		19,884		18,547		14,776
Net income		33,632		27,805		24,276
Net income attributable to noncontrolling interests		1,014		1,113		22
Contribution to consolidated net income attributable to Centuri	$	32,618	$	26,692	$	24,254

In October 2014, construction services operations were expanded by the acquisition of the Link-Line group of companies. Line items in the table above reflect the results of the acquired companies only since the acquisition date. In May 2016, Centuri acquired ETTI. Line items in the tables above reflect the results of ETTI only since the acquisition date, including approximately $6 million in revenues during 2016.

Southwest Gas Corporation 20

2016 vs. 2015

Contribution to consolidated net income from construction services increased $5.9 million compared to 2015. Additional bid work, lower depreciation and amortization, and decreased interest expense positively impacted net income. The prior year included a $3.4 million pretax loss associated with an industrial construction project in Canada.

Revenues increased $130.1 million, or 13%, when compared to 2015, primarily due to work performed on certain large bid projects and additional pipe replacement work. In addition, higher revenues were recognized due to favorable weather conditions during the year, generally in the mid-western and north-eastern parts of the United States and in Canada, which extended the construction season. Governmental-mandated pipeline safety-related programs resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues include contracts with Southwest totaling $98 million in 2016 and $104 million in 2015. Centuri accounts for services provided to Southwest at contractual prices. Refer to Consolidation under Summary of Significant Accounting Policies in Note 1 to the consolidated financial statements.

Construction expenses increased $125.6 million, or 14%, during the year due to additional pipe replacement work, higher labor costs experienced due to changes in the mix of work with existing customers, and greater operating expenses to support increased growth in operations. General and administrative expense (included in construction expenses) increased approximately $1.6 million overall to support the growth in operations and the increasing size, geographic footprint and complexity of Centuri’s business. Gains on sale of equipment (reflected as an offset to construction expenses) were approximately $7.1 million and $3.4 million for 2016 and 2015, respectively.

Depreciation and amortization expense decreased $1 million between 2016 and 2015 primarily due to a $4 million reduction in depreciation associated with an extension of the estimated useful lives of certain depreciable equipment and to a decline in amortization of certain finite-lived intangible assets recognized from the October 2014 acquisition, partially offset by an increase in depreciation on additional equipment purchased to support the growing volume of work being performed.

Operating income increased $5.4 million, or 10%, when compared to 2015, primarily due to increased bid work at favorable profit margins overall.

Net interest deductions were lower by $1.1 million, primarily due to lower interest rates on outstanding borrowings during 2016 as compared to 2015 and to a decrease in the average line of credit balance outstanding during 2016.

During the past several years, construction services segment efforts have been focused on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2016 and 2015, revenues from replacement work were 65% and 68%, respectively, of total revenues. As noted above, governmental pipeline safety-related programs and U.S. bonus depreciation tax incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.

2015 vs. 2014

Contribution to consolidated net income from construction services for 2015 increased $2.4 million compared to 2014.

Revenues increased $269.4 million, or 36%, when compared to 2014, due to additional pipe replacement work and to 2015 including a full year of revenues of the acquired companies (an increase of $124 million). NPL revenues in

Southwest Gas Corporation 21

the United States increased over $140 million primarily due to securing contracts to perform accelerated pipeline replacement work for its large utility customers. Favorable weather conditions in several operating areas during the fourth quarter of 2015 also provided an extended construction season as compared to 2014. Governmental-mandated pipeline safety-related programs resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues included contracts with Southwest totaling $104 million in 2015 and $92 million in 2014.

Construction expenses increased $250.9 million, or 39%, due primarily to additional pipe replacement work in 2015 and the inclusion of a full year of the acquired companies’ construction costs (an increase of $115 million). The increase in expense included a $3.4 million loss on a previous Canadian project. General and administrative expense (included in construction expenses) increased approximately $9 million overall, including $8 million from the acquired companies, which included changes that were implemented to match the increased size of the business and its complexity. Offsetting these increases were approximately $5 million of acquisition-related expenses in 2014 that were not incurred in 2015. Gains on sale of equipment (reflected as an offset to construction expenses) were $3.4 million and $6.2 million in 2015 and 2014, respectively.

Depreciation and amortization expense increased $7.8 million between 2015 and 2014 due primarily to incremental amortization in 2015 related to finite-lived intangible assets recognized from the acquisition ($3 million) and to incremental depreciation from the acquired companies ($4 million).

Net interest deductions were $7.8 million in 2015 compared to $3.8 million in 2014. The increase was due primarily to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the acquisition.

Rates and Regulatory Proceedings

General Rate Relief and Rate Design

Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) changes, and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management has worked with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such rate structures were in place in all of Southwest’s operating areas during all periods (2014—2016) for which results of Natural Gas Operations are disclosed above.

Nevada Jurisdiction

General Rate Case Status.    The most recent general rate case decision was received from the PUCN in November 2012, and was amended in a Rehearing Decision in April 2013. Ultimately, Southwest was authorized an overall rate of return of 6.56%, and a 10% return on 42.7% common equity in southern Nevada; and an overall rate of return of 7.88%, and a 9.30% return on 59.1% common equity in northern Nevada.

General Revenues Adjustment.    As part of the Annual Rate Adjustment (“ARA”) filing in June 2016, Southwest requested authorization to adjust rates associated with its revenue decoupling mechanism (General Revenues

Southwest Gas Corporation 22

Adjustment, or “GRA”). The ARA, including amounts to refund the over-collected balance in the accounts associated with this mechanism, was approved in December 2016, with rates effective January 2017. The rate adjustment is expected to refund approximately $16.7 million during 2017. While there is no impact to net income overall from this rate adjustment, operating cash flows will be reduced as the regulatory liability balance is refunded.

Infrastructure Replacement Mechanisms.    In January 2014, the PUCN approved final rules for a mechanism to defer and recover certain costs associated with accelerated replacement of infrastructure that does not currently provide incremental revenues. This mechanism has been in place since that time. Each year, Southwest files a Gas Infrastructure Replacement (“GIR”) Advance Application requesting authority to replace infrastructure under this mechanism and files separately as part of an annual GIR filing to reset the recovery surcharge. In December 2015, the PUCN approved new rates, effective in January 2016, which resulted in approximately $4 million in annualized revenues. For 2016, the annualized revenue requirement associated with the accelerated pipe replacement approved in 2015, to be completed during 2016 was approximately $4.5 million. In June 2016, Southwest filed a GIR Advance Application with the PUCN for projects expected to be completed during 2017. This filing proposed approximately $60 million of accelerated pipe replacement to include early vintage plastic, early vintage steel, and a Customer-Owned Yard Line (“COYL”) program. The COYL program, while not large in magnitude, represents the first of its kind in Nevada, modeled after the program in place in Southwest’s Arizona jurisdiction for several years. The PUCN issued an Order on the Advance Application in October 2016, approving approximately $57.3 million of replacement work with an annualized revenue requirement estimated at approximately $5.3 million. The proposed COYL program was approved for the northern Nevada rate jurisdiction, but consideration for the southern Nevada rate jurisdiction was deferred until 2020, at which time certain early vintage plastic pipe programs are expected to be completed. In September 2016, Southwest filed to adjust the GIR surcharge to recover the annual revenue requirement for amounts previously deferred. This filing was approved in December 2016 and new rates became effective January 2017.

Subsequent to three GIR rate applications, the GIR regulations require Southwest to either file a general rate case or a request for waiver before it can file another GIR advance application. The October 2016 rate application was the third filed by Southwest, necessitating a filing requesting a waiver to allow Southwest to proceed with the GIR program without filing a general rate case in 2017. This waiver was approved by the PUCN in January 2017; however, in order to continue the GIR program in 2018, a general rate case will need to be filed before June 2018.

Conservation and Energy Efficiency(“CEE”).    In June 2015, Southwest requested recovery of energy efficiency and conservation development and implementation costs, including promotions and incentives for various programs, as originally approved for deferral by the PUCN effective November 2009. While recovery of initial program costs was approved as part of the most recent general rate case, amounts incurred subsequent to May 2012 (the certification period) continued to be deferred. Approved rates for the post-May 2012 costs deferred became effective January 2016 and resulted in annualized margin increases of $2 million in northern Nevada and $8.5 million in southern Nevada, and also include amounts representing expected program expenditures for 2016. As part of the ARA filing approved in December 2016, Southwest will modify rates that will result in annualized margin decreases of $1.4 million in northern Nevada and $1.3 million in southern Nevada effective January 2017. There is, however, no anticipated impact to net income overall from these lower recoveries as amortization expense will also be reduced.

Southwest Gas Corporation 23

California Jurisdiction

General Rate Case.    In December 2012, Southwest filed a general rate case application, based on a 2014 future test year, with the 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 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 (“CPUC decision”), authorizing a $7.1 million overall revenue increase and PTY attrition increases of 2.75% annually for 2015 to 2018. A depreciation reduction of $3.1 million, as requested by Southwest, was also approved. The CPUC decision also provided 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 CPUC decision were effective June 2014, and annual attrition increases were implemented in January of both 2015 and 2016 in accordance with the June 2014 decision.

In November 2016, Southwest made its latest annual PTY attrition filing, requesting annual revenue increases of $2.1 million in southern California, $513,000 in northern California, and $256,000 for South Lake Tahoe. This filing was approved in December 2016 and rates were made effective in January 2017. At the same time, rates were updated to recover the regulatory asset associated with the revenue decoupling mechanism, or margin tracker.

In December 2016, Southwest filed to modify the most recent general rate case decision to extend the annual PTY attrition adjustments through 2020. The original decision would have required Southwest to file its next general rate application by September 2017. Southwest believes this extension would be in the public interest as it allows customers two additional years of reasonable and relatively stable rates, and would not be expected to be detrimental to Southwest. Expedited consideration has been requested; however, Southwest also requested that if a decision has not been received by April 2017, the CPUC suspend the filing requirements until such time as a decision is issued.

Greenhouse Gas (“GHG”) Compliance.    California Assembly Bill Number 32 and the regulations promulgated by the California Air Resources Board (“CARB”), require Southwest, as a covered entity, to comply with all applicable requirements associated with the California GHG emissions reporting and the California Cap and Trade Program. The objective of these programs is to reduce California statewide GHG emissions to 1990 levels by 2020. Southwest must report annual GHG emissions by April of each year and third-party verification of those reported amounts is required by September of each year. Starting with 2015, the CARB will annually allocate to Southwest a certain number of allowances based on Southwest’s reported 2011 GHG emissions. Southwest received (in the third quarters of each year 2014 through 2016) its allocations for each year from 2015 through 2017. Of those allocated allowances, Southwest must consign a certain percentage to the CARB for auction. Southwest can use any allocated allowances that remain after consignment, along with allowances it can purchase through CARB auctions or reserve sales, or through over the counter (“OTC”) purchases with other market participants, to meet its compliance obligations. The CPUC has issued a decision that provides for the regulatory treatment of the program costs and there is no expected impact on earnings.

Southwest Gas Corporation 24

Arizona Jurisdiction

Arizona General Rate Case.    Southwest filed a general rate application with the ACC in May 2016 requesting an increase in authorized annual operating revenues of approximately $32 million, or 4.2%, to reflect existing levels of expense and requested returns, in addition to reflecting capital investments made by Southwest since June 2010. The application requested an overall rate of return of 7.82% on an original cost rate base of $1.336 billion, a 10.25% return on common equity, and a capital structure utilizing 52% common equity. The filing included a depreciation study that supported a proposal to reduce currently effective depreciation expense by approximately $42 million, which was considered in the overall requested amount. This expense reduction coupled with the requested revenue increase, resulted in a net annual operating income increase request of $74 million. Southwest also sought to continue the current COYL program approved in its last general rate case and to expand this mechanism to include other non-revenue producing projects such as the replacement of vintage steel pipe, while utilizing the same cost recovery methodology. Southwest also requested a property tax tracker and to maintain the current decoupled rate design. A settlement (contingent on ACC approval) was reached among several parties in December 2016 and a formal draft settlement was filed in January 2017. Hearings were held in February 2017. The draft settlement provides for an overall operating revenue increase of $16 million and the capital structure and cost of capital as proposed by Southwest, with the exception of the return on common equity, which would be set at 9.50%. If approved, depreciation expense would be reduced by $44.7 million, for a combined net annual operating income increase of $60.7 million. Other key elements of the draft settlement include approval of the continuation of the current COYL program, a property tax mechanism to defer any changes in property tax expense for recovery in the next general rate case, implementation of a vintage steel pipe replacement program, and a continuation of the current decoupled rate design excluding a winter-period adjustment to rates, making the mechanism fundamentally similar to Nevada. The draft settlement also includes a three-year rate case moratorium prohibiting a new application to adjust base rates from being filed prior to May 2019. Pending ACC approval, new rates are expected to be in place by May 2017.

LNG (“Liquefied Natural Gas”) Facility.    In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, to be operated by Southwest and connected directly to its distribution system. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system). In December 2014, Southwest received an order from the ACC granting pre-approval of Southwest’s application to construct the LNG facility and the deferral of costs, up to $50 million. The initial cost estimate was made in 2013 prior to selecting the land and receipt of the detailed engineering design specifications. Following the December 2014 preapproval, Southwest purchased the site for the facility and completed detailed engineering design specifications for the purpose of soliciting bids for the engineering, procurement and construction (“EPC”) of the facility. Southwest solicited requests for proposals for the EPC phase of the project, and in October 2016 made a filing with the ACC to modify the previously issued Order to update the pre-approved costs to reflect a not-to-exceed amount of $80 million, which was intended to update the pre-approval to reflect the current pricing information made available through the recently completed EPC phase. The filing was approved by the ACC in December 2016. Through December 2016, Southwest incurred approximately $4.1 million in capital expenditures toward the project (including land acquisition costs). Southwest included a proposal for the ratemaking treatment of facility costs as part of its current Arizona rate case filing; the draft settlement discussed in the section above includes an agreement to defer the revenue requirement associated with all costs incurred before December 31, 2020 for recovery in Southwest’s next general rate case

Southwest Gas Corporation 25

proceeding and extended the authorization to defer costs through the same date. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. Construction is expected to be completed by the end of 2019.

COYL Program.    Southwest received approval, in connection with its previous Arizona general rate case, to implement a program to conduct leak surveys, and if leaks were present, to replace and relocate service lines and meters for Arizona customers whose meters were set off from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously responsible for the cost of maintaining these lines and were subject to the immediate cessation of natural gas service if low-pressure leaks occurred. Effective June 2013, the ACC authorized a surcharge to recover the costs of depreciation and pre-tax return on the costs incurred to replace and relocate service lines and meters. The surcharge is revised annually as the program progresses. In 2014, Southwest received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. In the most recent annual COYL filing made in February 2016, Southwest requested to increase the annual surcharge revenue from $2.5 million to $3.7 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total capital expenditures of $23.1 million, $13.4 million of which was incurred during 2014 and 2015. In May 2016, the ACC issued a decision approving the surcharge application, effective in June 2016.

Federal Energy Regulatory Commission (“FERC”) Jurisdiction

General Rate Case.    Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary of Southwest, filed a general rate case with the FERC in February 2014. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case, and in February 2015, the FERC approved the settlement. Tariff changes in compliance with the settlement were filed in March 2015. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement resulted in an annual revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. The settlement implied an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed to file a rate case no later than May 2019. No filing in advance of the date required is currently contemplated.

Elko County Expansion Project.    Paiute previously requested to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area, in order to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. In May 2015, the FERC issued an order authorizing a Certificate of Public Convenience and Necessity to Paiute to construct and operate the Elko County Expansion Project, and subsequently provided a formal Notice to Proceed. Construction began in the second quarter of 2015 and the project was placed in service in January 2016 as authorized by the FERC. Rates to begin recovering the cost of the project were implemented in January 2016 and are designed to result in $6 million in revenue annually. As of December 31, 2016, costs incurred were approximately $35 million and costs associated with remaining site restoration along the construction corridor are estimated at less than $1 million.

2018 Expansion.    In response to growing demand in the Carson City and South Lake Tahoe areas of northern California and northern Nevada, Paiute evaluated shipper interest in acquiring additional transportation capacity and executed precedent agreements for incremental transportation capacity with Southwest during the third quarter of 2016. In October 2016, Paiute initiated a pre-filing review process with the FERC for an expansion project, which was approved during the same month. The project is anticipated to consist of 8.4 miles of additional transmission pipeline infrastructure at an approximate cost of $17 million. A formal certificate application is

Southwest Gas Corporation 26

expected to be filed in mid-2017, at which time, an environmental assessment will also be facilitated. If the process progresses as planned, the additional facilities could be in place by the end of 2018.

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 December 31, 2016, under-collections in California resulted in an asset of $2.6 million, and over-collections in Arizona and northern and southern Nevada collectively resulted in a liability of $90.5 million on Southwest’s balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during 2016, resulting in additional over-recoveries since December 31, 2015. Despite surcredits in place during 2016, the lower cost of natural gas resulted in PGA payables existing at December 31, 2016. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual Consolidated Statements of Income components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

Southwest had the following outstanding PGA balances receivable/(payable) at the end of its two most recent fiscal years (millions of dollars):

	2016			2015
Arizona	$	(20,349	)	$	(3,537	)
Northern Nevada		(3,339	)		(2,311	)
Southern Nevada		(66,788	)		(39,753	)
California		2,608			3,591
	$	(87,868	)	$	(42,010	)

Arizona PGA Filings.    In Arizona, Southwest calculates the change in the gas cost component of customer rates, which are updated monthly, utilizing a rolling twelve-month average. In May 2014, Southwest filed an application to provide for monthly adjustments to the surcharge component of the Gas Cost Balancing Account to allow for more timely refunds to/recoveries from ratepayers, which was approved in July 2014. As part of this filing, the ACC also approved an initial surcharge component of $0.06 per therm effective August 2014. After this surcharge component was reduced during 2015, it was then eliminated in August 2015 as the receivable balance was fully collected. A surcredit was implemented in April 2016 to refund the over-collected balance, which has been adjusted monthly through December 2016.

California Gas Cost Filings.    In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments modeled in this fashion provide the timeliest recovery of gas costs in any Southwest jurisdiction and are designed to send appropriate pricing signals to customers.

Nevada Annual Rate Adjustment (“ARA”) Application.    In November 2016, Southwest filed to adjust its quarterly Deferred Energy Account Adjustment rate, which is based upon a twelve-month rolling average, in addition to requesting adjusted Base Tariff Energy rates, both of which were also approved effective January 2017. These new rates are intended to reduce the outstanding liability over a twelve-month period.

Southwest Gas Corporation 27

Gas Price Volatility Mitigation

Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and Swaps under its collective volatility mitigation programs for a portion (up to 25% in the Arizona and California jurisdictions) of its annual normal weather supply needs. For the 2016/2017 heating season, contracts contained in the fixed-price portion of the supply portfolio ranged from approximately $2.65 to approximately $4.15 per dekatherm. Southwest makes natural gas purchases not covered by fixed-price contracts under variable-price contracts with firm quantities, and on the spot market. The contract price for these contracts is determined at the beginning of each month to reflect that month’s published first-of-month index price. The contract price of commitments to purchase gas at daily market prices is based on a published daily price index. In either case, the index price is not published or known until the purchase period begins. In late 2013, Southwest suspended fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. Southwest evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.

Pipeline Safety Regulation

The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) is in the process of proposing a series of significant rulemakings that are expected to further transform the regulatory requirements for pipelines. In October 2016, PHMSA issued a final rule regarding expanding the use of excess flow valves in natural gas distribution systems. The new rule has an effective date of April 2017. Management continues to evaluate potential impacts of this regulation on its operations and customers. Management continues to monitor changing pipeline safety legislation and participates to the extent possible in developing associated mandates and reporting requirements. Additionally, it works with its state and federal commissions, where possible, to develop customer rates that are responsive to incremental costs of compliance. However, due to the timing of when rates are implemented in response to new requirements, and as additional rules are developed, compliance requirements could impact operating expenses and the timing and amount of capital expenditures.

Capital Resources and Liquidity

Over the past three years, cash on hand and cash flows from operations have generally provided the majority of cash used in investing activities (primarily construction expenditures and property additions). Certain pipe replacement work of Southwest was accelerated during these years to take advantage of bonus depreciation tax incentives and to fortify system integrity and reliability. During the same three-year period, the Company was able to establish long-term cost savings from debt refinancing and strategic debt redemptions. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs. In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (“PATH Act”) was enacted extending the 50% bonus depreciation tax deduction provided for by earlier legislation for qualified property acquired or constructed and placed in-service during 2015 (and additional years as noted below) as well as other tax deductions, credits, and incentives through 2016. See Bonus Depreciation for more information.

Cash Flows

Operating Cash Flows.    Cash flows provided by consolidated operating activities increased $51.2 million between 2016 and 2015. The improvement in operating cash flows included an increase in net income and benefits from depreciation and deferred income taxes as well as the impacts of working capital components overall. Additionally, new and updated surcharges for decoupling mechanisms, conservation and energy efficiency and gas

Southwest Gas Corporation 28

infrastructure programs improved cash flows during 2016. Refer to Results of Natural Gas Operations and Rates and Regulatory Proceedings.

Investing Cash Flows.    Cash used in consolidated investing activities increased $55.8 million in 2016 as compared to 2015. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by Centuri due to the increased replacement construction work of its customers, as well as the acquisition of ETTI in the construction services segment.

Financing Cash Flows.    Net cash used in consolidated financing activities increased $1 million between 2016 and 2015. Southwest issued $300 million in senior notes and redeemed approximately $125 million of IDRBs during the current period (see Note 7 – Long-Term Debt). It also temporarily paid down $145 million of amounts outstanding on the long-term portion, as well as $18 million of amounts outstanding on the short-term portion, of its credit and commercial paper facility during 2016. All other long-term debt issuance amounts and retirements of long-term debt during this period are attributable to Centuri’s borrowing and repayment activity. The Company issued stock under its Equity Shelf Program during 2015, but not in 2016. See Note 6 – Common Stock, and discussion below. Dividends paid increased in 2016 as compared to 2015 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding.

Capital requirements and resources 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.

2016 Construction Expenditures

During the three-year period ended December 31, 2016, total gas plant in service increased from $5.3 billion to $6.2 billion, or at an average annual rate of 6%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as Southwest set approximately 70,000 meters during the three-year period.

During 2016, construction expenditures for the natural gas operations segment were $457 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant to fortify system integrity and reliability. Cash flows from operating activities of Southwest were $507 million and provided approximately 94% 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, as needed, existing credit facilities.

2016 Financing Activity

The $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) were redeemed at par plus accrued interest in July 2016. In September 2016, the $24.9 million 2006A 4.75% fixed-rate IDRBs (originally due in 2036) were redeemed at par plus accrued interest. Subsequently, in January 2017, Southwest repaid in full $25 million of 7.59% medium-term notes at maturity.

In September 2016, $300 million in 3.8% Senior Notes were issued at a discount of 0.302%. The notes will mature in September 2046. A portion of the net proceeds were used to temporarily pay down amounts outstanding under the credit facility. The remaining net proceeds were used for general corporate purposes.

Southwest Gas Corporation 29

During 2016, approximately 105,000 shares of common stock collectively were issued through the Restricted Stock/Unit Plan, the Management Incentive Plan, and the Stock Incentive Plan. Approximately $735,000 was raised from the issuance of shares of common stock through the Stock Incentive Plan.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Management estimates natural gas segment construction expenditures during the three-year period ending December 31, 2019 will be between $1.6 billion and $1.8 billion. Of this amount, approximately $570 million is expected to be incurred in 2017. Southwest plans to continue, as appropriate, to request regulatory support to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). This includes the recent approval in Nevada to complete $57.3 million in accelerated replacement projects in Nevada in 2017 as well as programs included in the current Arizona general rate case draft settlement (approval of the continuation of the COYL program and implementation of a vintage steel pipe replacement program) to expand existing or initiate new programs. If successful, significant replacement activities are expected to continue well beyond the next few years. See also Rates and Regulatory Proceedings for discussion of Nevada infrastructure, Arizona COYL, and an LNG facility. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 60% to 70% of the funding for the gas operations total construction expenditures and dividend requirements of natural gas operations. 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 debt securities, bank and other short-term borrowings, and other forms of financing. See additional discussion in the Notes to our financial statements (specifically, Note 6 – Common Stock).

Liquidity

Liquidity refers to the ability of an enterprise to generate sufficient amounts of cash through its operating activities and external financings to meet its cash requirements. Several general factors (some of which are out of the control of management) 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, the ability to access and obtain capital from external sources, interest rates, changes in income tax laws, pension funding requirements, inflation, and the level of earnings. Natural gas prices and related gas cost recovery rates have historically had the most significant impact on liquidity.

On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses these mechanisms 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. During 2016, the PGA net payable (over-collected) balance increased from $42 million to $87.9 million at December 31, 2016. See PGA Filings for more information.

In March 2016, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020 and was extended to March 2021. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. The maximum amount outstanding during 2016 occurred during the third quarter and was $230 million ($150 million outstanding on the long-term portion of the credit facility, including $50 million on the commercial paper program, in addition to $80 million outstanding on the short-term portion). At December 31, 2016, $5 million

Southwest Gas Corporation 30

was outstanding on the long-term portion of the credit facility (none of which was in commercial paper), and no borrowings were outstanding on the short-term portion. The maximum amount outstanding on the credit facility (including the commercial paper program) during each of the first, second, and fourth quarters was $68 million, $5 million, and $9 million, respectively. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, meeting the refund needs of over-collected balances, or temporarily funding capital expenditures. At December 31, 2016, the credit facility was deemed adequate for working capital needs outside of funds raised through operations and other types of external financing.

Southwest has a $50 million commercial paper program as noted above. Any issuance under the commercial paper program is supported by the 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 then current commercial paper rate. At December 31, 2016, no borrowings were outstanding on the commercial paper program. The maximum outstanding on the program was $50 million in each of the first and third quarters. Other than the $25 million 7.59% medium-term notes, which were repaid upon maturity in January 2017, there are no other long-term debt maturities in 2017.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. The term loan facility portion had an initial limit of approximately $150 million, which was reached in 2014 and is in the process of being repaid. No further borrowing is permitted under this portion of the facility. The secured revolving credit facility portion also has a limit of $150 million; amounts borrowed and repaid under this portion of the facility are available to be re-borrowed. The maximum amount outstanding on the credit facility during 2016 was $198 million, which occurred in the third quarter, at which point $115 million was outstanding on the term loan facility. At December 31, 2016, $41.2 million was outstanding on the Centuri secured revolving credit facility. At December 31, 2016, there was approximately $95 million, net of letters of credit, available under the line of credit.

Credit Ratings

Credit ratings apply to debt securities such as bonds, notes, and other debt instruments and do not apply to equity securities such as common stock. Borrowing costs and the ability to raise funds are directly impacted by the credit ratings of the Company. Credit ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Credit ratings are important because long-term debt constitutes a significant portion of total capitalization. These credit ratings are a factor considered by lenders when determining the cost of future debt for both Southwest and Southwest Gas Holdings, Inc. (i.e., generally the better the rating, the lower the cost to borrow funds). The current unsecured long-term debt ratings of both companies are all considered investment grade.

The issuer credit rating for Southwest Gas Holdings, Inc. from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as assigned in December 2016. Southwest’s unsecured long-term debt rating from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as reaffirmed in December 2016. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal. The ratings from ‘AA’ to ‘CCC’ may be modified by the addition of a plus “+” or minus “-” sign to show relative standing within the major rating categories.

The issuer credit rating of Southwest Gas Holdings, Inc. from Moody’s Investors Service, Inc. (“Moody’s”) is Baa1 with a stable outlook as assigned in December 2016. Southwest Gas Corporation’s senior unsecured long-term

Southwest Gas Corporation 31

debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is A3 with a stable outlook as last affirmed in January 2016. Moody’s debt ratings range from Aaa (highest rating possible) to C (lowest quality, usually in default). Moody’s applies an A rating to obligations which are considered upper-medium grade obligations with low credit risk. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the A to indicate the approximate rank of a company within the range.

The long-term issuer default rating (“IDR”) of Southwest Gas Holdings, Inc. from Fitch Ratings (“Fitch”) is BBB+ (with a stable outlook) as assigned in December 2016. Southwest’s senior unsecured long-term debt rating from Fitch Ratings (“Fitch”) is A (with a stable outlook) as affirmed in December 2016. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of A indicates low default risk and a strong ability to pay financial commitments. The modifiers “+” or “-” may be appended to a rating to denote relative status within major rating categories.

A credit rating is not a recommendation to buy, sell, or hold a debt security, but is intended to provide an estimation of the relative level of credit risk of debt securities, and is subject to change or withdrawal at any time by the rating agency. The foregoing credit ratings are subject to change at any time in the discretion of the applicable ratings agency. Numerous factors, including many that are not within management’s control, are considered by the ratings agencies in connection with assigning credit ratings.

No debt instruments have credit triggers or other clauses that result in default if these bond ratings are lowered by rating agencies. Certain debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs if debt ratings deteriorated. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2016, the Company is in compliance with all covenants. Under the most restrictive of the covenants, approximately $2.3 billion in additional debt could be issued and the leverage ratio requirement would still be met. At least $1.1 billion of cushion in equity relating to the minimum net worth requirement exists at December 31, 2016.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $145 million in additional debt and meet the leverage ratio requirement. Centuri has at least $21 million of cushion relating to the minimum fixed charge ratio coverage requirement. Centuri’s revolving credit and term loan facility is secured by underlying assets of the construction services segment.

Bonus Depreciation

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (“PATH Act”) was enacted, extending the 50% bonus depreciation tax deduction for qualified property acquired or constructed and placed in-service during 2015 (and additional years as noted below) as well as other tax deductions, credits, and incentives. The bonus depreciation tax deduction will be phased out over five years. The PATH Act provides for a 50% bonus depreciation tax deduction in 2015 through 2017, 40% in 2018, 30% in 2019, and no bonus deduction after 2019. Management estimates the bonus depreciation provision of the PATH Act will defer the payment of more than $60 million of federal income taxes for 2016. The actual amount will be dependent upon the ultimate level of qualifying expenditures. The foregoing does not contemplate any further changes not already enacted.

Inflation

Inflation can impact results of operations. Natural gas, labor, employee benefits, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to the cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor and employee benefits are

Southwest Gas Corporation 32

components of the cost of service, and gas infrastructure costs are the primary component of utility rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.

Off-Balance Sheet Arrangements

All debt is recorded in the balance sheet. Long-term operating and capital leases are described in Note 2 – Utility Plantand Leases of the Notes to Consolidated Financial Statements, and included in the Contractual Obligations table below.

Contractual Obligations

The table below summarizes the Company’s contractual obligations at December 31, 2016 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2017		2018-2019		2020-2021		Thereafter
Operating leases (Note 2)	$	21	$	7	$	8	$	4	$	2
Gas purchase obligations		155		108		46		1		—
Pipeline capacity/storage		1,117		137		192		150		638
Other commitments		22		12		10		—		—
Long-term debt, including current maturities (Note 7)		1,600		50		159		142		1,249
Interest on long-term debt		1,088		65		129		114		780
Capital leases (Note 2)		2		1		1		—		—
Total	$	4,005	$	380	$	545	$	411	$	2,669

In the table above, operating leases represent multi-year obligations for office rent and certain equipment. Gas purchase obligations include fixed-price and variable-rate gas purchase contracts covering approximately 155 million dekatherms. The fixed-price contracts range in price from approximately $2.65 to approximately $4.15 per dekatherm. Variable-price contracts reflect minimum contractual obligations, with estimation in pricing.

Southwest has pipeline capacity/storage contracts for firm transportation service, both on a short- and long-term basis, with several companies for all of its service territories, some with terms extending to 2044. Southwest also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise. Costs associated with these pipeline capacity contracts are a component of the cost of gas sold and are recovered from customers primarily through the PGA mechanisms. Included in the pipeline capacity payments shown in the above table, are payments associated with storage that Southwest has contracted for in southern California and Arizona. The terms of these contracts extend through 2024 and 2019, respectively.

Debt obligations in the table above consist of scheduled principal and interest payments over the life of the debt. Capital leases represent multi-year obligations for equipment. Interest rates in effect at December 31, 2016 on variable rate long-term debt were assumed to remain in effect in the future periods disclosed in the table.

Pension:     Estimated funding for pension and other postretirement benefits during calendar year 2017 is $39 million and is not included in the table above.

Southwest Gas Corporation 33

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition, recognition and measurement of financial instruments, leases, stock compensation, measurement of credit losses, classification of certain cash receipts and cash payments in the cash flow statement, accounting for income taxes relating to intra-entity asset transfers other than inventory, consolidation of a variable interest entity involving related parties under common control, and simplifying the test for goodwill impairment. See Note 1 – Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on financial position, results of operations, and disclosures.

Application of Critical Accounting Policies

A critical accounting policy is one which is very important to the portrayal of the financial condition and results of a company, and requires the most difficult, subjective, or complex judgments of management. The need to make estimates about the effect of items that are uncertain is what makes these judgments difficult, subjective, and/or complex. Management makes subjective judgments about the accounting and regulatory treatment of many items and bases its estimates on historical experience and on various other assumptions that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained, and as the operating environment changes. While management may make many estimates and judgments, many would not be materially altered, or provide a material impact to the financial statements taken as a whole, if different estimates, or means of estimation were employed. The following are accounting policies that are deemed critical to the financial statements. For more information regarding significant accounting policies, see Note 1—Summary of Significant Accounting Policies.

Regulatory Accounting

Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated entities and reflect the effects of the ratemaking process. As such, the Company is allowed to defer as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. It is also permitted to recognize, in its regulatory assets, amounts associated with its various revenue decoupling mechanisms, as long as it continues to meet the requirements of alternative revenue programs permitted under U.S. Generally Accepted Accounting Principles. Management reviews the regulatory assets to assess their ultimate recoverability within the approved regulatory guidelines. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset (which would be recognized as current-period expense). Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.

Accrued Utility Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, operating margin associated with natural gas service that has been provided but not yet billed is accrued. This accrued utility revenue is estimated each month based primarily on applicable rates, number of customers, rate structure,

Southwest Gas Corporation 34

analyses reflecting significant historical trends, seasonality, and experience. The interplay of these assumptions can impact the variability of the accrued utility revenue estimates. All Southwest rate jurisdictions have decoupled rate structures, limiting variability due to extreme weather conditions.

Accounting for Income Taxes

The Company is subject to income taxes in the United States and Canada. Income tax calculations require estimates due to known future tax rate changes, book to tax differences, and uncertainty with respect to regulatory treatment of certain property items. The asset and liability method of accounting is utilized for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Regulatory tax assets and liabilities are recorded to the extent management believes they will be recoverable from or refunded to customers in future rates. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Management regularly assesses financial statement tax provisions to identify any change in the regulatory treatment or tax-related estimates, assumptions, or enacted tax rates that could have a material impact on cash flows, financial position, and/or results of operations.

Accounting for Pensions and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, there is a separate unfunded supplemental retirement plan which is limited to officers. Pension obligations and costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans. For example, a change of 0.25% in the discount rate assumption would change the pension plan projected benefit obligation by approximately $36.3 million and future pension expense by $3.6 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.0 million and expense by $1.5 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.9 million (but has no impact on the pension obligation).

At December 31, 2016, the discount rate is 4.50%, the same as at December 31, 2015. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation remains at 3.25%. The asset return assumption of 7.00% to be used for 2017 expense was lowered from the 7.25% rate used for 2016. Pension expense for 2017 is estimated to be similar to that experienced in 2016. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Certifications

The Securities and Exchange Commission (“SEC”) requires the filing of certifications of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of registrants regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to periodic filings. The CEO and CFO certifications for the period ended December 31, 2016 are included as exhibits to the 2016 Annual Report on Form 10-K filed with the SEC.

Southwest Gas Corporation 35

Forward-Looking Statements

This annual 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 annual report are forward-looking statements, including, without limitation, statements regarding management’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote,” “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest savings, replacement market and new construction market, bonus depreciation tax deductions and future changes not yet enacted, amount and timing for completion of estimated future construction expenditures, including the LNG facility in southern Arizona and the cost of the Paiute 2018 expansion, forecasted operating cash flows and results of operations, net earnings impacts from gas infrastructure replacement surcharges, funding sources of cash requirements, amounts generally expected to be reflected in 2017 or future period revenues from regulatory rate proceedings, approval of the Arizona general rate case settlement and effective date of new general rates, PTY rate adjustments and the extension request including period for the next California general rate case, ARA rates and other surcharges, Nevada Conservation and Energy Efficiency programs, PGA, and other rate adjustments, sufficiency of working capital and current credit facilities, bank lending practices, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, future Centuri operating revenues, operating income, amortization and interest expense, pension and post-retirement benefits, certain benefits of tax acts, the effect of any rate changes or regulatory proceedings, effective dates of pipeline regulations, infrastructure replacement mechanisms and COYL programs, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, the impact of certain legal proceedings, the expectation that goodwill assigned to ETTI will be deductible for tax purposes, 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 could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, variability in volume of gas or transportation service sold to customers, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, our continued ability to meet consignment and purchase requirements under Cap and Trade regulations, results of Centuri bid work, Centuri construction expenses, differences between actual and originally expected outcomes of Centuri bid or other fixed-price construction agreements, and ability to successfully procure new work, acquisitions and management’s plans related thereto, competition, our ability to raise capital in external financings, our ability to continue to remain within the ratios and other limits subject to our debt covenants, and ongoing evaluations in regard to goodwill and other intangible assets. In addition, management 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 business risks, see Item 1A. Risk

Southwest Gas Corporation 36

Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Annual Report on Form 10-K for the year ended December 31, 2016.

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

Common Stock Price and Dividend Information

	2016				2015				Dividends Declared
	High		Low		High		Low		2016		2015
First quarter	$	67.29	$	53.51	$	63.68	$	52.94	$	0.450	$	0.405
Second quarter		79.43		62.75		59.75		51.69		0.450		0.405
Third quarter		79.58		67.97		58.40		51.26		0.450		0.405
Fourth quarter		76.64		64.35		62.56		50.78		0.450		0.405
									$	1.800	$	1.620

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2017, there were 13,488 holders of record of common stock, and the market price of the common stock was $82.93.

Dividends are payable on the Company’s common stock at the discretion of the Board of Directors (“Board”). In setting the dividend rate, the Board considers, among other factors, current and expected future earnings levels, our ongoing capital expenditure plans and expected external funding needs, our payout ratio, and our ability to maintain strong credit ratings and liquidity. The quarterly common stock dividend declared was 36.5 cents per share throughout 2014, 40.5 cents per share throughout 2015, and 45 cents per share throughout 2016. The Company has paid dividends on its common stock since 1956 and has increased that dividend each year since 2007. In February 2017, the Board elected to increase the quarterly dividend from $0.45 to $0.495 per share, representing a 10% increase, effective with the June 2017 payment. The Board currently targets a payout ratio of 55% to 65% of consolidated earnings per share.

Southwest Gas Corporation 37

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

December 31,	2016			2015
ASSETS
Utility plant:
Gas plant	$	6,193,564		$	5,854,917
Less: accumulated depreciation		(2,172,966	)		(2,084,007	)
Acquisition adjustments, net		196			370
Construction work in progress		111,177			119,805
Net utility plant (Note 2)		4,131,971			3,891,085
Other property and investments (Note 1)		342,343			313,531
Current assets:
Cash and cash equivalents		28,066			35,997
Accounts receivable, net of allowances (Note 3)		285,145			314,512
Accrued utility revenue		76,200			74,700
Income taxes receivable, net		4,455			34,175
Deferred purchased gas costs (Note 4)		2,608			3,591
Prepaids and other current assets (Notes 1, 4, and 13)		136,833			95,199
Total current assets		533,307			558,174
Noncurrent assets:
Goodwill (Note 1)		139,983			126,145
Deferred income taxes (Note 12)		1,288			428
Deferred charges and other assets (Notes 2, 4, and 13)		432,234			469,322
Total noncurrent assets		573,505			595,895
Total assets	$	5,581,126		$	5,358,685

Southwest Gas Corporation 38

CONSOLIDATED BALANCE SHEETS – Continued

December 31,	2016			2015
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized – 60,000,000 shares; issued and outstanding – 47,482,068 and 47,377,575 shares) (Note 11)	$	49,112		$	49,007
Additional paid-in capital		903,123			896,448
Accumulated other comprehensive income (loss), net (Note 5)		(48,008	)		(50,268	)
Retained earnings		759,263			699,221
Total Southwest Gas Corporation equity		1,663,490			1,594,408
Noncontrolling interest		(2,217	)		(2,083	)
Total equity		1,661,273			1,592,325
Redeemable noncontrolling interest (Note 16)		22,590			16,108
Long-term debt, less current maturities (Note 7)		1,549,983			1,551,204
Total capitalization		3,233,846			3,159,637
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		50,101			19,475
Short-term debt (Note 8)		—			18,000
Accounts payable		184,669			164,857
Customer deposits		72,296			72,631
Income taxes payable, net		1,909			940
Accrued general taxes		42,921			47,337
Accrued interest		17,939			16,173
Deferred purchased gas costs (Note 4)		90,476			45,601
Other current liabilities (Notes 2, 4, and 13)		168,064			150,031
Total current liabilities		628,375			535,045
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 12)		840,653			769,445
Accumulated removal costs (Note 4)		308,000			303,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 10, and 13)		570,252			591,558
Total deferred income taxes and other credits		1,718,905			1,664,003
Total capitalization and liabilities	$	5,581,126		$	5,358,685

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 39

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

Year Ended December 31,	2016			2015			2014
Operating revenues:
Gas operating revenues	$	1,321,412		$	1,454,639		$	1,382,087
Construction revenues		1,139,078			1,008,986			739,620
Total operating revenues		2,460,490			2,463,625			2,121,707
Operating expenses:
Net cost of gas sold		397,121			563,809			505,356
Operations and maintenance		401,724			393,199			383,732
Depreciation and amortization		289,132			270,111			253,027
Taxes other than income taxes		52,376			49,393			47,252
Construction expenses		1,024,423			898,781			647,857
Total operating expenses		2,164,776			2,175,293			1,837,224
Operating income		295,714			288,332			284,483
Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(73,660	)		(71,879	)		(72,069	)
Other income (deductions)		9,469			2,879			7,107
Total other income and (expenses)		(64,191	)		(69,000	)		(64,962	)
Income before income taxes		231,523			219,332			219,521
Income tax expense (Note 12)		78,468			79,902			78,373
Net income		153,055			139,430			141,148
Net income (loss) attributable to noncontrolling interests		1,014			1,113			22
Net income attributable to Southwest Gas Corporation	$	152,041		$	138,317		$	141,126
Basic earnings per share (Notes 1 and 15)	$	3.20		$	2.94		$	3.04
Diluted earnings per share (Notes 1 and 15)	$	3.18		$	2.92		$	3.01
Average number of common shares outstanding		47,469			46,992			46,494
Average shares outstanding (assuming dilution)		47,814			47,383			46,944

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 40

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

Year Ended December 31,	2016			2015			2014
Net Income	$	153,055		$	139,430		$	141,148
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)		(14,118	)		(18,922	)		(107,661	)
Amortization of prior service cost		828			828			220
Amortization of net actuarial loss		16,781			21,316			14,667
Prior service cost		—			—			(4,130	)
Regulatory adjustment		(3,462	)		(3,500	)		86,991
Net defined benefit pension plans		29			(278	)		(9,913	)
Forward-starting interest rate swaps:
Amounts reclassified into net income (Notes 5 and 13)		2,075			2,073			2,073
Net forward-starting interest rate swaps		2,075			2,073			2,073
Foreign currency translation adjustments		161			(1,954	)		(659	)
Total other comprehensive income (loss), net of tax		2,265			(159	)		(8,499	)
Comprehensive income		155,320			139,271			132,649
Comprehensive income (loss) attributable to noncontrolling interests		1,019			1,047			—
Comprehensive income attributable to Southwest Gas Corporation	$	154,301		$	138,224		$	132,649

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 41

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

Year Ended December 31,	2016			2015			2014
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	153,055		$	139,430		$	141,148
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		289,132			270,111			253,027
Deferred income taxes		68,732			48,785			64,309
Changes in current assets and liabilities:
Accounts receivable, net of allowances		30,096			(39,850	)		(3,683	)
Accrued utility revenue		(1,500	)		(800	)		(1,200	)
Deferred purchased gas costs		45,858			129,566			(69,339	)
Accounts payable		21,695			(3,491	)		(41,499	)
Accrued taxes		26,340			(8,405	)		(13,573	)
Other current assets and liabilities		(29,551	)		18,300			23,379
Gains on sale		(7,148	)		(3,102	)		(6,171	)
Changes in undistributed stock compensation		5,456			2,914			7,973
AFUDC		(2,289	)		(3,008	)		(1,995	)
Changes in other assets and deferred charges		16,960			(14,166	)		(21,732	)
Changes in other liabilities and deferred credits		(18,447	)		10,863			15,779
Net cash provided by operating activities		598,389			547,147			346,423

Southwest Gas Corporation 42

CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued

Year Ended December 31,	2016			2015			2014
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(529,531	)		(488,000	)		(396,898	)
Acquisition of businesses, net of cash acquired		(17,000	)		(9,261	)		(190,497	)
Restricted cash		—			785			1,233
Changes in customer advances		7,900			18,300			20,363
Miscellaneous inflows		13,039			8,354			11,611
Miscellaneous outflows		—			—			(1,400	)
Net cash used in investing activities		(525,592	)		(469,822	)		(555,588	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		472			35,396			405
Dividends paid		(83,317	)		(74,248	)		(66,275	)
Centuri distribution to redeemable noncontrolling interest		(439	)		(99	)		—
Issuance of long-term debt, net		423,946			135,816			269,228
Retirement of long-term debt		(255,273	)		(187,973	)		(139,155	)
Change in credit facility and commercial paper		(145,000	)		—			140,000
Change in short-term debt		(18,000	)		13,000			5,000
Principal payments on capital lease obligations		(1,354	)		(1,420	)		(434	)
Other		(1,569	)		41			(1,257	)
Net cash provided by (used in) financing activities		(80,534	)		(79,487	)		207,512
Effects of currency translation on cash and cash equivalents		(194	)		(1,407	)		142
Change in cash and cash equivalents		(7,931	)		(3,569	)		(1,511	)
Cash and cash equivalents at beginning of period		35,997			39,566			41,077
Cash and cash equivalents at end of period	$	28,066		$	35,997		$	39,566
Supplemental information:
Interest paid, net of amounts capitalized	$	67,440		$	66,623		$	65,552
Income taxes paid (received)	$	(19,032	)	$	43,225		$	24,247

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 43

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

AND REDEEMABLE NONCONTROLLING INTEREST

(In thousands, except per share amounts)

	Southwest Gas Corporation Equity
	Common Stock				Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
	Shares		Amount
DECEMBER 31, 2013		46,356	$	47,986	$	840,521	$	(41,698	)	$	567,714		$	(2,128	)	$	1,412,395		$	—
Common stock issuances		167		167		10,860											11,027
Redeemable noncontrolling interest attributable to acquisition																				18,952
Net income (loss)											141,126			(129	)		140,997			151
Redemption value adjustments (Note 16)											(961	)					(961	)		961
Foreign currency exchange translation adj.								(637	)								(637	)		(22	)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)								(9,913	)								(9,913	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)								2,073									2,073
Dividends declared
Common: $1.46 per share											(68,715	)					(68,715	)
DECEMBER 31, 2014		46,523		48,153		851,381		(50,175	)		639,164			(2,257	)		1,486,266			20,042
Common stock issuances		854		854		39,290											40,144
Net income (loss)											138,317			174			138,491			939
Redemption value adjustments (Note 16)						5,777					(1,069	)					4,708			(4,708	)
Foreign currency exchange translation adj.								(1,888	)								(1,888	)		(66	)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)								(278	)								(278	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)								2,073									2,073

Southwest Gas Corporation 44

CONSOLIDATED STATEMENTS OF EQUITY – Continued

	Southwest Gas Corporation Equity
	Common Stock					Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
	Shares			Amount
Centuri distribution to redeemable noncontrolling interest																					(99	)
Dividends declared
Common: $1.62 per share												(77,191	)					(77,191	)
DECEMBER 31, 2015		47,377			49,007		896,448		(50,268	)		699,221			(2,083	)		1,592,325			16,108
Common stock issuances		105			105		6,675											6,780
Net income (loss)												152,041			(134	)		151,907			1,148
Redemption value adjustments (Note 16)												(5,768	)					(5,768	)		5,768
Foreign currency exchange translation adj.									156									156			5
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)									29									29
Amounts reclassified to net income, net of tax (Notes 5 and 13)									2,075									2,075
Centuri distribution to redeemable noncontrolling interest																					(439	)
Dividends declared
Common: $1.80 per share												(86,231	)					(86,231	)
DECEMBER 31, 2016		47,482	*	$	49,112	$	903,123	$	(48,008	)	$	759,263		$	(2,217	)	$	1,661,273		$	22,590

* There are 3.8 million common shares registered and available for issuance under provisions of the various stock issuance plans.

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 45

Notes to Consolidated Financial Statements

Note 1—Summary of Significant Accounting Policies

Holding Company Reorganization.    In 2015, the Board of Directors (“Board”) of the Southwest Gas Corporation (“the Company”) authorized management to evaluate and pursue a holding company reorganization to provide further separation between regulated and unregulated businesses, and to provide additional financing flexibility. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company (Southwest Gas Holdings, Inc.); whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of such reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The Board approved the reorganization in December 2016 which became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016. Specific disclosures and references to Southwest Gas Holdings, Inc. (the “holding company”) give effect to events and conditions of the equity registrant/consolidated entity and its officers or directors after December 31, 2016.

Nature of Operations.    The Company consists of two segments: natural gas operations (“Southwest”) and construction services (Centuri). Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Centuri, a 96.6% owned subsidiary, is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operations occur in 20 major markets in the U.S. and within the Canadian provinces of British Columbia and Ontario, and are generally conducted under the business names of NPL Construction Co. (“NPL”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd.), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). In May 2016, Centuri completed the acquisition of two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”). ETTI is operated as part of Brigadier. See Acquisition of Construction Services Businesses below for more information. In January 2017, W.S. Nicholls began conducting business as WSN Fabrication, a division of NPL Canada Ltd.

Basis of Presentation.    The Company follows generally accepted accounting principles in the United States (“U.S. GAAP”) in accounting for all of its businesses. Unless specified otherwise, all amounts are in U.S. dollars. Accounting for natural gas utility operations conforms with U.S. GAAP as applied to rate-regulated companies and as prescribed by federal agencies and commissions of the various states in which the utility operates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and

Southwest Gas Corporation 46

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.

Consolidation.    The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries as of December 31, 2016 (except those accounted for using the equity method as discussed further below). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and Centuri in accordance with accounting treatment for rate-regulated entities.

Centuri, through its subsidiaries, holds a 65% interest in a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. Centuri consolidates the entity (IntelliChoice Energy, LLC).

Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The investment in Western totaled $10.8 million at December 31, 2015 and 2016. Both periods include the impacts of foreign currency exchange translation adjustments. Dividends of $500,000 were received from Western during 2016 with no impact on earnings. No dividends were received from Western in 2015. A management fee was paid by Western to its partners, including W.S. Nicholls, in accordance with underlying agreements. The equity method investment in Western is included in Other Property and Investments in the Consolidated Balance Sheets. Centuri’s maximum exposure to loss as a result of its involvement with Western is estimated at $35.8 million. The estimated maximum exposure to loss represents the maximum loss that would be absorbed by Centuri in the event that all of the assets of Western were deemed to be worthless. Centuri recorded earnings of $69,000 from this investment in 2016, which is included in Other Income (deductions) in the Consolidated Statements of Income.

In addition, Centuri, through its subsidiaries, has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture, which are also equity method investments.

Net Utility Plant.    Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction, less contributions in aid of construction.

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

	2016			2015
Centuri property, equipment, and intangibles	$	451,114		$	423,369
Centuri accumulated provision for depreciation and amortization		(228,374	)		(221,028	)
Net cash surrender value of COLI policies		106,744			99,276
Other property		12,859			11,914
Total	$	342,343		$	313,531

Deferred Purchased Gas Costs.    The various regulatory commissions have established procedures to enable Southwest to adjust its billing rates for changes in the cost of natural gas purchased. The difference between the

Southwest Gas Corporation 47

current cost of gas purchased and the cost of gas recovered in billed rates is deferred. Generally, these deferred amounts are recovered or refunded within one year.

Prepaids and other current assets.    Prepaids and other current assets includes gas pipe materials and operating supplies of $30 million in 2016 and $24 million in 2015 (carried at weighted average cost). Also included is natural gas stored underground and liquefied natural gas (both carried at weighted average cost), in addition to prepaid assets.

Income Taxes.    The asset and liability method of accounting is utilized for the recognition of income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. For regulatory and financial reporting purposes, investment tax credits (“ITC”) related to gas utility operations are deferred and amortized over the life of related fixed assets. As of December 31, 2016, the Company had cumulative earnings of approximately $5 million in its foreign jurisdiction. However, management intends to permanently reinvest any foreign earnings in Canada. See Note 12 – Income Taxes for further information.

Cash and Cash Equivalents.    For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents also includes money market fund investments totaling approximately $5.3 million and $250,000 at December 31, 2016 and 2015, respectively, which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

Significant non-cash investing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $6.5 million, $3.1 million, and $8.1 million during 2016, 2015, and 2014, respectively, were applied as contributions toward utility construction activity and represent non-cash investing activity. In 2014, investing activities included an $18.9 million non-cash investing outflow due to the equity of the noncontrolling interest associated with businesses acquired. In addition, a non-cash investing outflow activity of $10.8 million in 2014 related to acquisition consideration payable. This outflow activity was recorded in investing activities in 2015 as Acquisition of businesses, net of cash acquired.

Goodwill.    Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill may have occurred. The goodwill impairment analysis is conducted in the 4^th quarter each year and may start with an assessment of qualitative factors (Step 0) to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the qualitative factors, management determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or if management does not perform a qualitative assessment, a Step 1 impairment test will be performed. Management considered the qualitative factors and the evidence obtained and determined that it is not more likely than not that the fair value of our reporting units are less than their carrying amounts in either 2015 or 2016. Thus, no impairment was recorded in either year. One of the businesses associated with the ETTI acquisition in 2016 (further discussion below) was acquired via asset purchase. As a result, goodwill associated with ETTI is expected to be deductible for tax purposes.

Southwest Gas Corporation 48

	Natural Gas Operations		Construction Services		Consolidated
(In thousands of dollars)
December 31, 2015	$	10,095	$	116,050	$	126,145
Additional goodwill from ETTI acquisition		—		10,726		10,726
Foreign currency translation adjustment		—		3,112		3,112
December 31, 2016	$	10,095	$	129,888	$	139,983

Goodwill from the ETTI acquisition consists of the excess of purchase price over the fair value of the acquired net assets and represents the value of the assembled workforce and the estimated economic value attributable to future opportunities that will arise based on the strong financial performance of the combined entities.

Acquisition of Construction Services Businesses.    In May 2016, Centuri completed the acquisition of ETTI, which is based in Lisbon Falls, Maine, and has a primary focus on underground utility installation using horizontal directional drilling technology. The acquisition of ETTI will provide complementary operational support to, and be operated as part of, Brigadier, expanding operations into Maine. Neither the acquisition itself nor the impacts to assets and operations were material to the construction services segment or the Company at December 31, 2016.

Assets acquired in the transaction were recorded at their acquisition date fair values. The final purchase accounting is complete. The final estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):

	Acquisition Date
Property, plant and equipment	$	4.3
Intangible assets		2.9
Goodwill		10.7
Total assets acquired	$	17.9

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

Southwest Gas Corporation 49

Intangible Assets.    Intangible assets (other than goodwill) are amortized using the straight-line method to reflect the pattern of economic benefits consumed over the estimated periods benefited. The recoverability of intangible assets is evaluated when events or circumstances indicate that a revision of estimated useful lives is warranted or that an intangible asset may be impaired. Intangible assets are primarily associated with construction services businesses acquired in 2014 and have finite lives. Centuri has $37.7 million and $36.8 million of intangible assets (varies due to foreign currency translation) at December 31, 2016 and 2015, respectively, as detailed in the following table (thousands of dollars):

December 31, 2016	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	34,033	$	(3,906	)	$	30,127
Trade names and trademarks		9,349		(2,565	)		6,784
Customer contracts backlog		1,656		(1,656	)		—
Noncompete agreement		1,029		(271	)		758
Total	$	46,067	$	(8,398	)	$	37,669
December 31, 2015
Customer relationships	$	31,226	$	(2,070	)	$	29,156
Trade names and trademarks		8,621		(1,331	)		7,290
Customer contracts backlog		1,606		(1,606	)		—
Noncompete agreement		437		(110	)		327
Total	$	41,890	$	(5,117	)	$	36,773

The intangible assets (other than goodwill and software-related intangibles) are included in Other property and investments in the Consolidated Balance Sheets. The estimated future amortization of the intangible assets for the next five years is as follows (in thousands):

2017	$	3,339
2018		3,126
2019		2,463
2020		2,395
2021		2,269

See Note 2 – Utility Plant and Leases for additional information regarding natural gas operations intangible assets.

Accumulated Removal Costs.    Approved regulatory practices allow Southwest to include in depreciation expense a component to recover removal costs associated with utility plant retirements. In accordance with the Securities and Exchange Commission (“SEC”) position on presentation of these amounts, management reclassifies estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the Consolidated Balance Sheets. Amounts fluctuate between periods depending on the level of replacement work performed, the estimated cost of removal in rates and the actual cost of removal experienced.

Gas Operating Revenues.    Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs and state and local laws, regulations, and agreements. An estimate of the margin associated with natural gas service provided, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also

Southwest Gas Corporation 50

recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of unusual weather variability and conservation on margin.

The Company acts as an agent for state and local taxing authorities in the collection and remission of a variety of taxes, including sales and use taxes and surcharges. These taxes are not included in gas operating revenues. Management uses the net classification method to report taxes collected from customers to be remitted to governmental authorities.

Construction Revenues.    The majority of Centuri contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in a few weeks or less. Revenues are recorded as installations are completed. Long-term fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized on fixed-price contracts is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.

Construction Expenses.    The construction expenses classification in the income statement includes payroll expenses, office and equipment rental costs, subcontractor expenses, training, job-related materials, gains and losses on equipment sales, and professional fees of Centuri.

Net Cost of Gas Sold.    Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of natural gas derivative instruments. Also included are the net impacts of PGA deferrals and recoveries, which by their inclusion, result in net cost of gas sold overall that is comparable to amounts included in billed gas operating revenues. Differences between amounts incurred with suppliers, transmission pipelines, etc. and those already included in customer rates, are temporarily deferred in purchased gas adjustment accounts pending inclusion in customer rates.

Operations and Maintenance Expense.    For financial reporting purposes, operations and maintenance expense includes Southwest’s operating and maintenance costs associated with serving utility customers, uncollectible expense, administrative and general salaries and expense, employee benefits expense, and legal expense (including injuries and damages).

Depreciation and Amortization.    Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for removal costs (net of salvage value), and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. During the third quarter of 2016, Centuri evaluated the estimated useful lives of its depreciable assets, and in so doing determined that certain equipment lives should be extended. This change in estimate

Southwest Gas Corporation 51

reduced 2016 depreciation by approximately $4 million. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense. See also discussion regarding Accumulated Removal Costs above.

Allowance for Funds Used During Construction (“AFUDC”).    AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The debt portion of AFUDC is reported in the Consolidated Statements of Income as an offset to net interest deductions and the equity portion is reported as other income. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.

	2016			2015			2014
(In thousands)
AFUDC:
Debt portion	$	1,175		$	1,666		$	1,228
Equity portion		2,289			3,008			1,995
AFUDC capitalized as part of utility plant	$	3,464		$	4,674		$	3,223
AFUDC rate		7.35	%		7.32	%		7.73	%

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

	2016			2015			2014
Change in COLI policies	$	7,400		$	(500	)	$	5,300
Interest income		1,849			2,173			2,602
Equity AFUDC		2,289			3,008			1,995
Foreign currency transaction gain (loss)		(22	)		(824	)		(178	)
Equity in earnings of unconsolidated investment - Western		69			310			107
Miscellaneous income and (expense)		(2,116	)		(1,288	)		(2,719	)
Total other income (deductions)	$	9,469		$	2,879		$	7,107

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 the Company 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.

Foreign Currency Translation. Foreign currency-denominated assets and liabilities of consolidated subsidiaries are translated into U.S. dollars at exchange rates existing at the respective balance sheet dates. Translation adjustments resulting from fluctuations in exchange rates are recorded as a separate component of accumulated other comprehensive income within stockholders’ equity. Results of operations of foreign subsidiaries are translated using the monthly weighted-average exchange rates during the respective periods. Gains and losses resulting from foreign currency transactions are included in other income (expense). Gains and losses resulting

Southwest Gas Corporation 52

from intercompany foreign currency transactions that are of a long-term investment nature are reported in other comprehensive income, if applicable.

Earnings Per Share.    Basic earnings per share (“EPS”) in each period of this report were calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during those periods. Diluted EPS includes additional weighted-average common stock equivalents (stock options, performance shares, and restricted stock units). Unless otherwise noted, the term “Earnings Per Share” refers to Basic EPS. A reconciliation of the denominator used in the Basic and Diluted EPS calculations is shown in the following table.

	2016		2015		2014
(In thousands)
Average basic shares		47,469		46,992		46,494
Effect of dilutive securities:
Stock options		1		8		17
Performance shares		124		171		215
Restricted stock units		220		212		218
Average diluted shares		47,814		47,383		46,944

Recently Issued Accounting Standards Updates.    In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. In accordance with the update, an entity will be required to identify the contract with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. In July 2015, the FASB approved a one-year deferral of the effective date (annual periods beginning after December 15, 2017). In March, April, May, and December of 2016, the FASB issued updates to Topic 606 related to “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, “Identifying Performance Obligations and Licensing”, “Narrow-Scope Improvements and Practical Expedients”, and certain “Technical Corrections and Improvements”. The amendments in the first two updates, respectively, provide guidance when another party, along with the entity, is involved in providing a good or service to a customer, and provide clarification with regard to identifying performance obligations and of the licensing implementation guidance in Topic 606. The third update includes improvements to the guidance on collectability, noncash consideration, and completed contracts at transition. In addition, a practical expedient is provided for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The fourth update affects narrow aspects of the guidance as issued to date. The combined amendments do not change the core principles of the guidance in Topic 606. Management plans to adopt all of these updates at the required adoption date, which is for interim and annual reporting periods commencing January 2018.

Management has substantially completed the evaluation of the sources of revenue and are currently assessing the effect of the new guidance on the financial position, results of operations and cash flows. The assessment is contingent, in part, upon the completion of deliberations currently in progress by the utility industry, notably in

Southwest Gas Corporation 53

connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants (“AICPA”). In association with this undertaking, the AICPA formed a number of industry task forces, including a Power & Utilities (“P&U”) Task Force, on which Company personnel actively participate via formal membership. Industry representatives and organizations, the largest auditing firms, the AICPA’s Revenue Recognition Working Group and its Financial Reporting Executive Committee have undertaken, and continue to undertake, consideration of several items relevant to the utility industry. Where applicable or necessary, the FASB’s Transition Resource Group (TRG) is also participating. Currently, the industry is working to address several items including the evaluation of collectability from customers if a utility has regulatory mechanisms to help assure recovery of uncollected accounts from ratepayers and the accounting for funds received from third parties to partially or fully reimburse the cost of construction of an asset. Currently, a timeline for the resolution of these deliberations has not been established. Southwest is actively working with its peers in the rate-regulated natural gas industry and with the public accounting profession to conclude on the accounting treatment for several other issues that are not expected to be addressed by the P&U Task Force.

As of December 31, 2016, the construction services segment has substantially completed the evaluation of sources of revenue and is currently assessing the effect of the new guidance on financial position, results of operations and cash flows. The principals of the new revenue recognition guidance are very similar to existing guidance for construction contractors. Similar to the P&U Task Force noted above, the AICPA formed the Engineering and Construction Contractors Task Force to assist the construction industry with implementing the new guidance. The accounting guide the AICPA intends to release is expected to provide implementation guidance related to several issues including 1) combining contracts and separating performance obligations; 2) estimating change orders, incentives, penalties, liquidated damages and other variable consideration items and 3) acceptable measures of progress when recognizing revenue over time.

Given the uncertainty with respect to the conclusions that might arise from the deliberations on issues associated with both the natural gas and construction services segments, the Company is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, business processes, or the transition method it will utilize to adopt the new guidance.

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

Southwest Gas Corporation 54

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

• A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and

• A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Though companies have historically been required to make disclosures regarding leases and of contractual obligations, leases (with terms longer than a year) will no longer exist off-balance sheet. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. Early application is permitted. Management currently plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2019. Existing leases have been documented by both segments and management is in the process of determining if special software will be necessary to implement the standard. In addition, management is evaluating the potential impacts of various natural gas industry-related issues in light of the leasing standard. Given the uncertainty with respect to the conclusions that might arise from these deliberations, management is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, or business processes.

In March 2016, the FASB issued the update “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The update requires the recording of all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then recorded in the income statement. While the simplification will reduce some of the administrative complexities by eliminating the need to track a “windfall pool,” it will increase the volatility of income tax expense. The update also allows entities to withhold shares for the employee tax burden up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in a liability classification of the award (currently such withholding is limited to the employer’s minimum statutory withholding). The update clarifies that all cash payments made to taxing authorities on the employees’ behalf for withheld shares should be presented as financing activities on the statement of cash flows. Also, the update requires all tax-related cash flows resulting from share-based payments be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Management issues share-based payment awards to its employees. The update was adopted by management in January 2017.

In June 2016, the FASB issued the update “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. The update amends guidance on reporting credit losses for financial

Southwest Gas Corporation 55

assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, the update eliminates the “probable” threshold for initial recognition of credit losses in current U.S. GAAP and, instead, requires an entity to reflect its current estimate of all expected credit losses. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset to present the net amount expected to be collected. For available for sale debt securities, credit losses should be measured in a manner similar to current U.S. GAAP, however the update will require that credit losses be presented as an allowance rather than as a write-down. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The update affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. All entities may adopt the amendments in this update earlier as of fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

In August 2016, the FASB issued the update “Classification of Certain Cash Receipts and Cash Payments”. This update addresses the following specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance (“COLI”) policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows, including identification of the predominant nature in cases where cash receipts and payments have aspects of more than one class of cash flows. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Management is evaluating the impacts this update might have on its consolidated cash flow statements and disclosures.

In October 2016, the FASB issued the update “Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory.” This update eliminates the current U.S. GAAP exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted; however, the guidance can only be adopted in the first interim period of a fiscal year. The modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Management is evaluating the impacts this update might have on its consolidated financial statements.

In October 2016, the FASB issued the update “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” The amendments affect reporting entities that are required to evaluate whether they should consolidate a variable interest entity in certain situations involving entities under common control. The update is effective for fiscal and interim periods beginning after December 15, 2016. Management has determined that this update is not impactful to its consolidated financial statements.

Southwest Gas Corporation 56

In January 2017, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The update eliminates Step 2 from the goodwill impairment test. The annual, or interim, goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. In addition, income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit should be considered when measuring the goodwill impairment loss, if applicable. The update also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative test, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The amendments should be applied on a prospective basis. The update is effective for fiscal and interim periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Management has determined that this update would have had no impact on the consolidated financial statements for the periods presented if it had been effective during those periods.

Subsequent Events.    Management monitors events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued or disclosures to be made, and has reflected them where appropriate.

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2016 and 2015 was as follows (thousands of dollars):

December 31,	2016			2015
Gas plant:
Storage	$	24,614		$	22,944
Transmission		349,981			312,996
Distribution		5,198,531			4,935,730
General		382,084			365,865
Software and software-related intangibles		224,260			203,323
Other		14,094			14,059
		6,193,564			5,854,917
Less: accumulated depreciation		(2,172,966	)		(2,084,007	)
Acquisition adjustments, net		196			370
Construction work in progress		111,177			119,805
Net utility plant	$	4,131,971		$	3,891,085

Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for removal costs (net of salvage value), and retirements, based on the processes of regulatory proceedings and related regulatory commission approvals and/or mandates. In 2016, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2015 and 2014 also approximated 3.6%. Transmission and Distribution plant (combined), associated with our core natural gas delivery

Southwest Gas Corporation 57

infrastructure, constitute the majority of gas plant. Annual depreciation expense averaged approximately 3.3% of original cost of depreciable transmission and distribution plant during the period 2014 through 2016.

Depreciation and amortization expense on gas plant, including intangibles, was as follows (thousands of dollars):

	2016		2015		2014
Depreciation and amortization expense	$	214,037	$	201,233	$	194,360

Included in the figures above is amortization of intangibles of $14.8 million in 2016, $12.7 million in 2015, and $11.7 million in 2014.

Operating Leases and Rentals.    Certain office and construction equipment is leased. The majority of these leases are short-term and accounted for as operating leases. For the gas segment, these leases are also treated as operating leases for regulatory purposes. Centuri has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest’s rental payments and Centuri’s lease payments that are included in operating expenses (in thousands):

	2016		2015		2014
Southwest Gas	$	4,357	$	4,186	$	5,330
Centuri		53,956		45,849		30,012
Consolidated rental payments/lease expense	$	58,313	$	50,035	$	35,342

The following is a schedule of future minimum lease payments for significant non-cancelable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2016 (thousands of dollars):

Year Ending December 31,
2017	$	6,929
2018		4,837
2019		3,449
2020		2,411
2021		1,098
Thereafter		2,730
Total minimum lease payments	$	21,454

Capital Leases.    Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2016 and 2015 are as follows (thousands of dollars):

December 31,	2016			2015
Capital leased assets, gross	$	3,189		$	4,584
Less: accumulated amortization		(1,172	)		(1,043	)
Capital leased assets, net	$	2,017		$	3,541

Southwest Gas Corporation 58

The following is a schedule of future minimum lease payments for non-cancelable capital leases (with initial or remaining terms in excess of one year) as of December 31, 2016 (thousands of dollars):

Year Ending December 31,
2017	$	931
2018		546
2019		84
2020		—
2021		—
Thereafter		—
		1,561
Less: amount representing interest		(101	)
Total minimum lease payments	$	1,460

Note 3 – Receivables and Related Allowances

Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. The table below contains information about the gas utility customer accounts receivable balance (net of allowance) at December 31, 2016 and 2015, and the percentage of customers in each of the three states.

	December 31, 2016		December 31, 2015
Gas utility customer accounts receivable balance (in thousands)	$	111,320	$	151,775

	December 31, 2016
Percent of customers by state
Arizona		53	%
Nevada		37	%
California		10	%

Southwest Gas Corporation 59

Although Southwest seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Customer accounts are subject to collection procedures that vary by jurisdiction (late fee assessment, noticing requirements for disconnection of service, and procedures for actual disconnection and/or reestablishment of service). After disconnection of service, accounts are generally written off approximately one month after inactivation. Dependent upon the jurisdiction, reestablishment of service requires both payment of previously unpaid balances and additional deposit requirements. Provisions for uncollectible accounts are recorded monthly based on experience, customer and rate composition, and write-off processes. They are included in the ratemaking process as a cost of service. The Nevada jurisdictions have a regulatory mechanism associated with the gas cost-related portion of uncollectible accounts. Such amounts are deferred and collected through a surcharge in the ratemaking process. Activity in the allowance account for uncollectibles is summarized as follows (thousands of dollars):

	Allowance for Uncollectibles
Balance, December 31, 2013	$	1,725
Additions charged to expense		4,146
Accounts written off, less recoveries		(3,616	)
Balance, December 31, 2014		2,255
Additions charged to expense		4,113
Accounts written off, less recoveries		(4,098	)
Balance, December 31, 2015		2,270
Additions charged to expense		3,264
Accounts written off, less recoveries		(3,010	)
Balance, December 31, 2016	$	2,524

At December 31, 2016, the construction services segment (Centuri) had $173 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs related to Centuri customers have been insignificant and are not reflected in the table above.

Note 4 – Regulatory Assets and Liabilities

Southwest is subject to the regulation of the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”). Accounting policies of Southwest conform to U.S. GAAP applicable to rate-regulated entities and reflect the effects of the ratemaking process. Accounting treatment for rate-regulated entities allows for deferral as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

Southwest Gas Corporation 60

The following table represents existing regulatory assets and liabilities (thousands of dollars):

December 31,	2016			2015
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	379,063		$	384,647
Unrealized net loss on non-trading derivatives (Swaps) (2)		—			5,486
Deferred purchased gas costs (3)		2,608			3,591
Accrued purchased gas costs (4)		37,100			—
Unamortized premium on reacquired debt (5)		21,975			21,511
Accrued absence time (9)		13,440			13,240
Other (6)		23,557			59,782
		477,743			488,257
Regulatory liabilities:
Deferred purchased gas costs (3)		(90,476	)		(45,601	)
Accumulated removal costs		(308,000	)		(303,000	)
Accrued purchased gas costs (4)		—			(10,400	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		(4,377	)		—
Unamortized gain on reacquired debt (7)		(9,789	)		(10,325	)
Other (8)		(24,659	)		(36,631	)
Net regulatory assets	$	40,442		$	82,300

(1) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovery period is greater than five years. (See Note 10).

(2) The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the Consolidated Balance Sheets (thousands of dollars). The actual amounts, when realized at settlement, become a component of purchased gas costs under Southwest’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13).

Instrument	Balance Sheet Location	2016			2015
Swaps	Deferred charges and other assets	$	—		$	1,219
Swaps	Prepaids and other current assets		—			4,267
Swaps	Other current liabilities		(3,532	)		—
Swaps	Other deferred credits		(845	)		—

(3) Balance recovered or refunded on an ongoing basis with interest.

(4) Asset included in Prepaids and other current assets and liability included in Other current liabilities on the Consolidated Balance Sheets. Balance recovered or refunded on an ongoing basis.

(5) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovered over life of debt instruments.

Southwest Gas Corporation 61

(6) The following table details the components of Other regulatory assets which are included in either Prepaids and other current assets or Deferred charges and other assets on the Consolidated Balance Sheets (as indicated). Recovery periods vary. Margin tracking/decoupling mechanisms are alternative revenue programs and revenue associated with under-collections (for the difference between authorized margin levels and amounts billed to customers through rates currently) are recognized as revenue so long as recovery is expected to take place within 24 months.

Other Regulatory Assets	2016		2015
State mandated public purpose programs (including low income and conservation programs) (a) (f)	$	7,096	$	18,101
Margin and interest-tracking accounts (b) (f)		3,517		30,339
Infrastructure replacement programs and similar (c) (f)		6,976		6,947
Environmental compliance programs (d) (f)		4,329		2,300
Other (e)		1,639		2,095
	$	23,557	$	59,782

a) 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets; 2015 included in Deferred charges and other assets on the Consolidated Balance Sheets.

b) 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets; 2015 included in Prepaids and other current assets on the Consolidated Balance Sheets ($11 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($19.3 million).

c) Included in Deferred charges and other assets on the Consolidated Balance Sheets with the exception of $6,000 in 2016 that is included in Prepaids and other current assets on the Consolidated Balance Sheets.

d) 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets ($3.8 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($500,000); 2015 included in Prepaids and other current assets on the Consolidated Balance Sheets ($1.8 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($484,000).

e) 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets ($622,000) and Deferred charges and other assets on the Consolidated Balance Sheets ($1 million); 2015 included in Deferred charges and other assets on the Consolidated Balance Sheets.

f) Balance recovered or refunded on an ongoing basis, generally with interest.

(7) Included in Other deferred credits on the Consolidated Balance Sheets. Amortized over life of debt instruments.

(8) The following table details the components of Other regulatory liabilities which are included in either Other current liabilities or Deferred credits and other liabilities on the Consolidated Balance Sheets (as indicated).

Other Regulatory Liabilities	2016			2015
State mandated public purpose programs (including low income and conservation programs) (a) (d)	$	(7,101	)	$	(4,888	)
Margin and interest-tracking accounts (a) (d)		(3,668	)		(20,191	)
Environmental compliance programs (b) (d)		(4,469	)		(2,252	)
Regulatory offsets to deferred tax balances (c)		(3,390	)		(4,866	)
Regulatory accounts for differences related to pension funding (c)		(2,284	)		(1,363	)
Income tax and gross-up (c)		(3,203	)		(3,067	)
Other (d) (e)		(544	)		(4	)
	$	(24,659	)	$	(36,631	)

Southwest Gas Corporation 62

a) 2016 included in Other current liabilities on the Consolidated Balance Sheets; 2015 included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets.

b) Included in Other current liabilities on the Consolidated Balance Sheets.

c) Included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets.

d) Balance recovered or refunded on an ongoing basis, generally with interest.

e) 2016 included in Other current liabilities on the Consolidated Balance Sheets ($536,000) and in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets ($8,000); 2015 included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets.

(9) Regulatory recovery occurs on a one-year lag basis through the labor loading process.

Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income (“AOCI”)

The following information provides insight into amounts impacting Other Comprehensive Income (Loss), both before and after-tax, within the Consolidated Statements of Comprehensive Income, which also impact Accumulated Other Comprehensive Income in the Company’s Consolidated Balance Sheets and Consolidated Statements of Equity, as well as the Redeemable Noncontrolling Interest.

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

(Thousands of dollars)				2016									2015									2014
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(22,770	)	$	8,652		$	(14,118	)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)
Amortization of prior service cost		1,335			(507	)		828			1,335			(507	)		828			355			(135	)		220
Amortization of net actuarial (gain)/loss		27,066			(10,285	)		16,781			34,381			(13,065	)		21,316			23,656			(8,989	)		14,667
Prior service cost		—			—			—			—			—			—			(6,661	)		2,531			(4,130	)
Regulatory adjustment		(5,584	)		2,122			(3,462	)		(5,646	)		2,146			(3,500	)		140,308			(53,317	)		86,991
Pension plans other comprehensive income (loss)		47			(18	)		29			(449	)		171			(278	)		(15,988	)		6,075			(9,913	)
Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities):
Amounts reclassified into net income		3,345			(1,270	)		2,075			3,344			(1,271	)		2,073			3,345			(1,272	)		2,073
FSIRS other comprehensive income (loss)		3,345			(1,270	)		2,075			3,344			(1,271	)		2,073			3,345			(1,272	)		2,073
Foreign currency translation adjustments:
Translation adjustments		161			—			161			(1,954	)		—			(1,954	)		(659	)		—			(659	)
Foreign currency other comprehensive income (loss)		161			—			161			(1,954	)		—			(1,954	)		(659	)		—			(659	)
Total other comprehensive income (loss)	$	3,553		$	(1,288	)	$	2,265		$	941		$	(1,100	)	$	(159	)	$	(13,302	)	$	4,803		$	(8,499	)

(1) Tax amounts are calculated using a 38% rate. Management has elected to indefinitely reinvest the earnings of Centuri’s Canadian subsidiaries in Canada, thus preventing deferred taxes on such earnings. As a result of this assertion, management is not recognizing any tax effect or presenting a tax expense or benefit for the currency translation adjustment amount reported in Other Comprehensive Income, as repatriation of earnings is not anticipated.

Southwest Gas Corporation 63

The estimated amounts that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year are summarized below (in thousands):

Retirement plan net actuarial loss	$	24,000
SERP net actuarial loss		1,500
PBOP prior service cost		1,300

Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, included in AOCI at December 31, 2016, will be reclassified into interest expense within the next twelve months as the related interest payments on long-term debt occur.

The following table represents a rollforward of AOCI, presented on the Company’s Consolidated Balance Sheets and its Consolidated Statements of Equity:

AOCI—Rollforward

(Thousands of dollars)

	Defined Benefit Plans (Note 10)									FSIRS (Note 13)									Foreign Currency Items
	Before- Tax			Tax (Expense) Benefit (4)			After- Tax			Before- Tax			Tax (Expense) Benefit (4)			After- Tax			Before- Tax			Tax (Expense) Benefit		After- Tax			AOCI
Beginning Balance AOCI December 31, 2015	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)
Net actuarial gain/(loss)		(22,770	)		8,652			(14,118	)		—			—			—			—			—		—			(14,118	)
Translation adjustments		—			—			—			—			—			—			161			—		161			161
Other comprehensive income before reclassifications		(22,770	)		8,652			(14,118	)		—			—			—			161			—		161			(13,957	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,345			(1,270	)		2,075			—			—		—			2,075
Amortization of prior service cost (2)		1,335			(507	)		828			—			—			—			—			—		—			828
Amortization of net actuarial loss (2)		27,066			(10,285	)		16,781			—			—			—			—			—		—			16,781
Regulatory adjustment (3)		(5,584	)		2,122			(3,462	)		—			—			—			—			—		—			(3,462	)
Net current period other comprehensive income (loss)		47			(18	)		29			3,345			(1,270	)		2,075			161			—		161			2,265
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			5			—		5			5
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		47			(18	)		29			3,345			(1,270	)		2,075			156			—		156			2,260
Ending Balance AOCI December 31, 2016	$	(57,613	)	$	21,893		$	(35,720	)	$	(15,999	)	$	6,080		$	(9,919	)	$	(2,369	)	$	—	$	(2,369	)	$	(48,008	)

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

(2) These AOCI components are included in the computation of net periodic benefit cost (see Note 10 – Pension and Other Postretirement Benefits 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 Consolidated Balance Sheets).

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

Southwest Gas Corporation 64

The following table represents amounts (before income tax impacts) included in Accumulated other comprehensive income (in the table above), that have not yet been recognized in net periodic benefit cost as of December 31, 2016 and 2015:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2016			2015
Net actuarial (loss) gain	$	(430,973	)	$	(435,269	)
Prior service cost		(5,703	)		(7,038	)
Less: amount recognized in regulatory assets		379,063			384,647
Recognized in AOCI	$	(57,613	)	$	(57,660	)

See Note 10 – Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 13 – Derivatives and Fair Value Measurements for more information on the FSIRS.

Note 6 – Common Stock

On March 10, 2015, the Company filed with the Securities Exchange Commission (“SEC”) an automatic shelf registration statement on Form S-3 (File No. 333-202633), which became effective upon filing, for the offer and sale of up to $100,000,000 of common stock from time to time in at-the-market offerings under the prospectus included therein and in accordance with the Sales Agency Agreement, dated March 10, 2015, between the Company and BNY Mellon Capital Markets, LLC (the “Equity Shelf Program”). During the twelve months ended December 31, 2016, the Company sold no shares through the continuous equity offering program. Since the start of the program in March 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds of $35,167,584, net of $355,228 in agent commissions. Effective January 2017, no further shares will be issued under this registration statement.

During 2016, the Company issued approximately 105,000 shares of common stock through the Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan.

Note 7 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2016 and December 31, 2015 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, due to the Company’s ability to access similar debt arrangements at measurement dates with comparable terms, including variable rates. The fair values of debentures, senior notes, and fixed-rate IDRBs were determined utilizing a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves, credit ratings and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. The market values of

Southwest Gas Corporation 65

debentures and fixed-rate IDRBs are categorized as Level 2 (observable market inputs based on market prices of similar securities). The Centuri secured revolving credit and term loan facility and Centuri other debt obligations (not actively traded) are categorized as Level 3, based on significant unobservable inputs to their fair values. Since Centuri’s debt is not publicly traded, fair values for the secured revolving credit and term loan facility and other debt obligations were based on a conventional discounted cash flow methodology and utilized current market pricing yield curves, across Centuri’s debt maturity spectrum, of other industrial bonds with an assumed credit rating comparable to the Company’s.

December 31,	2016					2015
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	129,703	$	125,000		$	130,273
Notes, 6.1%, due 2041		125,000			149,734		125,000			141,581
Notes, 3.875%, due 2022		250,000			254,900		250,000			253,600
Notes, 4.875%, due 2043		250,000			266,793		250,000			251,483
Notes, 3.8%, due 2046		300,000			283,029		—			—
8% Series, due 2026		75,000			94,691		75,000			97,035
Medium-term notes, 7.59% series, due 2017		25,000			25,040		25,000			26,253
Medium-term notes, 7.78% series, due 2022		25,000			29,290		25,000			29,855
Medium-term notes, 7.92% series, due 2027		25,000			31,905		25,000			31,890
Medium-term notes, 6.76% series, due 2027		7,500			8,769		7,500			8,684
Unamortized discount and debt issuance costs		(9,931	)				(6,137	)
		1,197,569					901,363
Revolving credit facility and commercial paper		5,000			5,000		150,000			150,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
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:
4.85% 2005 Series A, due 2035		—			—		100,000			100,452
4.75% 2006 Series A, due 2036		—			—		24,855			25,130
Unamortized discount and debt issuance costs		(2,489	)				(3,946	)
		197,511					320,909
Centuri term loan facility		106,700			106,819		112,571			112,665
Unamortized debt issuance costs		(516	)				(692	)
		106,184					111,879
Centuri secured revolving credit facility		41,185			41,292		60,627			60,724
Centuri other debt obligations		52,635			52,840		25,901			26,059
		1,600,084					1,570,679
Less: current maturities		(50,101	)				(19,475	)
Long-term debt, less current maturities	$	1,549,983				$	1,551,204

Southwest Gas Corporation 66

In March 2016, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020, but was extended to March 2021. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At December 31, 2016, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2016, $5 million was outstanding on the long-term portion of the credit facility, none of which was in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 5.21% at December 31, 2016. Borrowings under the credit facility ranged from none at various times throughout 2016 to a high of $230 million during the third quarter of 2016. With regard to the short-term portion of the credit facility, there were no borrowings outstanding at December 31, 2016 and $18 million outstanding at December 31, 2015. (See Note 8 – Short-Term Debt).

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 program are calculated at the then current commercial paper rate. At December 31, 2016, and as noted above, no borrowings were outstanding under the commercial paper program.

Southwest redeemed its $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) at par with accrued interest in July 2016. In September 2016, Southwest redeemed its $24.9 million 2006 Series A 4.75% fixed-rate IDRBs (originally due in 2036) at par with accrued interest. In January 2017, subsequent to the most recent balance sheet date, the $25 million 7.59% medium-term notes were repaid at maturity, using available cash on hand.

In September 2016, Southwest issued $300 million in 3.8% Senior Notes at a discount of 0.302%. The notes will mature in September 2046. A portion of the net proceeds were used to temporarily pay down amounts then outstanding under the credit facility. The remaining net proceeds were used for general corporate purposes.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. This facility includes a revolving credit facility and a term loan facility. The term loan facility had an initial limit of approximately $150 million, which was reached in 2014 and is in the process of being repaid. No further borrowing is permitted under the term loan facility. The revolving credit facility has a limit of $150 million; amounts borrowed and repaid under the revolving credit facility are available to be re-borrowed. The revolving credit and term loan facility is secured by substantially all of Centuri’s assets except ones explicitly excluded under the terms of the agreement (including owned real estate and certain certificated vehicles). Centuri assets securing the facility at December 31, 2016 totaled $445 million.

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

Southwest Gas Corporation 67

a low of $36.2 million during February 2016 to a high of $83.2 million during July 2016. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.63% at December 31, 2016.

The effective interest rates on Southwest’s variable-rate IDRBs are included in the table below:

	December 31, 2016			December 31, 2015
2003 Series A		1.47	%		0.87	%
2008 Series A		1.53	%		0.87	%
2009 Series A		1.43	%		0.75	%
Tax-exempt Series A		1.51	%		0.81	%

In Nevada, interest fluctuations due to changing interest rates on Southwest’s 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.

None of Southwest’s debt instruments have credit triggers or other clauses that result in default if bond ratings are lowered by rating agencies. Certain debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2016, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, at December 31, 2016, approximately $2.3 billion in additional debt could be issued while still meeting the leverage ratio requirement. Relating to the minimum net worth requirement, as of December 31, 2016, there is at least $1.1 billion of cushion in equity.

Certain Centuri debt instruments also have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $145 million in additional debt and meet the leverage ratio requirement. Centuri has at least $21 million of cushion relating to the minimum fixed charge ratio coverage requirement.

Estimated maturities of long-term debt for the next five years are (in thousands):

2017	$	50,101
2018		24,082
2019		134,534
2020		134,452
2021		7,815

Note 8 – Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2021, of which $150 million has been designated by management for working capital purposes. Southwest had no short-term borrowings outstanding at December 31, 2016 and $18 million in short-term borrowings outstanding at December 31, 2015.

Note 9 – Commitments and Contingencies

The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the

Southwest Gas Corporation 68

opinion of management that no litigation or regulatory proceeding to which the Company is currently subject will have a material adverse impact on its financial position, results of operations, or cash flows.

Southwest maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, Southwest 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 2016 to July 2017, these liability insurance policies require Southwest to be responsible for the first $1 million (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. Through an assessment process, Southwest 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, Southwest will make an accrual, as necessary.

Note 10 – Pension and Other Postretirement Benefits

An Employees’ Investment Plan is offered to eligible employees of Southwest through deduction of a percentage of base compensation, subject to IRS limitations. The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock. One-half of amounts deferred by employees are matched, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. The cost of the plan is disclosed below (in thousands):

	2016		2015		2014
Employee Investment Plan cost	$	4,976	$	5,072	$	4,816

Centuri has a separate plan, the cost and liability of which are not significant.

A deferred compensation plan is offered to all officers and a separate deferred compensation plan for members of the Board of Directors. The plans provide the opportunity to defer up to 100% of annual cash compensation. One-half of amounts deferred by officers are matched, up to a maximum matching contribution of 3.5% of an officer’s annual base salary. Upon retirement, payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150% of Moody’s Seasoned Corporate Bond Rate Index.

A noncontributory qualified retirement plan with defined benefits covering substantially all Southwest employees is available in addition to a separate unfunded supplemental executive retirement plan (“SERP”) which is limited to officers. Postretirement benefits other than pensions (“PBOP”) are provided to qualified retirees for health care, dental, and life insurance benefits.

The overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, are recognized in the Consolidated Balance Sheets. Any actuarial gains and losses, prior service costs and transition assets or obligations are recognized in Accumulated other comprehensive income under Stockholders’ equity, net of tax, until they are amortized as a component of net periodic benefit cost.

A regulatory asset has been established for the portion of the total amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through rates in future periods. Changes in actuarial gains and losses and prior service costs pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are amortized and recognized as components of net periodic pension costs each year.

Southwest Gas Corporation 69

Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors of the Company. They are designed to enhance capital, maintain minimum liquidity required for retirement plan operations, manage funded status risk and effectively manage pension assets.

A target portfolio of investments in the qualified retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Asset return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. At December 31, 2016, the percentage ranges of the target portfolio are:

Type of Investment	Percentage Range
Equity securities		63 to 67
Debt securities		33 to 37
Other		up to 1

The qualified retirement plan invests the majority of its plan assets in common collective trusts which includes a well-diversified portfolio of domestic and international equity securities and fixed income securities, which are managed by a professional investment manager appointed by the Company. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the specific guidelines prescribed by the Company through the plan’s investment policy statement. In 2016, the Company adopted a liability driven investment (“LDI”) strategy for part of the portfolio, a form of investing designed to better match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the pension plan liability. The implementation of the LDI strategy will be phased in over time by using a glide path. The glide path is designed to increase the allocation of the plan’s assets to fixed income securities, as the funded status of the plan increases, in order to more closely match the duration of the plan assets to that of the plan liability.

During the third quarter of 2016, qualifying term-vested participants were offered a lump-sum present value payout of their pensions. The offer was primarily intended to reduce insurance and ongoing maintenance costs associated with qualifying participant balances. About one-half of the approximate 800 participants subject to the offer accepted the offer, resulting in an approximate $30 million payment from pension assets paid in the fourth quarter of 2016.

In August 2016, Russell Investments Trust Company (“Russell”), an outside professional investment manager as defined in Section 3(38) of ERISA, was engaged as a fiduciary of the pension plan. Russell has full discretionary authority to direct the investment of the pension plan’s assets within the guidelines prescribed by the pension plan’s investment policy statement. The change, related to managing pension plan assets, has no impact on retirement benefit calculations for pension plan participants, and was approved by the Board of Directors of the Company.

Pension plan assets are held in a Master Trust. Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of the obligations to the pension plan’s beneficiaries. To meet this objective, the pension plan assets are managed by an

Southwest Gas Corporation 70

outside adviser using a portfolio strategy that will provide liquidity to meet the plan’s benefit payment obligations. The pension plan funding policy is in compliance with the federal government’s funding requirements.

Pension costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan. In determining the discount rate, management matches the plan’s projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are generally made in increments of 25 basis points.

There was no change in the discount rate between years. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase also remained the same (consistent with management’s expectations overall). The asset return assumption (which impacts the following year’s expense) was lowered. The rates are presented in the table below:

	December 31, 2016			December 31, 2015
Discount rate		4.50	%		4.50	%
Weighted-average rate of compensation increase		3.25	%		3.25	%
Asset return assumption		7.00	%		7.25	%

Pension expense for 2017 is estimated to be similar to that experienced in 2016. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Southwest Gas Corporation 71

The following table sets forth the retirement plan, SERP, and PBOP funded statuses and amounts recognized on the Consolidated Balance Sheets and Consolidated Statements of Income.

	2016									2015
	Qualified Retirement Plan			SERP			PBOP			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Change in benefit obligations
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$	1,044,817		$	42,720		$	72,632		$	1,060,240		$	41,176		$	72,202
Service cost		22,833			331			1,499			25,123			320			1,641
Interest cost		46,027			1,859			3,180			44,229			1,695			2,999
Actuarial loss (gain)		8,550			1,347			(2,060	)		(44,553	)		2,322			(3,251	)
Benefits paid		(73,874	)		(2,946	)		(1,386	)		(40,222	)		(2,793	)		(959	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,048,353			43,311			73,865			1,044,817			42,720			72,632
Change in plan assets
Market value of plan assets at beginning of year		736,880			—			43,584			754,796			—			44,892
Actual return on plan assets		39,956			—			4,818			(13,694	)		—			(1,034	)
Employer contributions		36,000			2,946			—			36,000			2,793			—
Benefits paid		(73,874	)		(2,946	)		(289	)		(40,222	)		(2,793	)		(274	)
Market value of plan assets at end of year		738,962			—			48,113			736,880			—			43,584
Funded status at year end	$	(309,391	)	$	(43,311	)	$	(25,752	)	$	(307,937	)	$	(42,720	)	$	(29,048	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.50	%		4.50	%		4.50	%		4.50	%		4.50	%		4.50	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		N/A			3.25	%		3.25	%		N/A

Estimated funding for the plans above during calendar year 2017 is approximately $39 million, of which $36 million pertains to the retirement plan. Management monitors plan assets and liabilities and could, at its discretion, increase plan funding levels above the minimum in order to achieve a desired funded status and avoid or minimize potential benefit restrictions.

The accumulated benefit obligation for the retirement plan and the SERP is presented below (in thousands):

	December 31, 2016		December 31, 2015
Retirement plan	$	939,002	$	922,992
SERP		40,852		39,270

Southwest Gas Corporation 72

Benefits expected to be paid for pension, SERP, and PBOP over the next 10 years are as follows (in millions):

	2017		2018		2019		2020		2021		2022-2026
Pension	$	48.6	$	50.1	$	51.5	$	53.2	$	55.1	$	294.2
SERP		2.9		2.9		2.9		2.9		2.9		14.4
PBOP		4.1		4.3		4.4		4.5		4.5		20.6

No assurance can be made that actual funding and benefits paid will match these estimates.

For PBOP measurement purposes, the per capita cost of the covered health care benefits medical rate trend assumption is 7% declining to 4.5%. Fixed contributions are made for health care benefits of employees who retire after 1988, but Southwest pays all covered health care costs for employees who retired prior to 1989. The medical trend rate assumption noted above applies to the benefit obligations of pre-1989 retirees only.

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2016			2015			2014			2016			2015			2014			2016			2015			2014
(Thousands of dollars)
Service cost	$	22,833		$	25,123		$	21,360		$	331		$	320		$	292		$	1,499		$	1,641		$	1,101
Interest cost		46,027			44,229			43,440			1,859			1,695			1,745			3,180			2,999			2,829
Expected return on plan assets		(56,558	)		(57,808	)		(53,342	)		—			—			—			(3,149	)		(3,464	)		(3,264	)
Amortization of prior service cost		—			—			—			—			—			—			1,335			1,335			355
Amortization of net actuarial loss		25,266			32,743			22,873			1,383			1,293			783			417			345			—
Net periodic benefit cost	$	37,568		$	44,287		$	34,331		$	3,573		$	3,308		$	2,820		$	3,282		$	2,856		$	1,021
Weighted-average assumptions (net benefit cost)
Discount rate		4.50	%		4.25	%		5.00	%		4.50	%		4.25	%		5.00	%		4.50	%		4.25	%		5.00	%
Expected return on plan assets		7.25	%		7.75	%		7.75	%		N/A			N/A			N/A			7.25	%		7.75	%		7.75	%
Weighted-average rate of compensation increase		3.25	%		2.75	%		3.25	%		3.25	%		2.75	%		3.25	%		N/A			N/A			N/A

Southwest Gas Corporation 73

Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income

	2016												2015												2014
	Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)	$	22,770		$	25,153		$	1,347		$	(3,730	)	$	30,519		$	26,949		$	2,322		$	1,248		$	173,646		$	163,215		$	5,460		$	4,971
Amortization of prior service cost (b)		(1,335	)		—			—			(1,335	)		(1,335	)		—			—			(1,335	)		(355	)		—			—			(355	)
Amortization of net actuarial loss (b)		(27,066	)		(25,266	)		(1,383	)		(417	)		(34,381	)		(32,743	)		(1,293	)		(345	)		(23,656	)		(22,872	)		(784	)		—
Prior service cost		—			—			—			—			—			—			—			—			6,661			—			—			6,661
Regulatory adjustment		5,584			102			—			5,482			5,646			5,214			—			432			(140,308	)		(129,031	)		—			(11,277	)
Recognized in other comprehensive (income) loss		(47	)		(11	)		(36	)		—			449			(580	)		1,029			—			15,988			11,312			4,676			—
Net periodic benefit costs recognized in net income		44,423			37,568			3,573			3,282			50,451			44,287			3,308			2,856			38,172			34,331			2,820			1,021
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	44,376		$	37,557		$	3,537		$	3,282		$	50,900		$	43,707		$	4,337		$	2,856		$	54,160		$	45,643		$	7,496		$	1,021

The table above discloses the net gain or loss and prior service cost recognized in other comprehensive income, separated into (a) amounts initially recognized in other comprehensive income, and (b) amounts subsequently recognized as adjustments to other comprehensive income as those amounts are amortized as components of net periodic benefit cost.

See also Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income (“AOCI”).

U.S. GAAP states that a fair value measurement should be based on the assumptions that market participants would use in pricing the asset or liability and establishes a fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The three levels of the fair value hierarchy are as follows:

Level 1 – quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access at the measurement date.

Level 2 – inputs other than quoted prices included within Level 1 that are observable for similar assets or liabilities, either directly or indirectly.

Level 3 – unobservable inputs for the asset or liability. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

Southwest Gas Corporation 74

The following table sets forth, by level within the three-level fair value hierarchy, the fair values of the assets of the qualified pension plan and the PBOP as of December 31, 2016 and December 31, 2015. The change in the types of pension investment holdings between years is due to the engagement of Russell and the subsequent transition of pension investments to Russell funds. The transition efforts consolidated the majority of the pension plan investments into private commingled equity and fixed income funds. The SERP has no assets.

	December 31, 2016						December 31, 2015
	Qualified Retirement Plan		PBOP		Total		Qualified Retirement Plan			PBOP		Total
Assets at fair value (thousands of dollars):
Level 1 – Quoted prices in active markets for identical financial assets
Common stock
Agriculture	$	—	$	—	$	—	$	7,021		$	209	$	7,230
Capital equipment		—		—		—		533			16		549
Chemicals/materials		—		—		—		3,304			98		3,402
Consumer goods		—		—		—		41,035			1,221		42,256
Energy and mining		—		—		—		11,066			329		11,395
Finance/insurance		—		—		—		29,957			892		30,849
Healthcare		—		—		—		37,930			1,129		39,059
Information technology		—		—		—		29,229			870		30,099
Services		—		—		—		12,341			367		12,708
Telecommunications/internet/media		—		—		—		25,883			770		26,653
Other		—		—		—		9,043			269		9,312
Real estate investment trusts		—		—		—		5,010			149		5,159
Mutual funds		—		24,922		24,922		87,483			23,985		111,468
Government fixed income securities		—		—		—		33,482			996		34,478
Futures contracts		—		—		—		(7	)		—		(7	)
Total Level 1 Assets (1)	$	—	$	24,922	$	24,922	$	333,310		$	31,300	$	364,610
Level 2 – Significant other observable inputs
Private commingled equity funds (2)
International	$	290,668	$	9,140	$	299,808	$	—		$	—	$	—
Large and medium capitalization		121,434		3,819		125,253		—			—		—
Small capitalization		25,947		816		26,763		—			—		—
Emerging markets		45,309		1,424		46,733		—			—		—
Private commingled fixed income funds (3)
U.S. corporate bonds		161,086		5,066		166,152		—			—		—
U.S. debt market long duration		77,349		2,432		79,781		—			—		—
U.S. Treasury securities		8,665		272		8,937		—			—		—
Pooled funds and mutual funds		4,889		216		5,105		14,808			796		15,604
Government fixed income and mortgage backed securities		167		5		172		49,571			1,475		51,046
Corporate fixed income securities
Asset-backed and mortgage-backed		—		—		—		23,542			701		24,243
Banking		—		—		—		20,857			621		21,478
Insurance		—		—		—		4,896			146		5,042
Utilities		—		—		—		3,826			114		3,940
Other		—		—		—		30,995			922		31,917
Real estate investment trusts		—		—		—		1,949			58		2,007
State and local obligations		—		—		—		950			28		978
Preferred securities		—		—		—		554			17		571
Convertible securities		—		—		—		196			6		202
Total Level 2 assets (4)	$	735,514	$	23,190	$	758,704	$	152,144		$	4,884	$	157,028
Total Plan assets at fair value	$	735,514	$	48,112	$	783,626	$	485,454		$	36,184	$	521,638
Commingled equity funds (5)		—		—		—		250,511			7,455		257,966
Insurance company general account contracts (6)		3,448		—		3,448		3,719			—		3,719
Total Plan assets (7)	$	738,962	$	48,112	$	787,074	$	739,684		$	43,639	$	783,323

Southwest Gas Corporation 75

(1) The Mutual funds category above is an intermediate-term bond fund whose manager employs multiple concurrent strategies and takes only moderate risk in each, thereby reducing the risk of poor performance arising from any single source, and a balanced fund that invests in a diversified portfolio of common stocks, preferred stocks and fixed-income securities. Strategies utilized by the bond fund include duration management, yield curve or maturity structuring, sector rotation, and all bottom-up techniques including in-house credit and quantitative research. Strategies employed by the fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income. Currently, this balanced fund is the only mutual fund in which the Plan invests.

In the prior year, Level 1 also included Common stock, Real Estate Investment Trusts, Mutual funds, and U.S. Government securities listed or regularly traded on a national securities exchange and were valued at quoted market prices as of the last business day of the calendar year.

(2) The private commingled equity funds include common collective trusts that invest in a diversified portfolio of domestic and international securities regularly traded on securities exchanges. These funds are shown in the above table at net asset value (“NAV”), which is the value of securities in the fund less the amount of any liabilities outstanding. Investment strategies employed by the funds include:

• Domestic equities

• International developed countries equities

• Emerging markets equities

Shares in the private equity commingled funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item.

Two funds are classified as international funds. One invests in international financial markets, primarily those of developed economies in Europe and the Pacific Basin. The fund invests primarily in equity securities issued by foreign corporations, but may invest in other securities perceived as offering attractive investment return opportunities. The other provides diversified exposure to global equity markets. The fund seeks to provide long-term capital growth by investing primarily in securities listed on the major developed equity markets of the United States, Europe, and Asia, as well as within those listed on emerging country equity markets on a tactical basis.

The large and medium capitalization fund is designed to track the performance of the large and medium capitalization companies contained in the index, which represents approximately 90% of the market capitalization of the United States stock market.

The small capitalization fund is designed to provide maximum long-term appreciation through investments that are well diversified by industry.

The emerging markets fund was developed to invest in emerging market equities worldwide. The purposes of the fund’s operations, “emerging market countries” include every country in the world except the developed markets of the United States, Canada, Japan, Australia, New Zealand, Hong Kong and Singapore, and most

Southwest Gas Corporation 76

countries located in Western Europe. Fund investments are made directly in each country or, where direct investment is inefficient or prohibited, through appropriate financial instruments or participation in commingled funds.

(3) The private commingled fixed income funds include domestic fixed income securities. These funds are shown in the above table at NAV. Shares in the private commingled fixed equity funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item.

The U.S. corporate bond fund seeks to provide high quality, mostly corporate bond-based exposure to fixed income securities which closely match those found in discount curves used to value United States pension liabilities.

The United States debt market long duration fund provides participation in the full spectrum of investment opportunities in primarily United States debt markets with longer maturities. The fund seeks to offer effective diversification against equities, take advantage of market trading opportunities, and provide a competitive rate of return on assets. The fund’s current duration is close to 14 years.

The United States Treasuries securities funds seeks to replicate the risk and return characteristics of the Barclays Treasury U.S. Separate Trading of Registered Interest and Principal of Securities (“STRIPS”) 28-29 Years Index with minimum tracking error.

(4) With the exception of items (2) and (3), which are discussed in detail above, the current year Level 2 assets consist mainly of pooled funds and mutual funds. These funds are collective short-term funds that invest in Treasury bills and money market funds and are used as a temporary cash repository.

In the prior year, the fair value of the Level 2 investments in debt securities with remaining maturities of one year or more was determined by dealers who make markets in such securities or by an independent pricing service, which considers yield or price of bonds of comparable quality, coupon, maturity, and type.

(5) In the prior year, the commingled equity funds included private equity funds that invest in domestic and international securities regularly traded on securities exchanges. These funds are shown in the above table at net asset value, which is the value of securities in the fund less the amount of any liabilities outstanding. Investment strategies employed by the funds included:

• Domestic large capitalization value equities

• International developed countries value and growth equities

• Emerging markets equities

• International small capitalization equities

The terms and conditions under which shares in the commingled equity funds were redeemed varied among the funds; the notice required ranged from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds required the payment of a minimal impact fee to be applied to redemptions and

Southwest Gas Corporation 77

subscriptions of $5 million or greater; the relative fee diminished the greater the transaction. Other such funds imposed fees to recover direct costs incurred by the fund at redemption, but were indeterminable prior to redemption.

(6) The insurance company general account contracts are annuity insurance contracts used to pay the pensions of employees who retired prior to 1989. The balance of the account disclosed in the above table is the contract value, which is the result of deposits, withdrawals, and interest credits.

(7) In the prior year, the assets in the above table exceeded the market value of plan assets shown in the funded status table by $2,859,000 (qualified retirement plan – $2,803,000, PBOP – $56,000), which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

Note 11 – Stock-Based Compensation

At December 31, 2016, two stock-based compensation plans existed: a performance share stock plan which includes a cash award, and a restricted stock/unit plan. All previous grants under the stock option plan expired in 2016. The table below shows total stock-based plan compensation expense, including the cash award, which was recognized in the Consolidated Statements of Income (in thousands):

	2016		2015		2014
Stock-based compensation plan expense, net of related tax benefits	$	7,185	$	7,278	$	8,130
Stock-based compensation plan related tax benefits		4,404		4,461		4,983

Under the option plan, options to purchase shares of common stock at a stated exercise price were previously granted to key employees and outside directors. The last option grants were in 2006 and no future grants are anticipated. Each option had an exercise price equal to the market price of the Company’s common stock on the date of grant and a maximum term of ten years. The final options were exercised in 2016.

The following tables summarize the stock option plan activity and related information (thousands of options):

	2016					2015					2014
	Number of options			Weighted- average exercise price		Number of options			Weighted- average exercise price		Number of options			Weighted- average exercise price
Outstanding at the beginning of the year		17		$	31.64		36		$	28.97		52		$	27.57
Exercised during the year		(17	)		31.64		(19	)		26.69		(16	)		24.31
Forfeited or expired during the year		—			—		—			—		—			—
Outstanding and exercisable at year end		—			N/A		17		$	31.64		36		$	28.97

Southwest Gas Corporation 78

The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding and exercisable options, and options that were exercised, are presented in the table below (in thousands):

	2016		2015		2014
Outstanding and exercisable	$	—	$	394	$	1,194
Exercised		554		590		451

	December 31, 2016		December 31, 2015		December 31, 2014
Market value of Company stock	$	76.62	$	55.16	$	61.81

During 2016, $735,000 in cash was received from the exercise of options with a corresponding tax benefit of $205,000, which was recorded in additional paid-in capital.

Under the performance share stock plan, performance shares may be issued to encourage key employees to remain as employees and to achieve short-term and long-term performance goals. Plan participants are eligible to receive a cash bonus (i.e., short-term incentive) and performance shares (i.e., long-term incentive). The performance shares vest three years after grant and are then issued as common stock.

Restricted stock/units under the restricted stock/unit plan are issued to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance. The restricted stock/units vest 40% at the end of year one and 30% at the end of years two and three and are issued annually as common stock in accordance with the percentage vested. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants of restricted stock/units to directors occurs immediately upon grant. The issuance of common stock for directors currently occurs when their service on the Board ends.

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2016 (thousands of shares):

	Performance Shares			Weighted- average grant date fair value		Restricted Stock/ Units			Weighted- average grant date fair value
Nonvested/unissued at beginning of year		197		$	50.63		228		$	44.36
Granted		44			59.05		73			60.39
Dividends		5					6
Forfeited or expired		—			—		—			—
Vested and issued*		(78	)		41.82		(45	)		51.98
Nonvested/unissued at December 31, 2016		168		$	55.62		262		$	46.41

* Includes shares for retiree payouts and those converted for taxes.

The weighted average grant date fair value of performance shares and restricted stock/units granted in 2015 and 2014 was $63.09 and $53.73, respectively.

As of December 31, 2016, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million.

Southwest Gas Corporation 79

Note 12 – Income Taxes

The following is a summary of income before taxes and noncontrolling interest for domestic and foreign operations (thousands of dollars):

Year ended December 31,	2016		2015			2014
U.S.	$	218,810	$	221,660		$	221,471
Foreign		12,713		(2,328	)		(1,950	)
Total income before income taxes	$	231,523	$	219,332		$	219,521

Income tax expense (benefit) consists of the following (thousands of dollars):

Year Ended December 31,	2016			2015			2014
Current:
Federal	$	541		$	21,321		$	1,739
State		5,748			9,899			5,073
Foreign		4,298			650			2,193
		10,587			31,870			9,005
Deferred:
Federal		68,270			51,132			71,439
State		140			(2,574	)		614
Foreign		(529	)		(526	)		(2,685	)
		67,881			48,032			69,368
Total income tax expense	$	78,468		$	79,902		$	78,373

Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):

Year Ended December 31,	2016			2015			2014
Deferred federal and state:
Property-related items	$	76,217		$	65,931		$	52,814
Purchased gas cost adjustments		361			(32,993	)		15,049
Employee benefits		(1,327	)		623			109
All other deferred		(6,532	)		15,332			2,257
Total deferred federal and state		68,719			48,893			70,229
Deferred ITC, net		(838	)		(861	)		(861	)
Total deferred income tax expense	$	67,881		$	48,032		$	69,368

Southwest Gas Corporation 80

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2014, 2015, and 2016 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2016			2015			2014
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.4			1.8			1.9
Property-related items		—			0.1			0.1
Tax credits		(0.4	)		(0.4	)		(0.5	)
Company owned life insurance		(1.2	)		0.1			(1.0	)
All other differences		(0.9	)		(0.2	)		0.2
Consolidated effective income tax rate		33.9	%		36.4	%		35.7	%

Deferred tax assets and liabilities consist of the following (thousands of dollars):

December 31,	2016			2015
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	1,094		$	1,614
Employee benefits		38,231			36,923
Alternative minimum tax credit		4,827			4,809
Net operating losses and credits		1,204			868
Interest rate swap		6,080			7,351
Other		18,415			24,636
Valuation allowance		(495	)		(499	)
		69,356			75,702
Deferred tax liabilities:
Property-related items, including accelerated depreciation		872,136			794,850
Regulatory balancing accounts		1,104			743
Unamortized ITC		1,710			2,549
Debt-related costs		5,712			5,497
Intangibles		8,803			9,547
Other		19,256			31,533
		908,721			844,719
Net noncurrent deferred tax liabilities	$	839,365		$	769,017

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, various states, and in Canada. With few exceptions, the Company is no longer subject to United States federal, state and local, or Canadian income tax examinations for years before 2012.

At December 31, 2016, the Company has U.S. federal net capital loss carryforwards of $278,000, which begin to expire in 2017. At December 31, 2016, the Company has an income tax net operating loss carryforward related to Canadian operations of $4.5 million which begins to expire in 2032.

As of December 31, 2016, the Company has approximately $5 million of undistributed foreign earnings. However, management intends to permanently reinvest any future foreign earnings in Canada.

Southwest Gas Corporation 81

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (thousands of dollars):

	2016		2015
Unrecognized tax benefits at beginning of year	$	296	$	305
Gross increases – tax positions in prior period		897		—
Gross decreases – tax positions in prior period		—		(9	)
Gross increases – current period tax positions		38		—
Gross decreases – current period tax positions		—		—
Settlements		—		—
Lapse in statute of limitations		—		—
Unrecognized tax benefits at end of year	$	1,231	$	296

In assessing whether uncertain tax positions should be recognized in its financial statements, management first determines whether it is more-likely-than-not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, management presumes that the position will be examined by the appropriate taxing authority that would have full knowledge of all relevant information. For tax positions that meet the more-likely-than-not recognition threshold, management measures the amount of benefit recognized in the financial statements at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. Unrecognized tax benefits are recognized in the first financial reporting period in which information becomes available indicating that such benefits will more-likely-than-not be realized. For each reporting period, management applies a consistent methodology to measure unrecognized tax benefits, and all unrecognized tax benefits are reviewed periodically and adjusted as circumstances warrant. Measurement of unrecognized tax benefits is based on management’s assessment of all relevant information, including prior audit experience, the status of audits, conclusions of tax audits, lapsing of applicable statutes of limitation, identification of new issues, and any administrative guidance or developments.

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate was $935,000 at December 31, 2016. No significant increases or decreases in unrecognized tax benefit are expected within the next 12 months.

The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. There was no tax-related interest income for 2016, 2015, and 2014.

Income Tax Regulations.    In September 2013, the United States Department of the Treasury and the Internal Revenue Service (“IRS”) issued regulations for the tax treatment of tangible property. The regulations include standards for determining whether and when a taxpayer must capitalize costs incurred in acquiring, maintaining, or improving tangible property. The regulations are generally effective for tax years beginning on or after January 1, 2014, and were eligible for adoption in earlier years under certain circumstances. Regulations were also released that revise the rules for dispositions of tangible property and general asset accounts. Management expects the IRS to issue natural gas industry guidance that will facilitate its analysis regarding the regulations’ impact on natural gas distribution networks. Based upon preliminary analysis of the regulations, and in anticipation of specific guidance for the natural gas industry, management expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.

Southwest Gas Corporation 82

Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (up to 25% in the Arizona and California jurisdictions) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2017 through March 2019. Under such contracts, Southwest pays the counterparty a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):

	December 31, 2016		December 31, 2015
Contract notional amounts		10,543		7,407

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 Southwest’s Swaps (derivatives) for the years ended December 31, 2016, 2015, and 2014 and their location in the Consolidated Statements of Income:

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

(Thousands of dollars)

Instrument	Location of Gain or (Loss) Recognized in Income on Derivative		2016			2015			2014
Swaps		Net cost of gas sold	$	5,006		$	(7,598	)	$	(2,363	)
Swaps		Net cost of gas sold		(5,006	)*		7,598	*		2,363	*
Total			$	—		$	—		$	—

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

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

Southwest Gas Corporation 83

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

Fair values of derivatives not designated as hedging instruments:

December 31, 2016 Instrument	Balance Sheet Location		Asset Derivatives		Liability Derivatives			Net Total
Swaps		Deferred charges and other assets	$	899	$	(54	)	$	845
Swaps		Prepaids and other current assets		3,551		(19	)		3,532
Total			$	4,450	$	(73	)	$	4,377
December 31, 2015 Instrument	Balance Sheet Location		Asset Derivatives		Liability Derivatives			Net Total
Swaps		Other current liabilities	$	—	$	(4,267	)	$	(4,267	)
Swaps		Other deferred credits		4		(1,223	)		(1,219	)
Total			$	4	$	(5,490	)	$	(5,486	)

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

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

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

	Year ended December 31, 2016		Year ended December 31, 2015		Year ended December 31, 2014
(Thousands of dollars)
Paid to counterparties	$	5,583	$	7,537	$	829
Received from counterparties	$	726	$	—	$	4,713

Southwest Gas Corporation 84

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

December 31, 2016 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(845	)
Swaps	Other current liabilities		(3,532	)
December 31, 2015 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	4,267
Swaps	Deferred charges and other assets		1,219

Fair Value Measurements.    The estimated fair values of Southwest’s Swaps were determined at December 31, 2016 and December 31, 2015 using New York Mercantile Exchange (“NYMEX”) futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measurement.

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, financial assets and liabilities that were accounted for at fair value (see Note 10 – Pension and Other Post Retirement Benefits for definitions of the levels of the fair value hierarchy):

Level 2 – Significant other observable inputs

	December 31, 2016		December 31, 2015
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets – Swaps	$	3,532	$	—
Deferred charges and other assets – Swaps		845		—
Liabilities at fair value:
Other current liabilities – Swaps		—		(4,267	)
Other deferred credits – Swaps		—		(1,219	)
Net Assets (Liabilities)	$	4,377	$	(5,486	)

No financial assets or liabilities associated with the Swaps, which were accounted for at fair value, fell within Level 1 or Level 3 of the fair value hierarchy.

With regard to the fair values of assets associated with pension and postretirement benefit plans, refer to Note 10 – Pension and Other Post Retirement Benefits.

Southwest Gas Corporation 85

Note 14 – Segment Information

Operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and providing industrial construction solutions. Over 99% of the total Company’s long-lived assets are in the United States.

The accounting policies of the reported segments are the same as those described within Note 1 – Summary of Significant Accounting Policies.Centuri accounts for the services provided to Southwest at contractual prices at contract inception. Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).

	December 31, 2016		December 31, 2015
Accounts receivable for Centuri services	$	10,585	$	10,006

The following table presents the amount of revenues for both segments by geographic area (thousands of dollars):

	December 31, 2016		December 31, 2015		December 31, 2014
Revenues (a)
United States	$	2,256,600	$	2,289,133	$	2,069,513
Canada		203,890		174,492		52,194
Total	$	2,460,490	$	2,463,625	$	2,121,707

(a) Revenues are attributed to countries based on the location of customers.

Southwest Gas Corporation 86

The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2016 is as follows (thousands of dollars):

2016	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,321,412	$	1,040,957				$	2,362,369
Intersegment sales		—		98,121					98,121
Total	$	1,321,412	$	1,139,078				$	2,460,490
Interest revenue	$	1,848	$	1				$	1,849
Interest expense	$	66,997	$	6,663				$	73,660
Depreciation and amortization	$	233,463	$	55,669				$	289,132
Income tax expense	$	58,584	$	19,884				$	78,468
Segment net income	$	119,423	$	32,618				$	152,041
Segment assets	$	5,001,756	$	579,370				$	5,581,126
Capital expenditures	$	457,120	$	72,411				$	529,531
2015	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,454,639	$	904,870				$	2,359,509
Intersegment sales		—		104,116					104,116
Total	$	1,454,639	$	1,008,986				$	2,463,625
Interest revenue	$	1,754	$	419				$	2,173
Interest expense	$	64,095	$	7,784				$	71,879
Depreciation and amortization	$	213,455	$	56,656				$	270,111
Income tax expense	$	61,355	$	18,547				$	79,902
Segment net income	$	111,625	$	26,692				$	138,317
Segment assets	$	4,822,845	$	535,840				$	5,358,685
Capital expenditures	$	438,289	$	49,711				$	488,000
2014	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,382,087	$	647,432				$	2,029,519
Intersegment sales		—		92,188					92,188
Total	$	1,382,087	$	739,620				$	2,121,707
Interest revenue	$	2,596	$	6				$	2,602
Interest expense	$	68,299	$	3,770				$	72,069
Depreciation and amortization	$	204,144	$	48,883				$	253,027
Income tax expense	$	63,597	$	14,776				$	78,373
Segment net income	$	116,872	$	24,254				$	141,126
Segment assets	$	4,652,307	$	566,589	$	(10,599	)	$	5,208,297
Capital expenditures	$	350,025	$	46,873				$	396,898

Southwest Gas Corporation 87

(a) Construction services segment assets included two liabilities that were netted against gas operations segment assets during consolidation in 2014. They are: Income taxes payable of $3.3 million, netted against income taxes receivable, net and deferred income taxes of $1.4 million, netted against deferred income taxes, net. Construction services segment assets exclude a long-term deferred tax benefit of $1.4 million, which was netted against gas operations segment deferred income taxes and investment tax credits, net during consolidation. Gas operations segment assets include a deferred income tax liability of $4.5 million, which was netted against a construction services segment asset for deferred income taxes, net during consolidation.

Note 15 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30		September 30			December 31
(Thousands of dollars, except per share amounts)
2016
Operating revenues	$	731,248	$	547,748	$	539,969		$	641,525
Operating income		134,096		28,116		15,539			117,963
Net income		75,355		9,099		2,907			65,694
Net income attributable to Southwest Gas Corporation		75,446		8,943		2,472			65,180
Basic earnings per common share*		1.59		0.19		0.05			1.37
Diluted earnings per common share*		1.58		0.19		0.05			1.36
2015
Operating revenues	$	734,220	$	538,604	$	505,396		$	685,405
Operating income		129,556		25,047		16,143			117,586
Net income (loss)		71,879		5,063		(4,210	)		66,698
Net income (loss) attributable to Southwest Gas Corporation		71,983		4,949		(4,734	)		66,119
Basic earnings (loss) per common share*		1.54		0.11		(0.10	)		1.40
Diluted earnings (loss) per common share*		1.53		0.10		(0.10	)		1.38
2014
Operating revenues	$	608,396	$	453,153	$	432,475		$	627,683
Operating income		127,065		26,755		18,290			112,373
Net income		70,697		9,627		1,927			58,897
Net income attributable to Southwest Gas Corporation		70,783		9,627		1,970			58,746
Basic earnings per common share*		1.52		0.21		0.04			1.26
Diluted earnings per common share*		1.51		0.21		0.04			1.25

* The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted-average number of common shares outstanding.

The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in operations. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.

Southwest Gas Corporation 88

Note 16 – Construction Services Noncontrolling Interests

Associated with the agreement reached in conjunction with the acquisition of the Canadian construction businesses in October 2014, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses, and special dividend rights which entitled the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri, and subject to certain conditions, such interests could become exchangeable for a 3.4% equity interest in Centuri. In consideration of the underlying exchange rights of the original agreement, earnings attribution by Centuri to the previous owners also occurred in an amount equivalent to 3.4% of Centuri earnings since October 2014. During the third quarter of 2015, the sellers formally exercised their exchange rights under the terms of the original agreement. No new rights were conveyed to the noncontrolling parties as a result of the exchange and no new consideration was involved. The previous owners are currently eligible to exit their investment retained by requiring the purchase of a portion of their interest and in incremental amounts annually. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election beginning in July 2022. Due to the ability of the noncontrolling parties to redeem their interest in Centuri for cash, their collective interest is presented on the Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance.

Significant changes in the value of the redeemable noncontrolling interest are recognized as they occur, and the carrying value is adjusted as necessary at each reporting date. Guidance by the SEC indicates that downward adjustments in the value of redeemable noncontrolling interests are only permitted to the extent that upward adjustments in value were previously recognized. A floor for the noncontrolling interest was originally set at the acquisition date (in October 2014). However, U.S. GAAP generally views changes in ownership interest, where the parent retains its controlling interest, as an equity transaction, whereby the carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. In connection with the exchange rights exercised during the third quarter of 2015, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized at that time, due in part to the exchange option no longer being subject to probability estimates. In light of the U.S. GAAP requirement to adjust the carrying amount, a new floor was set for the redeemable noncontrolling interest at the exchange date (July 31, 2015), with a corresponding adjustment made to additional paid-in capital. Future adjustments to the redemption value are not permitted below a floor established subject to such conditions, and upward adjustments since the exchange date have had an offsetting impact to Retained earnings on the Balance Sheets. The following depicts impacts to the balance of the redeemable noncontrolling interest between the indicated periods.

	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2015	$	16,108
Net Income (loss) attributable to redeemable noncontrolling interest		1,148
Foreign currency exchange translation adjustment		5
Centuri distribution to redeemable noncontrolling interest		(439	)
Adjustment to redemption value		5,768
Balance, December 31, 2016	$	22,590

Southwest Gas Corporation 89

The redemption value of the redeemable noncontrolling interest utilizes a market approach to determine a construction services enterprise value. Publicly traded “guideline” companies are identified by using a selection criteria, including actively traded equities, their financial solvency, and other factors. Once the guideline companies are determined, enterprise value is calculated using a weighted approach of projected earnings before interest expense and taxes (“EBIT”) and earnings before interest expense, taxes, and depreciation and amortization expense (“EBITDA”). After an estimated fair value is determined, it is multiplied by 3.4%. A discount is then applied due to limitations of the nonpublic noncontrolling interest being valued. Each quarter, market changes in the guideline companies are considered and the weighted approach to projected EBIT and EBITDA, in relation to the guideline companies, is re-evaluated to determine if value changes are necessary at each quarterly reporting date. The adjustment to the redemption value in the table above reflects the sum of such adjustments made during the year.

Centuri also holds a 65% interest in a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. Centuri consolidates the entity (IntelliChoice Energy, LLC) as a majority-owned subsidiary. The interest is immaterial to the consolidated financial statements, but is identified as the Noncontrolling interest within Total equity on the Consolidated Balance Sheets.

Southwest Gas Corporation 90

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of internal control over financial reporting based on the “Internal Control – Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon management’s evaluation under such framework, management concluded that the internal control over financial reporting was effective as of December 31, 2016. The effectiveness of internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 28, 2017

Southwest Gas Corporation 91

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Holdings, Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interest , and cash flows present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 28, 2017

Southwest Gas Corporation 92