10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION

(Exact name of registrant as specified in its charter)

California	88-0085720
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5241 Spring Mountain Road Post Office Box 98510 Las Vegas, Nevada	89193-8510
(Address of principal executive offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $1 par value	New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

Large accelerated filer	þ	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

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

Aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant:

$2,503,122,220 as of June 30, 2015

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 47,456,479 shares as of February 16, 2016

DOCUMENTS INCORPORATED BY REFERENCE

Description	Part Into Which Incorporated
Annual Report to Shareholders for the Year Ended December 31, 2015 2016 Proxy Statement	Parts I, II, and IV Part III

TABLE OF CONTENTS

PART I		1
Item 1.	BUSINESS	1
	NATURAL GAS OPERATIONS	1
	General Description	1
	Rates and Regulation	2
	Demand for Natural Gas	3
	Natural Gas Supply	3
	Competition	5
	Environmental Matters	6
	Employees	6
	CONSTRUCTION SERVICES	6
Item 1A.	RISK FACTORS	8
Item 1B.	UNRESOLVED STAFF COMMENTS	13
Item 2.	PROPERTIES	13
Item 3.	LEGAL PROCEEDINGS	13
Item 4.	MINE SAFETY DISCLOSURES	13
Item 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	13
PART II		14
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	14
Item 6.	SELECTED FINANCIAL DATA	14
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	14
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	15
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	15
Item 9A.	CONTROLS AND PROCEDURES	15
Item 9B.	OTHER INFORMATION	16
PART III		16
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	16
Item 11.	EXECUTIVE COMPENSATION	18
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	18
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	19
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	19
PART IV		20
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	20
	LIST OF EXHIBITS	21
SIGNATURES		25

PART I

Item 1. BUSINESS

Southwest Gas Corporation (the “Company”) was incorporated in March 1931 under the laws of the state of California. The Company is composed 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.

Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a 96.6% owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”).

Financial information concerning the Company’s business segments is included in Note 14 of the Notes to Consolidated Financial Statements, which is included in the 2015 Annual Report to Shareholders and is incorporated herein by reference.

The Company maintains a website (www.swgas.com) for the benefit of shareholders, investors, customers, and other interested parties. The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports available, free of charge, through its website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The Company’s Corporate Governance Guidelines, Code of Business Conduct and Ethics, and charters of the nominating and corporate governance, audit, and compensation committees of the board of directors are also available on the Company’s website. Print versions of these documents are available to shareholders upon request directed to the Corporate Secretary, Southwest Gas Corporation, 5241 Spring Mountain Road, Las Vegas, NV 89150.

NATURAL GAS OPERATIONS

General Description

Southwest is subject to regulation by the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), and the California Public Utilities Commission (“CPUC”). These commissions regulate public utility rates, practices, facilities, and service territories in their respective states. The CPUC also regulates the issuance of all securities by the Company, with the exception of short-term borrowings. Certain accounting practices, transmission facilities, and rates are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Centuri is not regulated by the state utilities commissions or by the FERC in any of its operating areas.

As of December 31, 2015, Southwest purchased and distributed or transported natural gas to 1,956,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. Southwest added 26,000 net new customers during 2015. Southwest expects similar customer growth in 2016.

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The table below lists the percentage of operating margin (operating revenues less net cost of gas) by major customer class for the years indicated:

	Distribution
For the Year Ended	Residential and Small Commercial			Other Sales Customers			Transportation
December 31, 2015		85	%		4	%		11	%
December 31, 2014		85	%		4	%		11	%
December 31, 2013		85	%		4	%		11	%

Southwest is not dependent on any one or a few customers such that the loss of any one or several would have a significant adverse impact on earnings or cash flows. See Risk Factors below regarding impacts in the event of loss of significant customers in the construction services segment.

Transportation of customer-secured gas to end-users accounted for 49% of total system throughput in 2015, but only 11% of operating margin as shown in the table above. Customers who utilized this service transported 104 million dekatherms in 2015, 91 million dekatherms in 2014, and 104 million dekatherms in 2013.

The demand for natural gas is seasonal, with greater demand in the colder winter months and decreased demand in the warmer summer months. It is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in operations. The decoupled rate mechanisms in place in the three-state service territory are structured with seasonal variations. Also, earnings for interim periods can be significantly affected by the timing of general rate relief.

Rates and Regulation

Rates that Southwest is authorized to charge its distribution system customers are determined by the ACC, PUCN, and CPUC in general rate cases and are derived using rate base, cost of service, and cost of capital experienced in an historical test year, as adjusted in Arizona and Nevada, and projected for a future test year in California. The FERC regulates the northern Nevada transmission and liquefied natural gas (“LNG”) storage facilities of Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary, and the rates it charges for transportation of gas directly to certain end-users and to various local distribution companies (“LDCs”). The LDCs transporting on the Paiute system are: NV Energy (serving Reno and Sparks, Nevada) and Southwest (serving Truckee, South and North Lake Tahoe in California and various locations throughout northern Nevada).

Rates charged to customers vary according to customer class and rate jurisdiction and are set at levels that are intended to allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt as well as a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, plus certain other assets such as working capital and inventories, less accumulated depreciation on utility plant in service, net deferred income tax liabilities, and certain other deductions.

Rate structures in all service territories allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption, though decoupled structures vary by state. In California, authorized operating margin levels vary by month. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin. In Arizona, a full revenue decoupling mechanism with a winter-period monthly weather adjuster is in place, for most customer classes.

Rate schedules in all service areas contain deferred energy or purchased gas adjustment provisions, which allow Southwest to file for rate adjustments as the cost of purchased gas changes. Deferred energy and purchased gas adjustment (collectively “PGA”) rate changes affect cash flows, but have no direct impact on profit margin. Filings to change rates in accordance with PGA clauses are subject to audit by the appropriate state regulatory commission staff.

Information with respect to recent general rate cases and PGA filings is included in the Rates and Regulatory Proceedings section of Management’s Discussion and Analysis (“MD&A”) in the 2015 Annual Report to Shareholders.

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The table below lists recent docketed general rate filings and the status of such filing within each ratemaking area:

Ratemaking Area	Type of Filing	Month Filed	Month Final Rates       Effective
Arizona:	General rate case	November 2010	January 2012
California:
Northern and Southern	Annual attrition	November 2015	January 2016
Northern and Southern	General rate case	December 2012	June 2014
Nevada:
Northern and Southern	General rate case	April 2012	April 2013
FERC:
Paiute	General rate case	February 2014	February 2015

While Southwest is subject to regulatory rules and oversight with regard to rates and operating requirements under its various state tariffs (and federal tariff, in the case of Paiute Pipeline), it is also subject to regulation with regard to the safety and integrity of its pipeline systems. The Department of Transportation (“DOT”) administers pipeline regulations through the Office of Pipeline Safety, within the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). In recent years, various pieces of legislation have been passed in the areas of distribution pipeline integrity, control room management, and pipeline safety. The Pipeline Inspection, Protection, Enforcement, and Safety (“PIPES”) Act of 2006 mandated, among other things, a graduated implementation program for control room management, a requirement to install excess flow valves on single-family residential customer locations, and a Distribution Integrity Management Program (“DIMP”), which was required to be in place by August 2011, and includes evaluation and mitigation of risks, as well as certain reporting requirements. Additionally, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“the Bill”), effective January 2012, which increased/strengthened previously existing safety requirements, including damage prevention programs, penalty provisions, and requirements related to automatic and remote-controlled shut-off valves, public awareness programs, incident notification, and maximum allowable operating pressure for certain facilities. The Bill required the DOT to conduct further study of existing programs and future requirements; these studies are nearing their completion and proposed regulation changes are anticipated in 2016. The PHMSA is in the process of proposing a series of at least 5 significant rulemakings that are expected to further transform the regulatory requirements for pipelines. These changes seek to address Congressional mandates, National Transportation Safety Board recommendations, and General Accountability Office reports, as well as reports and recommendations of other agencies. The Company continues to monitor changing pipeline safety legislation and participates to the extent possible in crafting associated mandates and reporting. As additional rules are developed, they could impact the Company’s expenses and the timing and amount of capital expenditures.

Demand for Natural Gas

Deliveries of natural gas by Southwest are made under a priority system established by state regulatory commissions. The priority system is intended to ensure that the gas requirements of higher-priority customers, primarily residential customers and other customers who use 500 therms or less of gas per day, are fully satisfied on a daily basis before lower-priority customers, primarily electric utility and large industrial customers able to use alternative fuels, are provided any quantity of gas or capacity.

Demand for natural gas is greatly affected by temperature. On cold days, use of gas by residential and commercial customers can be as much as seven times greater than on warm days because of increased use of gas for space heating. To fully satisfy this increased high-priority demand, gas is withdrawn from storage in certain service areas, or peaking supplies are purchased from suppliers. If necessary, service to interruptible lower-priority customers may be curtailed to provide the needed delivery system capacity. Southwest maintains no significant backlog on its orders for gas service.

Natural Gas Supply

Southwest is responsible for acquiring and arranging delivery of natural gas to its system in sufficient quantities to meet its sales customers’ needs. Southwest’s primary natural gas procurement objective is to ensure that adequate supplies of natural gas are available at a reasonable cost. Southwest acquires natural gas from a wide variety of sources and a mix of purchase provisions, which includes spot market and firm supplies. The purchases may have terms from one day to several years and utilize both fixed and indexed pricing. During 2015, Southwest acquired natural gas from 41 suppliers. Southwest regularly monitors the number of suppliers, their performance, and their relative contribution to the overall customer supply

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portfolio. New suppliers are contracted when possible, and solicitations for supplies are extended to the largest practicable list of suppliers, taking into account each supplier’s creditworthiness. Competitive pricing, flexibility in meeting Southwest’s requirements, and demonstrated reliability of service are instrumental to any one supplier’s inclusion in Southwest’s portfolio. The goal of this practice is to mitigate the risk of nonperformance by any one supplier and ensure competitive prices in the portfolio.

Balancing reliability with supply cost results in a continually changing mix of purchase provisions within the supply portfolios. To address the unique requirements of its various market areas, Southwest assembles and administers a separate natural gas supply portfolio for each of its jurisdictional areas. Southwest facilitates most natural gas purchases through competitive bid processes.

To mitigate customer exposure to short-term market price volatility, Southwest seeks to fix the price on a portion (up to 25% in the Arizona and California jurisdictions) of its forecasted annual normal-weather volume requirement, primarily using firm, fixed-price purchasing arrangements that are secured periodically throughout the year. Southwest’s price volatility mitigation program includes the use of financial derivatives, in the form of fixed-for-floating-index-price swaps combined with indexed-price physical purchases, to secure a portion of the fixed-price portfolio for the Arizona rate jurisdiction. The combination of fixed-price contracts and financial derivatives is designed to increase flexibility for Southwest and increase supplier diversification. The cost of such financial derivatives combined with the associated indexed-price physical purchases is recovered from customers through the PGA mechanism.

In late 2013, the Company suspended using fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada territories. The Company evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions. Any future decision concerning Nevada VMP purchases will be documented and retained to facilitate regulatory review in accordance with a previous regulatory stipulation. The Company schedules quarterly meetings with the PUCN Staff and the Bureau of Consumer Protection to discuss market fundamentals, along with any decision by the Company concerning VMP purchases for the Nevada service territories.

For the 2015/2016 heating season, fixed-price physical commodity purchases ranged from slightly under $3 to approximately $4.40 per dekatherm. Southwest makes non-fixed-price natural gas purchases under variable-price contracts with firm quantities or on the spot market. Prices for these contracts are determined at the beginning of each month to reflect that month’s published first-of-month index price or based on a published daily price index. These monthly or daily index prices are not published or known until the purchase period begins.

The firm natural gas supply arrangements are structured such that a stated volume of natural gas is required to be nominated by Southwest and delivered by the supplier. Contracts provide for fixed or market-based penalties to be paid by the non-performing party.

Storage availability can influence the average annual price of natural gas, as storage allows a company to purchase natural gas quantities during the off-peak season and store it for use in high demand periods when prices may be greater or supplies/capacity tighter. Southwest currently has no storage availability in its southern Nevada rate jurisdiction. Limited storage availability exists in southern and northern California, northern Nevada, and the Arizona rate jurisdiction.

Southwest has a contract with Southern California Gas Company that is intended for delivery only within Southwest’s southern California rate jurisdiction. In addition, contracts with Paiute for its LNG facility allow for peaking capability only in northern Nevada and northern California. For all storage options, Southwest purchases natural gas for injection during the off-peak period for use in the high demand months, but these supplies have a limited impact on the overall price.

Southwest also has interruptible storage contracts with Northwest Pipeline Corporation (“NWPL”) for the northern Nevada and northern California rate jurisdictions. NWPL has the discretion to limit Southwest’s ability to inject or withdraw from this interruptible storage, which consequently limits Southwest’s use of this interruptible storage capacity. As such, this storage provides limited operational flexibility to adjust daily flowing supplies to meet demand, and has limited impact on the overall price of natural gas supplies.

Southwest also has an agreement for its Arizona rate jurisdiction with Enstor Grama Ridge Storage and Transportation, LLC (“Enstor”) which provides for a maximum quantity of 600,000 dekatherms of natural gas underground storage in New Mexico that is deliverable on the El Paso system. Southwest previously received approval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, operated by Southwest and

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connected directly to its distribution system. The Company purchased the site for the facility in October 2015 and is preparing the construction requirements bid package for potential contractors. The contract to construct the facility is currently expected to be in place in the second half of 2016 and construction is expected to take approximately two to three years to complete. The Company anticipates including a proposal for the ratemaking treatment of facility costs as part of its next Arizona rate case filing.

Natural gas supplies for Southwest’s southern system (Arizona, southern Nevada, and southern California properties) are primarily obtained from producing regions in Colorado and New Mexico (San Juan basin), Texas (Permian basin), and Rocky Mountain areas. For its northern system (northern Nevada and northern California properties), Southwest primarily obtains natural gas from Rocky Mountain producing areas and from Canada.

The landscape for national natural gas supply is continuously changing. Advanced drilling techniques continue to provide access to abundant and sustainable natural gas supplies. The natural gas market has responded to the abundant supply of natural gas with reductions to both price volatility and the total price of the commodity. Forecasts show that an ample and diverse natural gas supply is available to Southwest’s customers at a highly competitive price when compared with competing forms of energy.

Southwest arranges for transportation of natural gas to its Arizona, Nevada, and California service territories through the pipeline systems of El Paso Natural Gas Company (“El Paso”), Kern River Gas Transmission Company (“Kern River”), Transwestern Pipeline Company (“Transwestern”), NWPL, Tuscarora Gas Pipeline Company (“Tuscarora”), Southern California Gas Company, and Paiute. Southwest regularly monitors short- and long-term supply and pipeline capacity availability to ensure the reliability of service to its customers. Southwest currently receives firm transportation service, both on a short- and long-term basis, for all of its service territories on the pipeline systems noted above. Southwest also contracts for firm natural gas supplies that are delivered to Southwest’s city gates to supplement its firm capacity on the interstate pipelines and to meet projected peak-day demands. Southwest could also utilize its interruptible contracts on the interstate pipelines for the transportation of additional natural gas supplies.

Southwest believes that the current levels of contracted firm interstate capacity and delivered purchases are sufficient to serve each of its service territories’ forecasted peak-day requirements. As the need arises to acquire additional capacity on one of the interstate pipeline transmission systems, primarily due to customer growth, Southwest will continue to consider available options to obtain that capacity, either through the use of firm contracts with a pipeline company, by purchasing capacity on the open market, or through the purchase of firm delivered natural gas supplies.

Competition

Electric utilities are the principal competitors of Southwest for the residential and small commercial markets throughout its service areas. Competition for space heating, general household, and small commercial energy needs generally occurs at the initial installation phase when the customer/builder typically makes the decision as to which type of equipment to install and operate. The customer will generally continue to use the chosen energy source for the life of the equipment. Southwest interfaces directly with the various home builders and commercial property developers in its service territories to ensure that natural gas appliances are considered in new developments and commercial centers. As a result of its efforts, Southwest has continued to experience growth in the new construction market among residential and small commercial customer classes.

Unlike residential and small commercial customers, certain large commercial, industrial, and electric generation customers have the capability to switch to alternative energy sources. To date, Southwest has been successful in retaining most of these customers by setting rates at levels competitive with commercially available alternative energy sources such as electricity, fuel oils, and coal. However, high natural gas prices can impact Southwest’s ability to retain some of these customers. Overall, management does not anticipate any material adverse impact on operating margin from fuel switching by these large customers.

Southwest competes with interstate transmission pipeline companies, such as El Paso, Kern River, Transwestern and Tuscarora, to provide service to certain large end-users. End-use customers located in proximity to these interstate pipelines pose a potential bypass threat. Southwest attempts to closely monitor each customer situation and provide competitive service in order to retain the customer. Southwest has remained competitive through the use of negotiated transportation contract rates, special long-term contracts with electric generation and cogeneration customers, and other tariff programs. These competitive response initiatives have mitigated the loss of margin earned from large customers.

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Environmental Matters

Federal, state, and local laws and regulations governing the discharge of materials into the environment have a direct impact upon Southwest. Environmental efforts, with respect to matters such as storm water management, emissions of air pollutants, hazardous material management, protection of endangered species and archeological resources, directly impact the complexity and time required to obtain pipeline rights-of-way and construction permits. However, increased environmental legislation and regulation can also be beneficial to the natural gas industry. Natural gas is one of the most environmentally-friendly fossil fuels currently available and its use can help energy users to comply with stricter environmental air quality standards.

The United States Environmental Protection Agency (“EPA”) and the State of California Environmental Protection Agency (“Cal/EPA”) have issued regulations that require the reporting of greenhouse gas emissions (“GHG”) from large sources and suppliers in order to facilitate the development of policies and programs to reduce GHGs. The Company reports required information to EPA and Cal/EPA under each respective Mandatory Reporting Rule (“MRR”) including the volumes of natural gas that it receives for distribution to LDC customers (EPA and Cal/EPA MRR Subpart NN), and the “fugitive” GHG emissions that result from the operation of its LDC pipelines (EPA and Cal/EPA MRR Subpart W). While some parts of the MRRs do not apply to Southwest, other required information is being reported to the Department of Energy, the Department of Transportation, or is available in existing Company databases. The Company also monitors the development of climate legislation (including the State of California Global Warming Solutions Act), which could result in additional requirements or have financial implications.

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 of the requirements associated with the California GHG Emissions Reporting Program 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 2015, the CARB annually allocates to Southwest a certain number of allowances based on Southwest’s reported 2011 GHG emissions. Southwest received its allocation for 2015 in the third quarter of 2014 and, for 2016, in the third quarter of 2015. Of those allocated allowances, Southwest must consign a certain percentage, to the CARB for auction. The Company 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. In addition to allowances, Southwest can satisfy a portion of its compliance obligation through the purchase of offsets, which are credits available in the OTC market from industries that generate reductions in greenhouse gas emissions.

There are two triennial compliance periods; one ending in 2017 and the other ending in 2020. To meet its compliance obligations, during each triennial compliance period, Southwest must surrender a combination of allowances and offsets equal to 30% of its annual reported GHG emissions for the prior year by November 1 of each year (2016 through 2020). Also by November 1 of the year following each of the triennial compliance periods (2018 and 2021), Southwest must surrender a sufficient number of allowances and offsets to meet the amount of GHG emissions reported during that triennial compliance period, less the amount previously surrendered.

The CPUC has issued a decision that provides for the regulatory treatment of the program costs and there is no expected impact on earnings.

Employees

At December 31, 2015, the natural gas operations segment had 2,219 regular full-time equivalent employees. Southwest believes it has a good relationship with its employees and that compensation, benefits, and working conditions afforded its employees are comparable to those generally found in the utility industry. No employees are represented by a union.

CONSTRUCTION SERVICES

Centuri is a full-service contractor whose customers are primarily energy services utilities. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions. Centuri contracts primarily with LDCs to install, repair, and maintain energy distribution systems from the town border station to the end-user. The primary focus of Centuri operations is distribution pipe and service hook-up replacements as well as line installations for new business development. Construction work varies from relatively small projects to the piping of entire communities. Construction activity is seasonal in most areas. Peak construction periods are the summer and

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fall months in colder climate areas, such as the North East, Midwest, and Canada. In the warmer climate areas, such as the southwestern United States, construction continues year round.

During the past few years, several factors have resulted in an increase in large multi-year distribution pipe replacement projects. The U.S. Department of Transportation’s PHMSA instituted DIMP which required operators of gas distribution pipelines to develop and implement integrity management programs to enhance safety by identifying and reducing pipeline integrity risks. Also contributing to the increase in replacement projects were bonus depreciation tax deduction incentives. The Protecting Americans from Tax Hikes Act of 2015 extended 50% bonus depreciation tax deduction incentives through 2017 and at lesser rates through 2019. Finally, funding for customers’ planned replacement projects improved due to greater access to credit markets.

In connection with the increased construction activity, several large multi-year distribution pipe replacement projects were awarded to Centuri. Centuri was selected as the sole contractor on certain of these projects, or one of several contractors to work on others. Centuri continues to bid on pipe replacement projects throughout the United States and Canada and has made structural and transitional changes to match the increased size and complexity of the business. The amount of work completed by Centuri on these multi-year contracts will vary from year to year.

Centuri’s business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with Centuri to provide pipe replacement services and new line installations. Contract terms generally specify unit-price or fixed-price arrangements. Unit-price contracts establish prices for all of the various services to be performed during the contract period. These contracts often have annual pricing reviews. During 2015, approximately 87% of revenue was earned under unit-price contracts. As of December 31, 2015, a backlog of approximately $92.3 million existed with respect to outstanding fixed-priced construction contracts.

Materials used by Centuri in its construction activities are typically specified, purchased, and supplied by Centuri’s customers. Construction contracts also contain provisions which make customers generally liable for remediating environmental hazards encountered during the construction process. Such hazards might include digging in an area that was contaminated prior to construction, finding endangered animals, digging in historically significant sites, etc. Otherwise, Centuri’s operations have limited environmental impact (dust control, normal waste disposal, handling harmful materials, etc.)

Competition within the industry has traditionally been limited to several regional and numerous local competitors in what has been a largely fragmented industry. Some national competitors also exist within the industry. Centuri currently operates in 20 major markets within the United States and also within the provinces of British Columbia and Ontario in Canada. Its customers are primarily the principal LDCs in those markets. During 2015, Centuri served over 100 customers, with Southwest accounting for approximately 10% of total revenues. Additionally, two customers combined accounted for approximately 25% of total revenue, while four other customers individually accounted for 5% or more of total revenue.

Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2015, Centuri had 3,657 regular full-time equivalent employees. Employment peaked in October 2015 when there were 5,501 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.

Centuri’s operations are conducted from 25 field locations throughout the United States and 12 field locations within Canada with corporate headquarters located in Phoenix, Arizona. Buildings and equipment storage yards are normally leased from third parties. The lease terms are typically five years or less.

The construction services segment is not directly affected by regulations promulgated by the ACC, PUCN, CPUC, or FERC. Centuri is an unregulated energy services subsidiary of Southwest Gas Corporation. However, because Centuri performs work for the regulated natural gas segment of the Company, its associated construction costs are subject indirectly to “prudency reviews” just as any other capital work that is performed by third parties or directly by Southwest. However, such “prudency reviews” would not bring Centuri under the regulatory jurisdiction of any of the commissions noted above.

Centuri has a 65% interest in IntelliChoice Energy, LLC (“ICE”) and consolidates ICE as a majority owned subsidiary. ICE was established in 2009 and markets natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. To date, ICE has not been a significant component of Centuri operating results.

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 that specializes in construction of underground aviation fueling systems and storage tanks. The Company is not the primary beneficiary of Western; therefore, Western is not consolidated with Centuri and is accounted for under the equity method of accounting. To date, Western has not been a significant component of Centuri’s financial results.

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Item 1A. RISK FACTORS

Described below (and in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this report) are risk factors that we have identified that may have a negative impact on our future financial performance or affect whether we achieve the goals or expectations expressed or implied in any forward-looking statements contained herein. Unless indicated otherwise, references below to “we,” “us,” and “our” should be read to refer to Southwest Gas Corporation and its subsidiaries.

Governmental policies and regulatory actions can reduce our earnings.

Regulatory commissions set our utility customer rates and determine what we can charge for our rate-regulated services. Our ability to obtain timely future rate increases depends on regulatory discretion. Governmental policies and regulatory actions, including those of the Arizona Corporation Commission, the California Public Utilities Commission, the Federal Energy Regulatory Commission, and the Public Utilities Commission of Nevada relating to allowed rates of return, rate structure, purchased gas and investment recovery, operation and construction of facilities, present or prospective wholesale and retail competition, changes in tax laws and policies, and changes in and compliance with environmental and safety laws such as the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and policies, can reduce our earnings. Risks and uncertainties relating to delays in obtaining, or failure to obtain, regulatory approvals, conditions imposed in regulatory approvals, and determinations in regulatory investigations can also impact financial performance. In particular, the timing and amount of rate relief can materially impact results of operations.

We are unable to predict what types of conditions might be imposed on Southwest or what types of determinations might be made in pending or future regulatory proceedings or investigations. We nevertheless believe that it is not uncommon for conditions to be imposed in regulatory proceedings, for Southwest to agree to conditions as part of a settlement of a regulatory proceeding, or for determinations to be made in regulatory investigations that reduce our earnings and liquidity. For example, we may request recovery of a particular operating expense in a general rate case filing that a regulator disallows, negatively impacting our earnings if the expense continues to be incurred. Southwest records regulatory assets in its consolidated financial statements to reflect the ratemaking and regulatory decision-making authority of the regulators, as allowed by generally accepted accounting principles. The creation of a regulatory asset allows for the deferral of costs which, absent a mechanism to recover such costs from customers in rates approved by regulators, would be charged to expense in the consolidated income statement in the period incurred. If there was a change in regulatory positions surrounding the collection of these deferred costs, there could be a material impact on Southwest’s financial position, results of operations, and cash flows.

We may be subject to disallowances, penalties or fines related to the operation of natural gas pipelines under recent regulations concerning natural gas pipeline safety, which could have an adverse effect on our results of operations, financial condition, and/or cash flows.

We are committed to consistently monitoring and maintaining our distribution system and storage operations to ensure that natural gas is acquired, stored and delivered safely, reliably and efficiently. Due to the combustible nature of our product, we anticipate that the natural gas industry could be the subject of increased federal, state, and local regulatory oversight over time. We continue to work diligently with industry associations and federal, state, and local regulators to ensure compliance with any new laws, such as the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. We expect there to be increased costs associated with compliance (and potential penalties for any non-compliance) with this and similar laws. If these costs are not recoverable in our customer rates, or if there are delays in recoverability due to regulatory lag, they could have a negative impact on our operating costs and financial results.

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Our operating results may be adversely impacted by another economic downturn.

The 2007/2008 economic slowdown in the United States, and particularly in our service areas, resulted in a marked decline in the new housing market and an increase in the inventory of idle/vacant homes. Commercial entities (including restaurants and other service establishments) were also impacted, resulting in reductions in operations or closures. The impacts of that slowdown have eased in our service territories and most of the idle/vacant homes have returned to service. If another economic slowdown occurs, our financial condition, results of operations, and cash flows could be adversely affected. Fluctuations and uncertainties in the economy make it challenging for us to accurately forecast and plan future business activities and to identify risks that may affect our business, financial condition, and operating results. We cannot predict the timing, strength, or duration of any future economic slowdowns. If the economy or the markets in which we operate decline from present levels, it may have an adverse effect on our business, financial condition, and results of operations.

We rely on having access to interstate pipelines’ transportation capacity. If these pipelines were not available, it could impact our ability to meet our customers’ full requirements.

We must acquire both sufficient natural gas supplies and interstate pipeline capacity to meet customer requirements. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate pipeline capacity market, our own in-system resources, as well as the characteristics of our customer base. Interruptions to or reductions of interstate pipeline service caused by physical constraints, excessive customer usage, or other force majeure could reduce our normal supply of gas. A prolonged interruption or reduction of interstate pipeline service in any of our jurisdictions, particularly during the winter heating season, would reduce cash flow and earnings.

Our earnings may be materially impacted due to volatility in the cash surrender value of our company-owned life insurance policies during periods in which stock market changes are significant.

We have life insurance policies with a net death benefit value at December 31, 2015 of approximately $237 million on members of management and other key employees to indemnify ourselves against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The net cash surrender value of these policies (which is the cash amount we would receive if we voluntarily terminated the policies) is approximately $99 million at December 31, 2015 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, the cash surrender value (but not the net death benefits) moves up and down consistent with the movements in the broader stock and bond markets. During 2015, Southwest recognized a loss of $500,000 in Other income (deductions) due to decreases in the cash surrender values of its company-owned life insurance policies (compared to an increase of $5.3 million due to increases in cash surrender values and net death benefits recognized in 2014). Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of company-owned life insurance policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Currently, we intend to hold the company-owned life insurance policies for their duration. Changes in the cash surrender value of company-owned life insurance policies, except as related to the purchase of additional policies, affect our earnings but not our cash flows.

The cost of providing pension and postretirement benefits is subject to changes in pension asset values, changing demographics, and actuarial assumptions which may have an adverse effect on our financial results.

We provide pension and postretirement benefits to eligible employees. Our costs of providing such benefits are subject to changes in the market value of our pension fund assets, changing demographics, life expectancies of beneficiaries, current and future legislative changes, and various actuarial calculations and assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, withdrawal rates, interest rates, and other factors. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods. For example, lower than assumed returns on investments and/or reductions in bond yields could result in increased contributions and higher pension expense which would have a negative impact on our cash flows and reduce net income.

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Our liquidity, and in certain circumstances our earnings, may be reduced during periods in which natural gas prices are rising significantly or are more volatile.

Increases in the cost of natural gas may arise from a variety of factors, including weather, changes in demand, the level of production and availability of natural gas, transportation constraints, transportation capacity cost increases, federal and state energy and environmental regulation and legislation, the degree of market liquidity, natural disasters, wars and other catastrophic events, national and worldwide economic and political conditions, the price and availability of alternative fuels, and the success of our strategies in managing price risk.

Rate schedules in each of our service territories contain purchased gas adjustment clauses which permit us to file for rate adjustments to recover increases in the cost of purchased gas. Increases in the cost of purchased gas have no direct impact on our profit margins, but do affect cash flows and can therefore impact the amount of our capital resources. We have used short-term borrowings in the past to temporarily finance increases in purchased gas costs, and we expect to do so during 2016, if the need again arises.

We may file requests for rate increases to cover the rise in the cost of purchased gas. Due to the nature of the regulatory process, there is a risk of disallowance of full recovery of these costs during any period in which there has been a substantial run-up of these costs or our costs are more volatile. Any disallowance of purchased gas costs would reduce cash flow and earnings.

The nature of our operations presents inherent risks of loss that could adversely affect our results of operations.

Our operations are subject to inherent hazards and risks such as gas leaks, fires, natural disasters, catastrophic accidents, explosions, pipeline ruptures, and other hazards and risks that may cause unforeseen interruptions, personal injury, or property damage. Additionally, our facilities, machinery, and equipment, including our pipelines, are subject to third party damage from construction activities, vandalism, or acts of terrorism. Such incidents could result in severe business disruptions, significant decreases in revenues, and/or significant additional costs to us. Any such incident could have an adverse effect on our financial condition, earnings, and cash flows. In addition, any of these or similar events could cause environmental pollution, personal injury or death claims, damage to our properties or the properties of others, or loss of revenue by us or others.

We maintain liability insurance for some, but not all, risks associated with the operation of our natural gas pipelines and facilities. In connection with these liability insurance policies, we are 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. These liability insurance policies require us to be responsible for the first $1 million (self-insured retention) of each incident plus the first $4 million in total claims above our self-insured retention in the policy year. We cannot predict the likelihood that any future event will occur which will result in a claim exceeding $1 million; however, a large claim for which we were deemed liable would reduce our earnings up to and including these self-insurance maximums.

Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.

Our ability to implement our business strategy and serve our customers is dependent upon our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the knowledge and expertise of our workforce to new employees as our aging employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor could adversely affect our ability to manage and operate our business.

We may not be able to rely on rate decoupling to maintain stable financial position, results of operations, and cash flows.

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. Rate structures in all service territories allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption, though decoupled structures vary by state. In California, authorized operating margin levels vary by month. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin. In Arizona, a full revenue decoupling mechanism with a winter-period monthly weather adjuster is in place, for most customer classes. Significantly warmer-than-normal weather conditions in our service territories and other factors, such as climate change and alternative energy sources, may result in decreased cash flows attributable to lower natural gas sales and delays in recovering regulatory asset balances. Furthermore, continuation of the decoupled rate designs currently in place are

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subject to regulatory discretion, and if unfavorably modified or discontinued could adversely impact our financial position and results of operations.

Weather conditions in Centuri’s operating areas can adversely affect our operations, financial position, and cash flows.

Our results of operations, financial position, and cash flows can be significantly impacted by changes in weather that affect the ability of Centuri to provide utility companies with contracted-for trenching, installation, and replacement of underground pipes, as well as maintenance services for energy distribution systems. Generally, Centuri’s revenues are lowest during the first quarter of the year due to less favorable winter weather conditions.

Fixed-price contracts at Centuri are subject to potential losses that could adversely affect results of operations.

Centuri enters into a variety of types of contracts customary in the underground utility construction industry. These contracts include unit-priced contracts, unit-priced contracts with revenue caps, and fixed-price (lump sum) contracts. Contracts with caps and fixed-price arrangements can be susceptible to constrained profits, or even losses, especially those contracts that cover an extended-duration performance period. This is due, in part, to the necessity of estimating costs far in advance of the completion date (at bid inception). Unforeseen inflation, or other costs unanticipated at inception, can detrimentally impact profitability for these types of contracts.

A significant reduction in our credit ratings could materially and adversely affect our business, financial condition, and results of operations.

We cannot be certain that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Our credit ratings are subject to change at any time in the discretion of the applicable ratings agencies. Numerous factors, including many which are not within our control, are considered by the ratings agencies in connection with assigning credit ratings.

Any future downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in certain current, as well as future, financings, and our potential pool of investors and funding sources could decrease. A downgrade could require additional support in the form of letters of credit or cash or other collateral and otherwise adversely affect our business, financial condition and results of operations.

Uncertain economic conditions may affect our ability to finance capital expenditures.

Our ability to finance capital expenditures and other matters will depend upon general economic conditions in the capital markets. Declining interest rates are generally believed to be favorable to utilities while rising interest rates are believed to be unfavorable because of the high capital costs of utilities. In addition, our authorized rate of return is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, our authorized rate of return in the future could be reduced. If interest rates are higher than assumed rates, it will be more difficult for us to earn our currently authorized rate of return.

We require numerous permits and other approvals from various federal, state, and local governmental agencies to operate our business; any failure to obtain or maintain required permits or approvals could negatively affect our business and results of operations.

All of our existing and planned development projects require multiple permits. The acquisition, ownership and operation of natural gas pipelines and storage facilities require numerous permits, approvals and certificates from federal, state, and local governmental agencies. Once received, approvals may be subject to litigation, and projects may be delayed or approvals reversed in litigation. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approvals or to comply with any applicable laws or regulations, we may not be able to construct or operate our facilities, or we may be forced to incur additional costs.

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A cybersecurity incident has the potential to disrupt normal business operations, expose sensitive information, and/or lead to physical damages.

As a utility provider, maintaining business operations is critical for our customers, business partners, suppliers, and our employees. A disruption in service could adversely impact the Company’s reputation, ability to provide utility services for our customers, as well as impact the media used to communicate and exchange information both internally and externally.

Our Company processes and stores sensitive information including personal identifiable information, intellectual property, and business proprietary information as part of normal business operations. A cybersecurity breach of this information could expose the Company to monetary and other damages from customers, suppliers, business partners, government agencies, and others. In addition, a breach could increase costs incurred to protect against such risks, introduce financial penalties, and increase regulation for the industry.

Physical damage due to a cybersecurity incident or acts of cyber terrorism could impact utility services provided to our customers and could lead to material liabilities. The Company has taken the initiative in fortifying the core infrastructure that supports the utility services provided to our customers. While these measures do not eliminate the threats, they do provide layers of defense to mitigate these risks. Even though we have insurance coverage in place for cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.

Loss of one or more significant customers could adversely affect the results of the construction services segment.

During 2015, over one-half of the construction services revenues were generated from seven customers. This concentration of risk could be impactful to operating results if construction work slowed or halted with one or more of these customers, if competition for work increased, or if existing contracts were not replaced or extended.

We may pursue acquisitions and other strategic transactions, the success of which may impact our results of operations, cash flows and financial condition.

The integration of acquisitions requires significant time and resources. Investments of resources would be required to support any acquisition, which could result in significant ongoing operating expenses and may divert resources and management attention from other areas of our business. If we fail to successfully integrate companies we acquire, we may not realize the benefits expected from the transaction and goodwill recorded as a result of the acquisition could be impaired. We assess existing goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of an operating segment below its carrying value. We also assess long-lived assets, including intangible assets associated with acquisitions for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets becomes impaired, the impairment charges could have a material impact on our results of operations.

Disruptions in labor relations with Centuri’s employees could adversely affect results of operations.

The majority of Centuri’s labor force is covered by collective bargaining agreements with labor unions, which is typical of the utility construction industry. Labor disruptions, boycotts, strikes, or significant negotiated wage and benefit increases at Centuri, whether due to employee turnover or otherwise, could have a material adverse effect on Centuri’s business and our results of operations and cash flows.

As a holding company, we would depend on our operating subsidiaries to meet financial obligations.

As previously announced, we are pursuing a reorganization into a holding company structure. If the holding company structure is created, Company common stock would be converted into shares of a holding company with no significant assets other than the stock of operating subsidiaries, including Southwest and Centuri. As contemplated, the holding company’s ability to pay dividends to shareholders would be dependent on the ability of its subsidiaries to generate sufficient net income and cash flows to service debt and pay upstream dividends. The ability of the holding company’s subsidiaries to pay upstream dividends and make other distributions would be subject to applicable state law and regulatory restrictions.

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Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

The plant investment of Southwest consists primarily of transmission and distribution mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators, which comprise the pipeline systems and facilities located in and around the communities served. Southwest also includes other properties such as land, buildings, furnishings, work equipment, vehicles, and software systems in plant investment. The northern Nevada and northern California properties of Southwest are referred to as the northern system; the Arizona, southern Nevada, and southern California properties are referred to as the southern system. Several properties are leased by Southwest. Total gas plant, exclusive of leased property, at December 31, 2015 was $6 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.

Substantially all gas main and service lines are constructed across property owned by others under right-of-way grants obtained from the record owners thereof, on the streets and grounds of municipalities under authority conferred by franchises or otherwise, or on public highways or public lands under authority of various federal and state statutes. None of the numerous county and municipal franchises are exclusive, and some are of limited duration. These franchises are renewed regularly as they expire, and Southwest anticipates no serious difficulties in obtaining future renewals.

With respect to the right-of-way grants, Southwest has had continuous and uninterrupted possession and use of all such rights-of-way, and the associated gas mains and service lines, commencing with the initial stages of construction of such facilities. Permits have been obtained from public authorities and other governmental entities in certain instances to cross or to lay facilities along roads and highways. These permits typically are revocable at the election of the grantor and Southwest occasionally must relocate its facilities when requested to do so by the grantor. Permits have also been obtained from railroad companies to cross over or under railroad lands or rights-of-way, which in some instances require annual or other periodic payments and are revocable at the election of the grantors.

Southwest operates two primary pipeline transmission systems:

• a system (including an LNG storage facility) owned by Paiute extending from the Idaho-Nevada border to the Reno, Sparks, and Carson City areas and communities in the Lake Tahoe area in both California and Nevada and other communities in northern and western Nevada; and

• a system extending from the Colorado River at the southern tip of Nevada to the Las Vegas distribution area.

Southwest provides natural gas service in parts of Arizona, Nevada, and California. Service areas in Arizona include most of the central and southern areas of the state including Phoenix, Tucson, Yuma, and surrounding communities. Service areas in northern Nevada include Carson City, Yerington, Fallon, Lovelock, Winnemucca, and Elko. Service areas in southern Nevada include the Las Vegas valley (including Henderson and Boulder City) and Laughlin. Service areas in southern California include Barstow, Big Bear, Needles, and Victorville. Service areas in northern California include the Lake Tahoe area and Truckee.

Information on properties of Centuri can be found in this Form 10-K under Construction Services.

Item 3. LEGAL PROCEEDINGS

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

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The listing of the executive officers of the Company is set forth under Part III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE, which by this reference is incorporated herein.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 16, 2016, there were 14,095 holders of record of common stock, and the market price of the common stock was $59.56. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2015 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

In February 2016, the Board of Directors (“Board”) increased the quarterly dividend payout to 45 cents per share, effective with the June 2016 payment. This marks the tenth consecutive year in which the dividend was increased. The Board’s policy is to target a dividend payout ratio that allows the Company to maintain its strong credit ratings and effectively fund its rate base growth and is consistent with the local distribution company peer group average. The timing and amount of any increases will be based upon the Board’s continual review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects. The quarterly common stock dividend declared was 33 cents per share throughout 2013, 36.5 cents per share throughout 2014, and 40.5 cents per share throughout 2015.

Item 6. SELECTED FINANCIAL DATA

Information required by this item is included in the 2015 Annual Report to Shareholders and is incorporated herein by reference.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information required by this item is included in the 2015 Annual Report to Shareholders and is incorporated herein by reference.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various forms of market risk, including commodity price risk, weather risk, interest rate risk, and foreign currency exchange rate risk. The following describes the Company’s exposure to these risks.

Commodity Price Risk

In managing its natural gas supply portfolios, Southwest has historically entered into short duration (generally one year or less) fixed-price contracts and variable-price contracts (firm and spot). Southwest has experienced price volatility over the past several years and such volatility is expected to continue into 2016 and beyond.

Southwest is protected financially from commodity price risk by deferred energy or purchased gas adjustment (collectively “PGA”) mechanisms in each of its jurisdictions. These mechanisms generally allow Southwest to defer over- or under-collections of gas costs to PGA balancing accounts. With regulatory approval, Southwest can either refund amounts over-collected or recoup amounts under-collected in future periods. In addition to the PGA mechanism, Southwest utilizes volatility mitigation programs to attempt to further reduce price volatility for customers. Under these programs, Southwest fixes the price of a portion (up to 25% in the Arizona and California jurisdictions) of its natural gas portfolio using fixed-price contracts and/or derivative instruments (fixed-for-floating swaps), and where available, natural gas storage.

In late 2013, the Company suspended using swaps and fixed-price purchases pursuant to the Volatility Mitigation Program for its Nevada service territories. The Company along with its regulators will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

Southwest’s natural gas purchasing practices are subject to prudence review by the various regulatory bodies in each jurisdiction. PGA changes affect cash flows and potentially short-term borrowing requirements, but do not directly impact profit margin.

Weather Risk

Rate design is the primary mechanism available to Southwest to mitigate weather risk. All of Southwest’s service territories have decoupled rate structures which mitigate weather risk. In California, CPUC regulations allow Southwest to

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decouple operating margin from usage and offset weather risk. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin by insulating the Company from the effects of lower usage (including volumes associated with unusual weather). In Arizona, a full revenue decoupling mechanism, which includes a winter-period monthly weather adjuster, is in place for most customer classes. With decoupled rate structures, Southwest’s operating margin is limited during unusually cold weather. Additionally, Southwest is not assured that decoupled rate structures will continue to be supported in future rate cases.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. The primary interest rate risk for the Company is the risk of increasing interest rates on variable-rate obligations. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. In Nevada, fluctuations in interest rates on $150 million of variable-rate Industrial Development Revenue Bonds (“IDRBs”) are tracked and recovered from ratepayers through an interest balancing account, which mitigates risk to earnings and cash flows from interest rate fluctuations on these IDRBs between general rate cases. As of December 31, 2015 and 2014, Southwest had $218 million and $205 million, respectively, in variable-rate debt outstanding, excluding the IDRBs noted above. Assuming a constant outstanding balance on variable-rate debt for the next twelve months, a hypothetical 1% change in interest rates would increase or decrease interest expense for the next twelve months by approximately $2,180,000. As of December 31, 2015 and 2014, Centuri had approximately $173 million and $200 million in variable-rate debt outstanding. Assuming a constant outstanding balance in variable-rate debt for the next twelve months, a hypothetical 1% change in interest rates would increase or decrease interest expense for the next twelve months by approximately $1,730,000.

Foreign Currency Exchange Rate Risk

The Company, through its subsidiaries, owns businesses that operate in Canada. Due to these operations, the Company is exposed to market risk associated with foreign currency exchange rate fluctuations between the Canadian dollar and the U.S. dollar. Foreign currency translation risk is the risk that exchange rate gains or losses arise from translating foreign entities’ statements of income and balance sheets from their functional currency (the Canadian Dollar) to the Company’s reporting currency (the U.S. Dollar) for consolidation purposes. During 2015, translation adjustments due to fluctuations in exchange rates were not significant. The Company does not have exposure to other foreign currency exchange rate fluctuations.

Other risk information is included in Item 1A. Risk Factors of this report.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements of Southwest Gas Corporation and Subsidiaries and Notes thereto, together with the report of PricewaterhouseCoopers LLP, are included in the 2015 Annual Report to Shareholders and are incorporated herein by reference.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

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Based on the most recent evaluation, as of December 31, 2015, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.

Internal Control Over Financial Reporting

The report of management of the Company required to be reported herein is incorporated by reference to the information reported in the 2015 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 82.

The Attestation Report of the Independent Registered Public Accounting Firm required to be reported herein is incorporated by reference to the information reported in the 2015 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 83.

There have been no changes in the Company’s internal controls over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) that occurred during the most recent fiscal quarter that have materially affected or that are reasonably likely to materially affect the Company’s internal control over financial reporting.

In January 2016, the Company implemented a financial systems modernization project which involved replacing or changing several financial systems currently utilized by the natural gas operations segment, including the replacement of the current general ledger system. The modernized systems are being used for transactions in 2016, but were not utilized in preparing 2015 financial information. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes are being conducted to enable management to evaluate the design and effectiveness of internal controls during 2016.

Item 9B. OTHER INFORMATION

In 2015, the Board of Directors (“Board”) of the Company authorized management to evaluate and pursue a holding company reorganization. Regulatory applications for preapproval of the reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. In January 2016, approval was received by the CPUC, but approvals by the ACC and the PUCN are still pending. Following the reorganization, the Company would be a wholly owned subsidiary of the new parent holding company (“HoldCo”), and the Company’s 96.6% interest in Centuri would be held by HoldCo.

Upon consummation of the reorganization, each outstanding share of Southwest Gas Corporation common stock would automatically convert into a share of common stock of HoldCo on a one-for-one basis. Shareholders of Southwest Gas Corporation immediately prior to consummation of the reorganization would own the same relative percentages of HoldCo upon the consummation of the reorganization. Shareholder approval is not required to consummate the reorganization under the provisions of the California Corporations Code. The reorganization would not result in any new tax liabilities for the Company or its stakeholders, including shareholders.

The reorganization is subject to approval by the aforementioned state regulatory commissions, consents from various third parties, and final Board approval. Subject to such conditions, the reorganization could become effective in the second half of 2016.

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

(a) Identification of Directors. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

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(b) Identification of Executive Officers. The name, age, position, and period position held during the last five years for each of the Executive Officers of the Company as of December 31, 2015 are as follows:

Name	Age	Position	Period Position Held
John P. Hester	53	President and Chief Executive Officer President Executive Vice President Senior Vice President/Regulatory Affairs & Energy Resources	2015-Present 2014-2015 2013-2014 2011-2013
William N. Moody	59	Executive Vice President Senior Vice President/Staff Operations & Technology Vice President/Gas Resources	2013-Present 2012-2013 2011-2012
Roy R. Centrella	58	Senior Vice President/Chief Financial Officer	2011-Present
Eric DeBonis	48	Senior Vice President/Operations Senior Vice President/Staff Operations & Technology Vice President/Special Projects	2012-Present 2011-2012 2011
Karen S. Haller	52	Senior Vice President/General Counsel and Corporate Secretary Vice President/General Counsel, Compliance Officer, and Corporate Secretary	2012-Present 2011-2012
Edward A. Janov	61	Senior Vice President/Corporate Development	2011-Present
Anita M. Romero	53	Senior Vice President/Staff Operations & Technology Vice President/Information Services Vice President/Special Projects Vice President/Southern Nevada Division	2013-Present 2012-2013 2011-2012 2011
Kenneth J. Kenny	53	Vice President/Finance/Treasurer	2011-Present
Gregory J. Peterson	56	Vice President/Controller and Chief Accounting Officer	2011-Present

(c) Identification of Certain Significant Employees. None.

(d) Family Relationships. No Directors or Executive Officers are related either by blood, marriage, or adoption.

(e) Business Experience. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein. All Executive Officers have held responsible positions with the Company for at least five years as described in (b) above.

(f) Involvement in Certain Legal Proceedings. None.

(g) Promoters and Control Persons. None.

(h) Audit Committee Financial Expert. Information with respect to the financial expert of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(i) Identification of the Audit Committee. Information with respect to the composition of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(j) Material Changes in Director Nomination Procedures for Security Holders. None.

Section 16(a) Beneficial Ownership Reporting Compliance. The Company has adopted procedures to assist its directors and executive officers in complying with Section 16(a) of the Exchange Act which includes assisting in the preparation of forms for filing. Based upon a review of filings with the SEC and written representations that no other reports were required, the Company believes that all of its directors and executive officers complied during 2015 with the reporting requirements of Section 16(a) of the Exchange Act.

Code of Business Conduct and Ethics. The Company has adopted a code of business conduct and ethics for its employees, including its president and chief executive officer, chief financial officer, chief accounting officer, and non-employee directors. A code of ethics is defined as written standards that are reasonably designed to deter wrongdoing and to promote: 1) honest and ethical conduct; 2) full, fair, accurate, timely, and understandable disclosure in reports and documents

17

that a registrant files; 3) compliance with applicable governmental laws, rules, and regulations; 4) the prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and 5) accountability for adherence to the code. The Company’s Code of Business Conduct and Ethics can be viewed on the Company’s website (www.swgas.com). If any substantive amendments to the Code of Business Conduct and Ethics are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct & Ethics, to the Company’s president and chief executive officer, chief financial officer and chief accounting officer, the Company will disclose the nature of such amendment or waiver on the Company’s website, www.swgas.com.

Item 11. EXECUTIVE COMPENSATION

Information with respect to executive compensation is set forth under the heading “Executive Compensation” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(a) Compensation Committee Interlocks and Insider Participation. Information with respect to Compensation Committee interlocks and insider participation is set forth under the heading “Governance of the Company” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(b) Compensation Committee Report. Information with respect to the Compensation Committee Report is set forth under the heading “Compensation Committee Report” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(a) Security Ownership of Certain Beneficial Owners. Information with respect to security ownership of certain beneficial owners is set forth under the heading “Securities Ownership by Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(b) Security Ownership of Management. Information with respect to security ownership of management is set forth under the heading “Securities Ownership by Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

(c) Changes in Control. None.

(d) Securities Authorized for Issuance Under Equity Compensation Plans.

At December 31, 2015, the Company had three stock-based compensation plans. With respect to the first plan, the Company previously granted options to purchase shares of common stock to key employees and outside directors. The option grants in 2006 consumed the remaining options that could be issued under the option plan and no future grants are anticipated.

Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance (excluding securities reflected in column a)
	(a)		(b)		(c)
(Thousands of shares)
Equity compensation plans approved by security holders		17	$	31.64		—
Equity compensation plans not approved by security holders		—		—		—
Total		17	$	31.64		—

Pursuant to the terms of the management incentive plan, the Company may issue performance shares to encourage key employees to remain in its employment to achieve short-term and long-term performance goals.

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Plan category	Number of securities to be issued upon vesting of performance shares		Weighted-average grant date fair value of award		Number of securities remaining available for future issuance (excluding securities reflected in column a)
	(a)		(b)		(c)
(Thousands of shares)
Equity compensation plans approved by security holders		197	$	50.63		844
Equity compensation plans not approved by security holders		—		—		—
Total		197	$	50.63		844

Pursuant to the terms of the restricted stock/unit plan, the Company may award restricted stock and restricted stock units to attract, motivate, retain and reward key employees with incentives for high levels of individual performance and improved financial performance of the Company and to attract, motivate, and retain experienced and knowledgeable independent directors.

Plan category	Number of securities to be issued upon vesting of restricted stock units		Weighted-average grant date fair value of award		Number of securities remaining available for future issuance (excluding securities reflected in column a)
	(a)		(b)		(c)
(Thousands of shares)
Equity compensation plans approved by security holders		228	$	44.36		32
Equity compensation plans not approved by security holders		—		—		—
Total		228	$	44.36		32

Additional information regarding the three equity compensation plans is included in Note 11 of the Notes to Consolidated Financial Statements in the 2015 Annual Report to Shareholders.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information with respect to certain relationships and related transactions, and director independence is set forth under the heading “Governance of the Company” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information with respect to accounting fees and services associated with PricewaterhouseCoopers LLP is set forth under the heading “Selection of Independent Registered Public Accounting Firm” in the definitive 2016 Proxy Statement, which by this reference is incorporated herein.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report on Form 10-K:

(1) The Consolidated Financial Statements of the Company (including the Report of Independent Registered Public Accounting Firm) required to be reported herein are incorporated by reference to the information reported in the 2015 Annual Report to Shareholders under the following captions:

Consolidated Balance Sheets	34
Consolidated Statements of Income	36
Consolidated Statements of Comprehensive Income	37
Consolidated Statements of Cash Flows	38
Consolidated Statements of Equity and Redeemable Noncontrolling Interest	40
Notes to Consolidated Financial Statements	42
Management’s Report on Internal Control Over Financial Reporting	82
Report of Independent Registered Public Accounting Firm	83

(2) All schedules have been omitted because the required information is either inapplicable or included in the Notes to Consolidated Financial Statements.

(3) See LIST OF EXHIBITS.

(b) See LIST OF EXHIBITS.

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LIST OF EXHIBITS

Exhibit Number	Description of Document
1.01	Sales Agency Agreement between Southwest Gas Corporation and BNY Mellon Capital Markets, LLC. Incorporated by reference to Exhibit 1.1 to Form S-3ASR dated March 10, 2015, File No. 333-202633.
3(i)	Restated Articles of Incorporation, as amended. Incorporated herein by reference to Exhibit 3(i) to Form 10–Q for the quarter ended September 30, 2007, File No. 1-07850.
3(ii)	Amended Bylaws of Southwest Gas Corporation. Incorporated herein by reference to Exhibit 3(ii) to Form 8–K dated July 31, 2012, File No. 1-07850.
4.01	Indenture between City of Big Bear Lake, California, and Harris Trust and Savings Bank as Trustee, dated December 1, 1993, with respect to the issuance of $50,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation Project), 1993 Series A, due 2028. Incorporated herein by reference to Exhibit 4.11 to Form 10-K for the year ended December 31, 1993, File No. 1-07850.
4.02	Indenture between the Company and Harris Trust and Savings Bank dated July 15, 1996, with respect to Debt Securities. Incorporated herein by reference to Exhibit 4.04 to Form 8-K dated July 26, 1996, File No. 1–07850.
4.03	First Supplemental Indenture of the Company to Harris Trust and Savings Bank dated August 1, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to 7 1/2% and 8% Debentures, due 2006 and 2026, respectively. Incorporated herein by reference to Exhibit 4.11 to Form 8-K dated July 31, 1996, File No. 1-07850.
4.04	Second Supplemental Indenture of the Company to Harris Trust and Savings Bank dated December 30, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to Medium-Term Notes. Incorporated herein by reference to Exhibit 4.04 to Form 8-K dated December 30, 1996, File No. 1–07850.
4.05	Certificate of Trust of Southwest Gas Capital III. Incorporated herein by reference to Exhibit 4.04 to Form S–3 dated August 7, 2003, File No. 333-106419.
4.06	Certificate of Trust of Southwest Gas Capital IV. Incorporated herein by reference to Exhibit 4.05 to Form S–3 dated August 7, 2003, File No. 333-106419.
4.07	Trust Agreement of Southwest Gas Capital III. Incorporated herein by reference to Exhibit 4.07 to Form S-3 dated August 7, 2003, File No. 333-106419.
4.08	Trust Agreement of Southwest Gas Capital IV. Incorporated herein by reference to Exhibit 4.08 to Form S-3 dated August 7, 2003, File No. 333-106419.
4.09	Form of Common Stock Certificate. Incorporated herein by reference to Exhibit 4 to Form 8-K dated July 22, 2003, File No. 1-07850.
4.10	Indenture of Trust between Clark County, Nevada, and the Bank of New York Trust Company, N.A. as Trustee, dated as of October 1, 2005, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2005A. Incorporated herein by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005, File No. 1-07850.
4.11	Indenture of Trust between Clark County, Nevada, and the Bank of New York Trust Company, N.A. as Trustee, dated as of September 1, 2006, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2006A. Incorporated herein by reference to Exhibit 4.01 to Form 10-Q for the quarter ended September 30, 2006, File No. 1-07850.

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Exhibit Number	Description of Document
4.12	Indenture of Trust between Clark County, Nevada, and the BNY Midwest Trust Company, as Trustee, dated as of March 1, 2003, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2003. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850.
4.13	Indenture of Trust between Clark County, Nevada and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated as of September 1, 2008, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2008A. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850.
4.14	Indenture of Trust between Clark County, Nevada and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated December 1, 2009, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2009A. Incorporated herein by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2009, File No. 1-07850.
4.15	Note Purchase Agreement, dated November 18, 2010, by and between the Company and Metropolitan Life Insurance Company, John Hancock Life Insurance Company (U.S.A.), certain of their respective affiliates, and Union Fidelity Life Insurance Company. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated November 18, 2010, File No. 1-07850.
4.16	Amendment No. 1 to Note Purchase Agreement, dated March 28, 2014, by and among Southwest Gas Corporation and the holders of the Notes. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated March 31, 2014, File No. 1–07850.
4.17	Form of 6.1% Senior Note due 2041. Incorporated herein by reference to Exhibit 4.2 to Form 8-K dated November 18, 2010, File No. 1-07850.
4.18	Indenture, dated December 7, 2010, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 7, 2010, File No. 1-07850.
4.19	First Supplemental Indenture, dated as of December 10, 2010, supplementing and amending the indenture dated as of December 7, 2010, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (including the Form of 4.45% Senior Notes due 2020). Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 10, 2010, File No. 1-07850.
4.20	Indenture, dated March 23, 2012, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. 3.875% Notes due 2022. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated March 20, 2012, File No. 1-07850.
4.21	Indenture, dated as of October 4, 2013, by and between Southwest Gas Corporation and the Bank of New York Mellon Trust Company, N.A., as Trustee. 4.875% Notes due 2043. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 1, 2013. File No. 1-07850.
4.22	Southwest Gas Corporation Dividend Reinvestment and Direct Stock Purchase Plan. Incorporated by reference to Exhibit 4.4 to Form S-3ASR dated December 18, 2015, File No. 333-208609.
4.23	The Company hereby agrees to furnish to the SEC, upon request, a copy of any instruments defining the rights of holders of long-term debt issued by Southwest Gas Corporation or its subsidiaries; the total amount of securities authorized thereunder does not exceed 10% of the consolidated total assets of Southwest Gas Corporation and its subsidiaries.

22

Exhibit Number	Description of Document
10.01	Project Agreement between the Company and City of Big Bear Lake, California, dated as of December 1, 1993. Incorporated herein by reference to Exhibit 10.05 to Form 10-K for the year ended December 31, 1993, File No. 1-07850.
10.02 *	Southwest Gas Corporation Supplemental Retirement Plan, amended and restated as of January 1, 2005. Incorporated herein by reference to Exhibit 10.03 to Form 10-K for the year ended December 31, 2007, File No. 1–07850.
10.03 *	Southwest Gas Corporation Board of Directors Retirement Plan, amended and restated as of January 1, 2005. Incorporated herein by reference to Exhibit 10.04 to Form 10-K for the year ended December 31, 2007, File No. 1-07850.
10.04 *	Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated November 14, 2013, File No. 1-07850.
10.05 *	Southwest Gas Corporation Management Incentive Plan, amended and restated. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 26, 2014, File No. 1–07850.
10.06 *	Southwest Gas Corporation 2002 Stock Incentive Plan. Incorporated herein by reference to the Proxy Statement dated April 2, 2002, File No. 1-07850. Southwest Gas Corporation 1996 Stock Incentive Plan. Incorporated herein by reference to Appendix C to the Proxy Statement dated May 30, 1996, File No. 1–07850.
10.07 *	Southwest Gas Corporation Executive Deferral Plan, amended and restated March 1, 2008, effective January 1, 2005. Southwest Gas Corporation Executive Deferral Plan, amended and restated effective January 1, 2009. Incorporated herein by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2008, File No. 1-07850.
10.08 *	Southwest Gas Corporation Directors Deferral Plan, amended and restated effective January 1, 2009. Incorporated herein by reference to Exhibit 10.11 to Form 10-K for the year ended December 31, 2008, File No. 1-07850.
10.09	Financing agreement dated as of March 1, 2003 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2003A, Series 2003B, Series 2003C, Series 2003D and Series 2003E. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 2003, File No. 1-07850.
10.10 *	Form of Executive Option Grant under 2002 Stock Incentive Plan. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 2004, File No. 1-07850.
10.11	First Amendment to Financing Agreement by and between Clark County, Nevada, and Southwest Gas Corporation dated as of July 1, 2005, amending the Financing Agreement dated as of March 1, 2003, with respect to Clark County, Nevada Industrial Development Revenue Bonds Series 2003A, Series 2003B, Series 2003C, Series 2003D, and Series 2003E. Incorporated herein by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2005, File No. 1-07850.
10.12	Financing Agreement dated as of October 1, 2005 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2005A. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2005, File No. 1-07850.
10.13	Financing Agreement dated as of September 1, 2006 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2006A. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2006, File No. 1-07850.

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Exhibit Number	Description of Document
10.14	Financing Agreement between Clark County, Nevada, and Southwest Gas Corporation, dated as of September 1, 2008, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2008A. Incorporated herein by reference to Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850.
10.15	Financing Agreement between Clark County, Nevada and Southwest Gas Corporation, dated December 1, 2009, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2009A. Incorporated herein by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 2009, File No. 1-07850.
10.16	$300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 15, 2012, File No. 1-07850.
10.17	Amendment No. 1 to Revolving Credit Agreement, dated as of March 25, 2014, by and among Southwest Gas Corporation, each of the lenders parties to the Revolving Credit Agreement referred to therein, and the Bank of New York Mellon, as Administrative Agent. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 25, 2014, File No. 1–07850.
10.18	Amendment No. 2 to Revolving Credit Agreement, dated as of March 25, 2015, by and among Southwest Gas Corporation, each of the lenders parties to the Revolving Credit Agreement referred to therein, and the Bank of New York Mellon, as Administrative Agent. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 24, 2015, File No. 1–07850.
10.19 *	Southwest Gas Corporation 2006 Restricted Stock/Unit Plan, as amended and restated. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 28, 2012, File No. 1-07850.
10.20	NPL (Centuri) $300 million Credit Facility Agreement. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2014, File No. 1-07850.
10.21	Amendment No. 1 to Credit Agreement, dated as of January 13, 2016, by and among NPL Construction Co. and Centuri Construction Group, Inc., as US Borrowers, Lynxus Construction Group Inc., a corporation organized under the laws of the Province of Ontario, Canada, as Canadian Borrower, the Lenders party thereto, and Wells Fargo Bank, as Administrative Agent.
12.01	Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.
13.01	Portions of 2015 Annual Report to Shareholders incorporated by reference to the Form 10-K.
21.01	List of subsidiaries of Southwest Gas Corporation.
23.01	Consent of PricewaterhouseCoopers LLP, an independent registered public accounting firm.
31.01	Section 302 Certifications.
32.01	Section 906 Certifications.
101.01	The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in Extensible Business Reporting Language (“XBRL”): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows, (v) the Consolidated Statements of Equity and Redeemable Noncontrolling Interest, and (vi) the Notes to the Consolidated Financial Statements.

* Management Contracts or Compensation Plans

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHWEST GAS CORPORATION
Date: February 25, 2016	By	/S/ JOHN P. HESTER
		John P. Hester
		President and Chief Executive Officer

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/S/ ROBERT L. BOUGHNER (Robert L. Boughner)	Director	February 25, 2016
/S/ JOSÉ A. CÁRDENAS (José A. Cárdenas)	Director	February 25, 2016
/S/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	February 25, 2016
/S/ STEPHEN C. COMER (Stephen C. Comer)	Director	February 25, 2016
/S/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	February 25, 2016
/S/ JOHN P. HESTER (John P. Hester)	Director, President and Chief Executive Officer	February 25, 2016
/S/ ANNE L. MARIUCCI (Anne L. Mariucci)	Director	February 25, 2016
/S/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Chairman of the Board of Directors	February 25, 2016
/S/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director	February 25, 2016
/S/ A. RANDALL THOMAN (A. Randall Thoman)	Director	February 25, 2016
/S/ THOMAS A. THOMAS (Thomas A. Thomas)	Director	February 25, 2016
/S/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	February 25, 2016
/S/ ROY R. CENTRELLA (Roy R. Centrella)	Senior Vice President/ Chief Financial Officer	February 25, 2016
/S/ GREGORY J. PETERSON (Gregory J. Peterson)	Vice President, Controller, and Chief Accounting Officer	February 25, 2016

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EX-10.21

Exhibit 10.21

EXECUTION COPY

FIRST AMENDMENT TO CREDIT AGREEMENT

Dated as of January 13, 2016

This FIRST AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) is by and among NPL CONSTRUCTION CO., a Nevada corporation and CENTURI CONSTRUCTION GROUP, INC. (formerly known as Isleworth Holding Co.), a Nevada corporation, as US Borrowers, LYNXUS CONSTRUCTION GROUP INC. (formerly known as 2431251 Ontario Inc.), a corporation organized under the laws of the Province of Ontario, Canada, as Canadian Borrower, the Lenders party hereto, and WELLS FARGO BANK, NATIONAL ASSOCIATION, a national banking association, as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

PRELIMINARY STATEMENTS

WHEREAS, the Borrowers, the lenders party thereto (the “Lenders”) and the Administrative Agent entered into that certain Credit Agreement dated as of October 1, 2014 (as amended hereby and as further amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”); and

WHEREAS, the Borrowers have requested that the Administrative Agent and the Lenders agree to amend the Credit Agreement as specifically set forth herein and, subject to the terms of this Amendment, the Administrative Agent and the Lenders party hereto have agreed to grant such request.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto hereby agree as follows:

Section 1.    Capitalized Terms.    All capitalized terms not otherwise defined in this Amendment (including without limitation in the introductory paragraph and the Preliminary Statements hereto) shall have the meanings as specified in the Credit Agreement.

Section 2.    Amendment to Credit Agreement.    Subject to and in accordance with the terms and conditions set forth herein, the Administrative Agent and the Lenders party hereto hereby agree to amend the Credit Agreement as follows:

(a)    The cover page to the Credit Agreement is hereby amended by: (i) replacing “ISLEWORTH HOLDING CO.” with “CENTURI CONSTRUCTION GROUP, INC. (formerly known as Isleworth Holding Co.)” and (ii) replacing “2431251 ONTARIO INC.” with “LYNXUS CONSTRUCTION GROUP INC. (formerly known as 2431251 Ontario Inc.)”.

(b)    The preamble to the Credit Agreement is hereby amended by: (i) replacing “ISLEWORTH HOLDING CO.” with “CENTURI CONSTRUCTION GROUP, INC. (formerly known as Isleworth Holding Co.)” and (ii) replacing “2431251 ONTARIO INC.” with “LYNXUS CONSTRUCTION GROUP INC. (formerly known as 2431251 Ontario Inc.)”.

(c)    The listing of Schedules in the Credit Agreement is hereby amended to delete the following:

“Schedule 12.22 – Holding Company Reorganization Description”

(d)    The definition of “Adjusted Consolidated Net Income” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Adjusted Consolidated Net Income” means Consolidated Net Income for the applicable period, but excluding in calculating Consolidated Net Income (solely to the extent Consolidated Net Income for such period is greater than $0), (a) impairment charges with respect to intangible assets and non-cash charges related to deferred taxes in an aggregate amount of up to $10,000,000 accrued for the applicable period of calculation and (b) amortization of goodwill in an aggregate amount of up to $20,000,000 accrued for the applicable period of calculation.

(e)    The definition of “Base Rate” in Section 1.1 of the Credit Agreement is hereby amended by replacing each reference therein to “LIBOR” with “the LIBOR Rate”.

(f)    The definition of “Canadian Borrower” in Section 1.1 of the Credit Agreement is hereby amended by replacing “2431251 Ontario Inc.” with “Lynxus Construction Group Inc. (formerly known as 2431251 Ontario Inc.)”.

(g)    The definition of “Carson Water” in Section 1.1 of the Credit Agreement is hereby amended by inserting the following phrase at the end of such definition:

“, and, after the Holding Company Reorganization, a direct Subsidiary of the Holding Company”

(h)    Section 1.1 of the Credit Agreement is hereby amended by adding the following additional defined term in appropriate alphabetical order:

“Centuri” means Centuri Construction Group, Inc. (formerly known as Isleworth Holding Co.), a Nevada corporation.

(i)    The definition of “Change in Control” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Change in Control” means an event or series of events by which:

(a)    prior to the Holding Company Reorganization, (i) Southwest Gas shall fail to own, directly or indirectly, and control at least ninety-six percent (96%) on a fully diluted basis of the economic and voting Equity Interests of Centuri, and (ii) Centuri shall fail to own, directly or indirectly, and control (A) one hundred percent (100%) on a fully diluted basis of the economic and voting Equity Interests of NPL, and (B) one hundred percent (100%) on a fully diluted basis of the economic and voting Equity Interests of the Canadian Borrower; and

(b)    after the Holding Company Reorganization, (i) Centuri shall fail to own, directly or indirectly, and control (A) one hundred percent (100%) on a fully diluted basis of the economic and voting Equity Interests of NPL, and (B) one hundred percent (100%) on a fully diluted basis of the economic and voting Equity Interests of the Canadian Borrower or (ii) the Holding Company shall fail to own, directly or indirectly, and control one hundred percent (100%) on a fully diluted basis of the economic and voting Equity Interests of each of the Borrowers.

2

(j)    The definition of “Consolidated Companies” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Consolidated Companies” means Centuri and its Subsidiaries.

(k)    The definition of “Consolidated EBITDA” in Section 1.1 of the Credit Agreement is hereby amended by replacing clause (iii) with the following new clause (iii):

“(iii) amortization (including, for the avoidance of doubt, impairment charges, and amortization of goodwill and intangible assets acquired or arising from a business acquisition, regardless of whether presented as a separate line item or included in other book entries), depreciation and other non-cash charges (except to the extent that such non-cash charges are reserved for cash charges to be taken in the future), including any non-cash equity based compensation expense,”

(l)    Section 1.1 of the Credit Agreement is hereby amended by adding the following additional defined term in appropriate alphabetical order:

“First Amendment Effective Date” means January 13, 2016.

(m)    The definition of “Holding Company” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Holding Company” means a California corporation the common Equity Interests of which are owned 100% by the existing shareholders of Southwest Gas immediately prior to the consummation of the Holding Company Reorganization.

(n)    The definition of “Holding Company Reorganization” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Holding Company Reorganization” means the organizational reorganization of the Consolidated Companies following the First Amendment Effective Date and on substantially the terms described in the Form 8-K filed by Southwest Gas on October 13, 2015 in which, along with other organizational changes, Southwest Gas will be replaced by the Holding Company as the ultimate parent company, Southwest Gas will become an indirect Subsidiary of the Holding Company, Carson Water will become a direct Subsidiary of the Holding Company, and Centuri shall continue to own all of the Equity Interests of the Subsidiaries of Centuri (including NPL and the Canadian Borrower) immediately prior to the consummation of the Holding Company Reorganization, all subject to compliance with Section 12.22.

(o)    The definition of “LIBOR Rate” in Section 1.1 of the Credit Agreement is hereby amended by inserting the following sentence at the end of such definition:

“Notwithstanding the foregoing, if the LIBOR Rate shall be less than zero, such rate shall be deemed to be zero for purposes of this Agreement.”

(p)    The last sentence of the definition of “Subsidiary” in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

3

“Unless otherwise qualified, references to “Subsidiary” or “Subsidiaries” herein shall refer to those of Centuri.”

(q)    The definition of “US Borrowers” in Section 1.1 of the Credit Agreement is hereby amended by replacing “Isleworth Holding Co., a Nevada corporation” in clause (b) with “Centuri”.

(r)    The definition of “US Credit Parties” is hereby amended by deleting “and, after the Holding Company Reorganization, the Holding Company”.

(s)    Section 1.3 of the Credit Agreement is hereby amended by deleting clause (d) in its entirety.

(t)    Section 7.20 of the Credit Agreement is hereby amended by inserting the following sentences at the end of such Section:

“Each Credit Party, its Subsidiaries and their respective officers and employees and to the knowledge of each Credit Party, its directors and agents, are in compliance with Anti-Corruption Laws and applicable Sanctions in all material respects. No Loan or Letter of Credit, use of the proceeds of any Loan or Letter of Credit or other transactions contemplated hereby will violate Anti-Corruption Laws or applicable Sanctions. Each Credit Party and its Subsidiaries are in compliance in all material respects with all Anti-Corruption Laws and the PATRIOT Act.”

(u)    Section 8.15 of the Credit Agreement is hereby amended by inserting the following sentence at the end of such Section:

“The Borrower will not request any Extension of Credit, and the Borrower shall not use, and shall ensure that its Subsidiaries and its or their respective directors, officers, employees and agents shall not use, the proceeds of any Extension of Credit (i) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws or (ii) in any manner that would result in the violation of any Sanctions applicable to any party hereto.”

(v)    Clause (d) of Section 9.1 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(d)    Indebtedness incurred in connection with Capital Leases and purchase money Indebtedness and incurred in the ordinary course of business of the Consolidated Companies in an aggregate amount not to exceed $65,000,000 at any time outstanding; provided that (i) such Indebtedness is incurred concurrently with or within twenty-four (24) months after the applicable acquisition, construction, repair, replacement or improvement and (ii) no more than $45,000,000 of such Indebtedness may be incurred during any twelve (12) month period;”

(w)    Clause (h) of Section 9.2 of the Credit Agreement is hereby amended by replacing, in clause (i) thereof, “substantially simultaneously with” with “concurrently with or within twenty-four (24) months of”.

4

(x)    Section 9.3 of the Credit Agreement is hereby amended by: (i) adding “and” after the semicolon in clause (vi), (ii) replacing “; and” at the end of clause (vii) with a period and (iii) deleting clause (viii) in its entirety.

(y)    Clause (i) of Section 9.4 of the Credit Agreement is hereby amended by replacing “a” with “the”.

(z)    Clause (viii) of Section 9.7 of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(viii) customary overhead allocations and intercompany charges applied by Centuri on a consistent basis to its Subsidiaries generally.”

(aa)    Clause (b) of Section 9.8 of the Credit Agreement is hereby amended by deleting “except to effectuate a Holding Company Reorganization,”.

(bb)    Clause (i) of Section 10.1 of the Credit Agreement is hereby amended by inserting “ (or, after the Holding Company Reorganization, the Holding Company or any Subsidiary thereof)” after “Southwest Gas”.

(cc)    Clause (j) of Section 10.1 of the Credit Agreement is hereby amended by inserting “ (or, after the Holding Company Reorganization, the Holding Company or any Subsidiary thereof)” after both references to “Southwest Gas”.

(dd)    Section 12.1 of the Credit Agreement is hereby amended by: (i) replacing “NPL Construction Co.” in 12.1(a) with “Centuri Construction Group, Inc.”, (ii) replacing “rpingle@GoNPL.com” in 12.1(a) with “rpringle@NextCenturi.com”, and (iii) replacing “NPL” in 12.1(c) with “Centuri”.

(ee)    Section 12.22 of the Credit Agreement is hereby amended by: (i) replacing each reference to “NPL” with “Centuri”, (ii) inserting “and” after the semicolon in clause (a)(i), (iii) inserting “(or such shorter period as agreed to by the Administrative Agent in its sole discretion)” after “thirty (30) days” in clause (a)(ii), (iv) replacing the semicolon at the end of clause (a)(ii) with a period, (v) deleting clauses (a)(iii) and (a)(iv) in their entirety and (vi) deleting clause (d) in its entirety.

Section 3.     Conditions of Effectiveness.    The effectiveness of the amendments in Section 2 shall be subject to the satisfaction of each of the following conditions precedent:

(a)    the Administrative Agent shall have received counterparts of this Amendment executed by each Borrower, each other Credit Party, the Administrative Agent and the Required Lenders;

(b)    the representations and warranties of the Credit Parties contained in Section 4 shall be true and correct; and

(c)    all reasonable out-of-pocket costs and expenses incurred by the Administrative Agent as of the date hereof in connection with the preparation, negotiation, execution and delivery of this Amendment and the other instruments and documents to be delivered hereunder (including, without limitation, the reasonable fees, charges and disbursements of legal counsel for the Administrative Agent in connection with the preparation, negotiation, execution and delivery of this Amendment) shall have been paid by the Borrowers.

5

Section 4.    Representations and Warranties of the Credit Parties.    Each Credit Party represents and warrants as follows:

(a)    Each Credit Party has the right, power, and authority and has taken all necessary corporate or other action to authorize the execution, delivery and performance of this Amendment. This Amendment constitutes a legal, valid and binding obligation of such Credit Party, enforceable against each Credit Party that is party hereto in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

(b)    The execution, delivery and performance by each Credit Party of this Amendment and the transactions contemplated hereby do not and will not, by the passage of time, the giving of notice or otherwise, (i) require any Governmental Approval or violate any Applicable Law relating to any Credit Party or any Subsidiary thereof where the failure to obtain such Governmental Approval or such violation could reasonably be expected to have a Material Adverse Effect, (ii) conflict with, result in a breach of or constitute a default under the articles of incorporation, bylaws or other organizational documents of any Credit Party or any Subsidiary thereof, (iii) conflict with, result in a breach of or constitute a default under any indenture, agreement or other instrument to which such Person is a party or by which any of its properties may be bound or any Governmental Approval relating to such Person, which could, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect, (iv) result in or require the creation or imposition of any Lien upon or with respect to any property now owned or hereafter acquired by such Person other than Permitted Liens or (v) require any consent or authorization of, filing with, or other act in respect of, an arbitrator or Governmental Authority and no consent of any other Person is required in connection with the execution, delivery, performance, validity or enforceability of this Amendment other than consents, authorizations, filings or other acts or consents for which the failure to obtain or make could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

(c)    After giving effect to this Amendment, the representations and warranties contained in each of the Loan Documents are true and correct in all material respects, except for any representation and warranty that is qualified by materiality or reference to Material Adverse Effect, which such representation and warranty are true and correct in all respects, on and as of the date hereof as though made on and as of such date (other than any such representations or warranties that, by their terms, refer to a specific date, in which case as of such specific date).

(d)    No Default or Event of Default shall exist after giving effect to this Amendment.

Section 5.    Reference to and Effect on the Loan Documents.    On and after the effectiveness of this Amendment, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in each of the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement, as amended by this Amendment and this Amendment shall constitute a Loan Document.

(a)    The Credit Agreement and each of the other Loan Documents, as specifically amended by this Amendment, are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.

(b)    The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the

6

Administrative Agent under any of the Loan Documents, nor constitute a waiver of any other provision of any of the Loan Documents.

Section 6.    Reaffirmations.    Each Credit Party (a) consents to this Amendment and agrees that the transactions contemplated by this Amendment shall not limit or diminish the obligations of such Person, or release such Person from any obligations, under any of the Loan Documents to which it is a party, (b) confirms and reaffirms its obligations under each of the Loan Documents to which it is a party and (c) agrees that each of the Loan Documents to which it is a party remain in full force and effect and are hereby ratified and confirmed.

Section 7.    Execution in Counterparts.    This Amendment may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Amendment by facsimile or in electronic (i.e., “pdf” or “tif”) format shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 8.    Governing Law.    This Amendment and any claim, controversy, dispute or cause of action (whether in contract or tort or otherwise) based upon, arising out of or relating to this Amendment and the transactions contemplated hereby and thereby shall be governed by, and construed in accordance with, the law of the State of New York.

Section 9.    Entire Agreement.    This Amendment and the other Loan Documents, and any separate letter agreements with respect to fees payable to the Administrative Agent, the Issuing Bank, the Swingline Lender and/or the Lead Arrangers, constitute the entire agreement among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof.

[Signature Pages Follow]

7

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized, as of the date first above written.

BORROWERS:
NPL CONSTRUCTION CO., as US Borrower
By:	/s/ RICARDO B. PRINGLE
Name:  Ricardo B. Pringle
Title:    Secretary
CENTURI CONSTRUCTION GROUP, INC., as US Borrower
By:	/s/ KEVIN NEILL
Name:  Kevin Neill
Title:    Senior Vice President/Chief Financial Officer and Treasurer
LYNXUS CONSTRUCTION GROUP INC., as Canadian Borrower
By:	/s/ DEREK A. VAN PATTER
Name:  Derek A. Van Patter
Title:    Secretary
GUARANTORS:
SOUTHWEST ADMINISTRATORS, INC., as a US Subsidiary Guarantor
By:	/s/ RICARDO B. PRINGLE
Name:  Ricardo B. Pringle
Title:    Secretary
VISTUS CONSTRUCTION GROUP, INC., as a US Subsidiary Guarantor
By:	/s/ RICARDO B. PRINGLE
Name:  Ricardo B. Pringle
Title:    Secretary

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

BRIGADIER PIPELINES INC., as a US Subsidiary Guarantor
By:	/s/ RICARDO B. PRINGLE
Name:  Ricardo B. Pringle
Title:    Secretary
LINK-LINE CONTRACTORS LTD., as a Canadian Subsidiary Guarantor
By:	/s/ DEREK A. VAN PATTER
Name:  Derek A. Van Patter
Title:    Vice President/Finance and Corporate Secretary
2018429 ONTARIO LTD., as a Canadian Subsidiary Guarantor
By:	/s/ DEREK A. VAN PATTER
Name:  Derek A. Van Patter
Title:    Secretary and Treasurer
W.S. NICHOLLS CONSTRUCTION INC., as a Canadian Subsidiary Guarantor
By:	/s/ DEREK A. VAN PATTER
Name:  Derek A. Van Patter
Title:    Secretary and Treasurer
W.S. NICHOLLS INDUSTRIES INC., as a Canadian Subsidiary Guarantor
By:	/s/ DEREK A. VAN PATTER
Name:  Derek A. Van Patter
Title:    Secretary and Treasurer

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

ADMINISTRATIVE AGENT AND LENDERS:
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Swingline Lender, Issuing Lender and Lender
By:	/s/ BRENDA K. ROBINSON
Name:  Brenda K. Robinson
Title:    Senior Vice President

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

BANK OF AMERICA, N.A., as Lender
By:	/s/ KENNETH TEBELMAN
Name:  Kenneth Tebelman
Title:    Vice President

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

CANADIAN IMPERIAL BANK OF COMMERCE, as Swingline Lender, Issuing Lender and Lender
By:	/s/ SCOTT MCCAHILL
Name:  Scott McCahill
Title:    Authorized Signatory
By:	/s/ JAMES LOGAN
Name:  James Logan
Title:    Authorized Signatory

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

UMB BANK, N.A., as Lender
By:	/s/ KYLE MCMILLIAN
Name:  Kyle McMillian
Title:    Vice President

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

U.S. BANK NATIONAL ASSOCIATION, as Lender
By:	/s/ HOLLAND H. WILLIAMS
Name:  Holland H. Williams
Title:    Vice President

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

NATIONAL BANK OF ARIZONA, as Lender
By:	/s/ SABINA ANTHONY
Name:  Sabina Anthony
Title:    Vice President

NPL Construction Co.

First Amendment to Credit Agreement

Signature Page

EX-12.01

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)

	December 31,
	2015		2014		2013		2012		2011
1. Fixed charges:
A) Interest expense	$	71,661	$	71,234	$	62,958	$	67,148	$	68,183
B) Amortization		1,884		2,063		2,002		2,001		2,137
C) Interest portion of rentals		16,678		11,802		11,809		10,605		8,943
Total fixed charges	$	90,223	$	85,099	$	76,769	$	79,754	$	79,263
2. Earnings (as defined):
D) Pretax income from continuing operations	$	219,332	$	219,521	$	222,815	$	207,915	$	175,066
Fixed Charges (1. above)		90,223		85,099		76,769		79,754		79,263
Total earnings as defined	$	309,555	$	304,620	$	299,584	$	287,669	$	254,329
		3.43		3.58		3.90		3.61		3.21

EX-13.01

Exhibit 13.01

Consolidated Selected Financial Statistics

Year Ended December 31,	2015			2014			2013			2012			2011
(Thousands of dollars, except pershare amounts)
Operating revenues	$	2,463,625		$	2,121,707		$	1,950,782		$	1,927,778		$	1,887,188
Operating expenses		2,175,293			1,837,224			1,676,567			1,656,254			1,637,108
Operating income	$	288,332		$	284,483		$	274,215		$	271,524		$	250,080
Net income	$	138,317		$	141,126		$	145,320		$	133,331		$	112,287
Total assets at year end	$	5,358,685		$	5,208,297		$	4,565,174		$	4,488,057		$	4,276,007
Capitalization at year end
Total equity	$	1,592,325		$	1,486,266		$	1,412,395		$	1,308,498		$	1,225,031
Redeemable noncontrolling interest		16,108			20,042			—			—			—
Long-term debt, excluding current maturities		1,551,204			1,631,374			1,381,327			1,268,373			930,858
	$	3,159,637		$	3,137,682		$	2,793,722		$	2,576,871		$	2,155,889
Current maturities of long-term debt	$	19,475		$	19,192		$	11,105		$	50,137		$	322,618
Common stock data
Common equity percentage of capitalization		50.4	%		47.4	%		50.6	%		50.8	%		56.8	%
Return on average common equity		8.9	%		9.7	%		10.6	%		10.4	%		9.3	%
Basic earnings per share	$	2.94		$	3.04		$	3.14		$	2.89		$	2.45
Diluted earnings per share	$	2.92		$	3.01		$	3.11		$	2.86		$	2.43
Dividends declared per share	$	1.62		$	1.46		$	1.32		$	1.18		$	1.06
Payout ratio		55	%		48	%		42	%		41	%		43	%
Book value per share at year end	$	33.65		$	32.03		$	30.51		$	28.39		$	26.68
Market value per share at year end	$	55.16		$	61.81		$	55.91		$	42.41		$	42.49
Market value per share to per share		164	%		193	%		183	%		149	%		159	%
Common shares outstanding at year end (000)		47,378			46,523			46,356			46,148			45,956
Number of common shareholders at year end		14,153			14,749			15,359			16,028			16,834
Ratio of earnings to fixed charges		3.43			3.58			3.90			3.61			3.21

Southwest Gas Corporation 8

Natural Gas Operations

Year Ended December 31,	2015			2014			2013			2012			2011
(Thousands of dollars)
Operating revenue	$	1,454,639		$	1,382,087		$	1,300,154		$	1,321,728		$	1,403,366
Net cost of gas sold		563,809			505,356			436,001			479,602			613,489
Operating margin		890,830			876,731			864,153			842,126			789,877
Expenses
Operations and maintenance		393,199			383,732			384,914			369,979			358,498
Depreciation and amortization		213,455			204,144			193,848			186,035			175,253
Taxes other than income taxes		49,393			47,252			45,551			41,728			40,949
Operating income	$	234,783		$	241,603		$	239,840		$	244,384		$	215,177
Contribution to consolidated net income	$	111,625		$	116,872		$	124,169		$	116,619		$	91,420
Total assets at year end	$	4,822,845		$	4,652,307		$	4,272,029		$	4,204,948		$	4,048,613
Net gas plant at year end	$	3,891,085		$	3,658,383		$	3,486,108		$	3,343,794		$	3,218,944
Construction expenditures and property additions	$	438,289		$	350,025		$	314,578		$	308,951		$	305,542
Cash flow, net
From operating activities	$	497,500		$	288,534		$	265,290		$	344,441		$	216,745
From (used in) investing activities		(416,727	)		(328,645	)		(304,189	)		(296,886	)		(289,234	)
From (used in) financing activities		(74,159	)		23,413			44,947			(43,453	)		(2,327	)
Net change in cash	$	6,614		$	(16,698	)	$	6,048		$	4,102		$	(74,816	)
Total throughput (thousands of therms)
Residential		655,421			617,377			741,327			655,046			718,765
Small commercial		285,118			276,582			298,045			270,665			303,923
Large commercial		92,284			94,391			102,761			116,582			112,256
Industrial/Other		30,973			32,374			50,210			47,830			50,208
Transportation		1,035,707			906,691			1,037,916			998,095			941,544
Total throughput		2,099,503			1,927,415			2,230,259			2,088,218			2,126,696
Weighted average cost of gas purchased ($/therm)	$	0.44		$	0.55		$	0.42		$	0.42		$	0.58
Customers at year end		1,956,000			1,930,000			1,904,000			1,876,000			1,859,000
Employees at year end		2,219			2,196			2,220			2,245			2,298
Customer to employee ratio		881			879			858			836			809
Degree days – actual		1,512			1,416			1,918			1,740			2,002
Degree days – ten-year average		1,792			1,816			1,876			1,866			1,888

Southwest Gas Corporation 9

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

About Southwest Gas Corporation

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

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

As of December 31, 2015, Southwest had 1,956,000 residential, commercial, industrial, and other natural gas customers, of which 1,045,000 customers were located in Arizona, 720,000 in Nevada, and 191,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2015, 55% of operating margin was earned in Arizona, 34% in Nevada, and 11% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

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

Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and develops industrial construction solutions. In October 2014, the Company acquired three privately held construction businesses, primarily based in Canada. The financial information contained herein only includes the results of the acquired entities since October 2014. Centuri operates in 20 major markets in the United States (primarily under the NPL name) and in 2 major markets in Canada (under the Link-Line and W.S. Nicholls names). Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented or modified pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with recent bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the U.S. Generally, revenues are lowest during the

Southwest Gas Corporation 10

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 83% 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,	2015		2014		2013
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	111,625	$	116,872	$	124,169
Construction services		26,692		24,254		21,151
Consolidated	$	138,317	$	141,126	$	145,320
Average number of common shares outstanding		46,992		46,494		46,318
Basic earnings per share fine
Consolidated	$	2.94	$	3.04	$	3.14
Natural Gas Operations
Operating margin	$	890,830	$	876,731	$	864,153

2015 Overview

Consolidated results for 2015 decreased compared to 2014 due to results from the natural gas operations segment, partially offset by improved results from the construction services segment. Basic earnings per share were $2.94 in 2015 compared to basic earnings per share of $3.04 in 2014.

Natural gas operations highlights include the following:

• Operating margin increased $14 million, or 2%, compared to the prior year

• Operating expenses increased $21 million, or 3%, between years

• Net financing costs decreased $4 million between 2015 and 2014

• COLI loss of $500,000 in 2015 compared to income of $5.3 million in 2014

• Paiute Pipeline Company general rate case settlement approved by FERC

• Redeemed $31.2 million of 5.00% IDRBs and $20 million of 5.25% IDRBs

• Credit facility expiration date extended one year to March 2020

• Issued $35.5 million in common stock under a $100 million Equity Shelf Program

• Filed for a holding company structure with state regulatory commissions – approval received in California

Southwest Gas Corporation 11

Construction services highlights include the following:

• Revenues in 2015 increased $269 million, or 36%, compared to 2014, reaching $1 billion for the first time

• Construction expenses increased $251 million or 39%, compared to 2014

• Contribution to net income increased $2 million compared to 2014

• Completed integration of Link-Line group of companies

Customer Growth.    Southwest completed 23,000 first-time meter sets, but realized 26,000 net new customers during 2015, an increase of 1.35%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for 2016.

Company-Owned Life Insurance (“COLI”).    Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $237 million at December 31, 2015. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $99 million at December 31, 2015 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with movements in the broader stock and bond markets. In 2015, as indicated in Note 1 of the Notes to Consolidated Financial Statements, the cash surrender values of COLI policies declined $500,000 (compared to positive returns of $5.3 million in 2014). Over the long-term, management expects average income of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized.

Liquidity. Southwest believes its liquidity position is sufficient. Southwest has a $300 million credit facility maturing in March 2020. The facility is provided through a consortium of eight major banking institutions. The maximum amount outstanding on the credit facility (including a commercial paper program) during 2015 was $180 million. In May 2015, the Company redeemed at par the $31.2 million 5.00% 2004 Series B Industrial Development Revenue Bonds (“IDRBs”) originally due in 2033. In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated these redemptions primarily from cash on hand and borrowings under its $300 million credit facility. At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $18 million was outstanding on the short-term portion of the credit facility. Southwest has no debt maturities prior to 2017.

Centuri has a $300 million secured revolving credit and term loan facility maturing in October 2019. The facility is provided through a consortium of six banking institutions and consists of a term loan with an initial limit of approximately $150 million (which was reached in 2014) and a revolving line of credit of $150 million. The maximum amount outstanding on the credit facility during 2015 was $276 million including $113 million outstanding on the term loan facility. At December 31, 2015, there was approximately $77.4 million, net of letters of credit, available under the line of credit.

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Results of Natural Gas Operations

Year Ended December 31,	2015		2014		2013
(Thousands of dollars)
Gas operating revenues	$	1,454,639	$	1,382,087	$	1,300,154
Net cost of gas sold		563,809		505,356		436,001
Operating margin		890,830		876,731		864,153
Operations and maintenance expense		393,199		383,732		384,914
Depreciation and amortization		213,455		204,144		193,848
Taxes other than income taxes		49,393		47,252		45,551
Operating income		234,783		241,603		239,840
Other income (deductions)		2,292		7,165		12,261
Net interest deductions		64,095		68,299		62,555
Income before income taxes		172,980		180,469		189,546
Income tax expense		61,355		63,597		65,377
Contribution to consolidated net income	$	111,625	$	116,872	$	124,169

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 years. New customers contributed $8 million in operating margin during 2015. Combined rate relief in the California jurisdiction and Paiute Pipeline Company (see Rates and Regulatory Proceedings) provided $5 million in operating margin. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues increased by $1 million.

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. These increases were partially offset by certain expenses that were higher in the prior year, including a $5 million legal accrual in 2014 and $1.1 million in rent expense (associated with the previously leased corporate headquarters complex).

Depreciation and amortization expense increased $9.3 million, or 5%. Average gas plant in service for the current year increased $276 million, or 5%, as compared to the prior year. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in California. 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 years primarily due to higher property taxes associated with net plant additions.

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Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, decreased $4.9 million between 2015 and 2014. The current year reflects a loss of $500,000 associated with COLI policy cash surrender value decreases, while the prior year included $5.3 million of COLI-related income.

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

2014 vs. 2013

Contribution to consolidated net income from natural gas operations decreased by $7.3 million between 2014 and 2013. Increases in net interest deductions, as well as a decrease in other income, offset improved operating income.

Operating margin increased $13 million between years including a combined $8 million of rate relief in the California jurisdiction and Paiute Pipeline Company. New customers contributed $8 million of the increase during 2014. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues declined by $3 million.

Operations and maintenance expense decreased $1.2 million, or less than 1%, between years primarily due to declines in employee-related costs, partially offset by a $5 million legal accrual in the first quarter of 2014 and higher general costs. A $9 million reduction in pension costs and a $3 million reduction in employer-sponsored medical costs, due to positive claims experience between years, resulted in a favorable impact to 2014 operations and maintenance expense of approximately $9.5 million.

Depreciation and amortization expense increased $10.3 million, or 5%. Average gas plant in service for 2014 increased $297 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 business, partially offset by depreciation rate decreases resulting from the most recent California general rate case decision. Amortization primarily associated with software-related intangible assets increased approximately $1.3 million. Amortization associated with the recovery of regulatory assets increased approximately $1.2 million overall (primarily due to Arizona demand-side management, or “DSM,” programs).

Taxes other than income taxes increased $1.7 million between years due to higher property taxes in Arizona and Nevada.

Other income decreased $5.1 million between 2014 and 2013. Cash surrender values of COLI policies (including net death benefits recognized) increased $5.3 million in 2014, while COLI-related income was $12.4 million in the prior year. Interest income increased $2.1 million between years, as under-collected PGA balances and the associated interest thereon rose significantly in 2014.

Net interest deductions increased $5.7 million between years, primarily due to the issuance of $250 million of long-term debt in the fourth quarter of 2013. The increase was mitigated by higher interest expense in 2013 associated with PGA balances, which were in an over-collected status for the majority of 2013.

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Results of Construction Services

Year Ended December 31,	2015		2014			2013
(Thousands of dollars)
Construction revenues	$	1,008,986	$	739,620		$	650,628
Operating expenses:
Construction expenses		898,781		647,857			573,284
Depreciation and amortization		56,656		48,883			42,969
Operating income		53,549		42,880			34,375
Other income (deductions)		587		(58	)		39
Net interest deductions		7,784		3,770			1,145
Income before income taxes		46,352		39,052			33,269
Income tax expense		18,547		14,776			12,565
Net income		27,805		24,276			20,704
Net income (loss) attributable to noncontrolling interests		1,113		22			(447	)
Contribution to consolidated net income attributable to Centuri	$	26,692	$	24,254		$	21,151

2015 vs. 2014

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. 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 the inclusion of a full year of revenues of the acquired companies (an increase of $124 million). NPL revenues in 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. Governmental-mandated pipeline safety-related programs have resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues include contracts with Southwest totaling $104 million in 2015 and $92 million in 2014. Centuri accounts for services provided to Southwest at contractual (market) prices.

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 includes a $3.4 million loss on a Canadian project, discussed below. 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.

During 2015, a loss of $3.4 million was recorded on an industrial construction project in Canada (revenue of $22.3 million and construction costs of $25.7 million). Work commenced on this project in March 2015 and was completed in the third quarter. During construction, delays in delivery of critical equipment to the job site resulted in

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production inefficiencies and an increase in total estimated project costs. At the end of the first quarter, total project costs were estimated to exceed contract revenues by $5.6 million, and by the end of the third quarter the estimated overrun was $7.7 million. Change orders were being negotiated during the construction period to offset the additional costs. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

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

During the past several years, construction services has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2015 and 2014, revenues from replacement work were 68% and 67%, respectively, of total revenues. Governmental pipeline safety-related programs and U.S. bonus depreciation tax incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.

2014 vs. 2013

Contribution to consolidated net income from construction services for 2014 increased $3.1 million compared to 2013.

Revenues increased $89.0 million, or 14%, when compared to 2013 primarily due to additional pipe replacement work in 2014 and the inclusion of the acquired companies’ revenues ($54.3 million) beginning in the fourth quarter of 2014. Construction revenues include Centuri contracts with Southwest totaling approximately $92 million in 2014 and $88 million in 2013.

Construction expenses increased $74.6 million, or 13%, due primarily to additional pipe replacement work in 2014 and the inclusion of the acquired companies’ construction costs ($49.4 million). General and administrative expense (included in construction expenses) increased $9.5 million, including $3.7 million from the acquired companies, acquisition costs ($5 million), and changes that were implemented to match the increased size of the business and its complexity. Offsetting these increases was approximately $4 million that was recorded in 2013 associated with a legal settlement, which was resolved in February 2014. Gains on sale of equipment (reflected as an offset to construction expenses) were $6.2 million and $4.1 million in 2014 and 2013, respectively. Depreciation and amortization expense increased $5.9 million between 2014 and 2013 due to the amortization on finite-lived intangible assets recognized from the acquisition ($1.5 million) and additional equipment purchased to support growth in the volume of work being performed.

Net interest deductions were $3.8 million in 2014 compared to $1.1 million in 2013. 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.

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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) change, 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 (2013—2015) 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 Public Utility Commission of Nevada (“PUCN”) in November 2012, and was amended in a Rehearing Decision in March 2013. The Rehearing Decision addressed issues raised by Southwest regarding capital structure. Ultimately, the Company 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, while retaining an alternative capital structure rather than what was initially proposed by Southwest.

General Revenues Adjustment.    As part of the Annual Rate Adjustment (“ARA”) filing in June 2015, Southwest requested recovery of amounts associated with its revenue decoupling mechanism (General Revenues Adjustment, or “GRA”). The ARA, including amounts to recover the regulatory asset associated with this mechanism, was approved in December 2015, with rates effective January 2016. The rate adjustment is expected to recover approximately $19 million of the associated regulatory asset during 2016. There is no impact to net income overall from these recoveries, but there is a favorable impact to cash flows as the regulatory asset balance is recovered.

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 non-revenue producing infrastructure. The regulations provide for the establishment of regulatory assets that recover the depreciation expense and authorized pre-tax rate of return of infrastructure replacement investments between rate cases, which also allows Southwest to develop rates to recover the associated amounts in a future general rate case proceeding, at which time the plant will be “rolled into” rate base. Southwest made a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying early vintage plastic pipe (“EVPP”) and vintage steel pipe (“VSP”) projects for replacement beginning in 2015. In October 2014, the PUCN approved EVPP replacement expenditures of $14.4 million for 2015. In June 2015, Southwest filed its GIR Advance Application with the PUCN proposing $43.5 million of accelerated pipe replacements for 2016 (subject to the GIR mechanism). Once completed, the annualized revenue requirement associated with the accelerated replacement is estimated at $4.6 million. In October 2015, the PUCN approved the GIR Advance Application, granting Southwest the authority to replace the $43.5 million of infrastructure under the GIR mechanism. Also in October 2015, management filed a rate application to reset the GIR surcharge, based upon project costs deferred through August 2015. In December, the PUCN approved new rates, effective in January 2016, which are expected to result in approximately $4 million in annualized revenues.

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Conservation and Energy Efficiency. As part of the ARA filing, Southwest requested recovery of energy efficiency and conservation development and implementation costs, including promotions and incentives for various programs, as originally approved for deferral by the PUCN effective November 2009. While recovery of these costs was approved as part of the most recent general rate case made effective May 2012, amounts incurred subsequent to the effective date continued to be deferred. Approved rates became effective January 2016 and will result in annualized margin increases of $2 million in northern Nevada and $8.7 million in southern Nevada, and also includes amounts representing expected program expenditures for 2016. There is, however, no anticipated impact to net income overall from these recoveries as the amounts collected through customer rates will also be reflected as higher amortization expense.

Expansion and Economic Development Legislation. In February 2015, legislation (“SB 151”) was introduced in Nevada directing the PUCN to adopt regulations authorizing natural gas utilities to expand their infrastructure consistent with a program of economic development. This includes providing natural gas service to unserved and underserved areas in Nevada, as well as attracting and retaining utility customers and accommodating the expansion of existing business customers. SB 151 was signed into law in May 2015. The draft regulations were reviewed by the Legislative Council Bureau and final regulations were approved by the PUCN in January 2016. Southwest is currently assessing and prioritizing potential areas to extend service to based on the legislation and regulations. The process will require the identification of projects, advance approval requests, and development of rates for investment in excess of allowable investment.

California Jurisdiction

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

In June 2014, the CPUC issued a final decision in this proceeding (“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 provides for a two-way pension balancing account to track differences between authorized and actual pension funding amounts, a limited COYL inspection program for schools, and an IRRAM to recover the costs associated with the new limited COYL program. New rates associated with the CPUC decision were effective June 2014.

In November 2015, Southwest made its annual PTY attrition filing, requesting annual revenue increases of $1.8 million in southern California, $499,000 in northern California and $249,000 for South Lake Tahoe. This filing was approved in December 2015 and rates were made effective in January 2016. At the same time, rates were updated to recover, the regulatory asset associated with the revenue decoupling mechanism, or margin tracker. The rate adjustment is expected to recover approximately $18 million of the associated regulatory asset balance during 2016. There is no impact to net income overall from margin tracker recoveries; however, there is a favorable impact to cash flows as the regulatory asset balance is recovered. In addition to the PTY attrition and margin tracking mechanism approvals, the CPUC also approved an adjustment to recover costs associated with Southwest’s

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Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plan (“Implementation Plan”), effective January 2016. The Implementation Plan involved replacing 7.1 miles of transmission pipeline in its system, in addition to installing a remote control shut-off valve. This adjustment is expected to result in an annualized margin increase of $1.7 million during 2016.

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 its allocation for 2015 in the third quarter of 2014 and for 2016, in the third quarter of 2015. Of those allocated allowances, Southwest must consign a certain percentage to the CARB for auction. The Company 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.

Arizona Jurisdiction

General Rate Case Status.    The most recent general rate case decision from the Arizona Corporation Commission (“ACC”) in Southwest’s Arizona rate jurisdiction was made effective in January 2012 and authorized a return on common equity of 9.50%, a fair value rate of return of 6.92% and a capital structure consisting of 47.7% long-term debt and 52.3% common equity, relative to an authorized original cost rate base of $1.07 billion. That ACC decision also approved a full revenue decoupling mechanism with a monthly weather adjuster. At that time, Southwest agreed not to file a general rate case prior to April 30, 2016. Given the period covered by the moratorium, Southwest is currently preparing its rate case filing and intends to request approval to continue its decoupled rate design, expand its currently approved infrastructure recovery program, and update its cost of service, including an increase in rate base of approximately 22-24% to reflect various investments Southwest has made since its last rate case to enhance its distribution system. Southwest also intends to include a depreciation study in compliance with the most recent general rate case decision to update depreciation rates. Southwest anticipates filings its general rate case in the second quarter of 2016, shortly after the “stay-out” period has expired.

LNG (“Liquefied Natural Gas”) Facility.    In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, operated by Southwest and connected directly to its distribution system. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system). In December 2014, Southwest received an order from the ACC granting pre-approval of Southwest’s application to construct the LNG facility and the deferral of costs, limited to $50 million. The authorization to defer costs expires on November 1, 2017 (from which point, expenditures incurred would not be eligible for deferral) and also requires any unquantified cost savings to be deferred. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. The Company purchased the site for the facility in October 2015 and is preparing the construction

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requirements bid package for potential contractors. The contract to construct the facility is currently expected to be in place in the second half of 2016 and construction is expected to take approximately two to three years to complete. The Company anticipates including a proposal for the ratemaking treatment of facility costs as part of its next Arizona rate case filing.

Customer-Owned Yardline (“COYL”) Program.    The Company received approval, in connection with its most recent Arizona general rate case, to implement a program to conduct leak surveys, and if leaks were present, to replace and relocate service lines and meters for approximately 100,000 Arizona customers whose meters were set off from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously responsible for the cost of maintaining these lines and were subject to the immediate cessation of natural gas service if low-pressure leaks occurred. To facilitate this program, the Company was authorized to collect estimated leak survey costs in rates commencing in 2012. Effective June 2013, the ACC authorized a surcharge to recover the costs of depreciation and pre-tax return the Company would have received if the additional pipe replacement costs themselves (incurred to replace and relocate service lines and meters) had been included in rate base concurrent with the most recent Arizona rate case. The surcharge is revised annually as the program progresses, with the undepreciated plant balance to be incorporated in rate base at the time of the next Arizona general rate case. In January 2014, the Company received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs, which was subsequently revised effective June 2014. Resources continue to be focused on contacting customers within replacement project areas to participate in the Phase II meter relocation. In February 2015, the Company filed to increase the surcharge revenue from $1.5 million to $2.5 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total capital expenditures of $16 million, $6.3 million of which was incurred during 2014. In May 2015, the ACC issued a decision approving the surcharge application, effective in June 2015.

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. The filing fulfilled an obligation from the settlement agreement reached in the 2009 Paiute general rate case. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case. In October 2014, Paiute requested, and was granted, the authority to place the settlement rates into effect on an interim basis effective September 2014. In February 2015, the FERC issued a letter order approving the settlement as filed. Tariff charges in compliance with the settlement were filed in March 2015. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement resulted in an annual revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. The settlement implies an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed not to file a rate case prior to May 2016, but no later than May 2019.

Elko County Expansion Project.    During the second and third quarters of 2013, Paiute notified present and potential shippers of its plans to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area. This additional capacity is required to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. Through the “open season” process, shippers responded with substantial interest. A certificate application for the project was filed in June 2014. 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

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project were implemented in January 2016 and are expected to result in $6 million in revenue annually. The total cost of this project is estimated at approximately $35 million, including remaining costs associated with site restoration along the construction corridor.

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, 2015, under-collections in California resulted in an asset of $3.6 million, and over-collections in Arizona and northern and southern Nevada collectively resulted in a liability of $45.6 million on the Company’s balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during 2015. The lower cost of natural gas, combined with surcharges in place during 2015, fully recovered PGA receivables existing at December 31, 2014. 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):

	2015			2014
Arizona	$	(3.5	)	$	48.4
Northern Nevada		(2.3	)		10.2
Southern Nevada		(39.8	)		20.4
California		3.6			8.6
	$	(42.0	)	$	87.6

Arizona PGA Filings.    In May 2014, Southwest filed an application to provide for monthly adjustments to the surcharge component of the Gas Cost Balancing Account to allow for more timely refunds to/recoveries from ratepayers, which was approved in July 2014. As part of this filing, the ACC also approved an initial surcharge of $0.06 per therm effective August 2014. This surcharge was reduced in June and July 2015 and was eliminated in August 2015 as the receivable balance was fully collected, while gas cost rates paid to suppliers remained low for the remainder of the year.

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 2015, 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 2016. These new rates are intended to reduce the outstanding liability over a twelve-month period.

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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 2015/2016 heating season, contracts contained in the fixed-price portion of the supply portfolio ranged from slightly under $3 to approximately $4.40 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, the Company suspended fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Company evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.

Holding Company Reorganization

In 2015, the Board of Directors (“Board”) of the Company authorized management to evaluate and pursue a holding company reorganization to provide further separation between regulated and unregulated businesses, and to provide additional financing flexibility. Regulatory applications for preapproval of the reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. In January 2016, approval was received by the CPUC, but approvals by the ACC and the PUCN are still pending. The reorganization is subject to approval by the aforementioned state regulatory commissions, consents from various third parties, and final Board approval. Subject to such conditions, the reorganization could become effective in the second half of 2016. In this event, each outstanding share of Southwest Gas common stock would automatically convert into a share of stock in the holding company, on a one-for-one basis.

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 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. In addition, in March 2015, the Company filed an automatic shelf registration statement for the offer and sale of up to $100 million of its common stock for general corporate purposes and for the noted investment activities, refer to Note 6 – Common Stock and the discussion below. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs. 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 $200.7 million between 2015 and 2014. The improvement in operating cash flows was primarily attributable to temporary increases from working capital components overall (notably the collection of deferred purchased gas costs).

Southwest Gas Corporation 22

Investing Cash Flows.    Cash used in consolidated investing activities decreased $85.8 million in 2015 as compared to 2014. The decline was primarily due to the acquisition of the construction services businesses in 2014. Construction expenditures, including scheduled and accelerated pipe replacement, and to a lesser extent, equipment purchases by Centuri due to the increased replacement construction work of its customers were higher in 2015. In association with the acquisition of construction services businesses, a $9 million working capital adjustment related to a contractual true-up period was paid in the first quarter of 2015.

Financing Cash Flows.    The change in financing cash flows was primarily due to net borrowings in 2014 to finance the construction services acquisition compared to net debt repayments and redemptions in 2015. Repayment of long-term debt in 2015 included $51.2 million of IDRBs, while the prior year included the repayment of $65 million of IDRBs. The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under the secured revolving credit facility portion of Centuri’s secured revolving credit and term loan facility. The majority of Centuri’s borrowings in the prior year were associated with the acquisition of construction services businesses. Southwest also issued approximately $35 million in stock under its Equity Shelf Program. See also Note 6 – Common Stock, and the discussion below. Dividends paid increased in 2015 as compared to 2014 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding. While Centuri paid dividends during 2015, the only impact to consolidated cash flows overall was due to the amount paid to the holders of the redeemable noncontrolling interest.

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

2015 Construction Expenditures

During the three-year period ended December 31, 2015, total gas plant increased from $5 billion to $5.9 billion, or at an average annual rate of 5%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as the Company set approximately 64,000 meters during the three-year period.

During 2015, construction expenditures for the natural gas operations segment were $438 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 $498 million and provided approximately 97% 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.

2015 Financing Activity

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

In March 2015, the Company filed with the SEC a shelf registration statement which included a prospectus detailing the Company’s plans to sell up to $100 million of the Company’s common stock over a period of time. In March 2015, the Company entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC relating to this

Southwest Gas Corporation 23

issuance and sale of shares of the Company’s common stock (“Equity Shelf Program”). Sales of the shares will continue to be made at market prices prevailing at the time of sale. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

During 2015, 645,225 shares were issued in at-the-market offerings at an average price of $55.05 per share with gross proceeds of $35.5 million, agent commissions of $355,000, and net proceeds of $35.2 million. See Note 6 – Common Stock for more information.

During 2015, the Company issued approximately 209,000 additional shares of common stock collectively through the Restricted Stock/Unit Plan, the Management Incentive Plan, and the Stock Incentive Plan. The Company raised approximately $741,000 from the issuance of shares of common stock through the Stock Incentive Plan.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2018 will be between $1.4 billion and $1.6 billion. Of this amount, approximately $460 million is expected to be incurred in 2016. Southwest plans to request regulatory support to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). This will include requests in California and Arizona 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, California IRRAM, 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. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

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 the Company) that could significantly affect liquidity in future years include: variability of natural gas prices, changes in the ratemaking policies of regulatory commissions, regulatory lag, customer growth in the natural gas segment’s service territories, Southwest’s ability to access and obtain capital from external sources, interest rates, changes in income tax laws, pension funding requirements, inflation, and the level of Company earnings. Natural gas prices and related gas cost recovery rates have historically had the most significant impact on Company liquidity.

On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses 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 2015, the PGA balance went from an under-collected balance of $87.6 million to an over-collected balance of $42 million at December 31, 2015. See PGA Filings for more information.

Southwest Gas Corporation 24

In March 2015, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2019 and was extended to March 2020. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. The maximum amount outstanding during 2015 occurred during the fourth quarter and was $180 million ($150 million outstanding on the long-term portion of the credit facility (including $50 million on the commercial paper program), in addition to $30 million outstanding on the short-term portion). At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility (including $50 million under the commercial paper program), and $18 million was 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 third quarters was $160 million, $56 million, and $97 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. This credit facility has been, and is expected to continue to be, adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing.

The Company has a $50 million commercial paper program as noted above. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the commercial paper program are calculated at the then current commercial paper rate. At December 31, 2015, $50 million was outstanding on the commercial paper program, which is the maximum amount outstanding at any time during the year.

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 Centuri secured revolving credit facility during 2015 was $104.3 million, which occurred in the second quarter. At December 31, 2015, $60.6 million was outstanding on the Centuri secured revolving credit facility. At December 31, 2015, there was approximately $77.4 million, net of letters of credit, available under the line of credit.

Credit Ratings

The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., generally the better the rating, the lower the cost to borrow funds). The Company’s current unsecured long-term debt ratings are all considered investment grade.

The Company’s unsecured long-term debt rating from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as reaffirmed in January 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.

Southwest Gas Corporation 25

The Company’s senior unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is A3 with a stable outlook as reaffirmed 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 Company’s senior unsecured ratings including IDRBs from Fitch Ratings (“Fitch”) is A (with a stable outlook) as reaffirmed in July 2015. 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. Such suffixes are not added to the ‘AAA’ obligation rating category, or to corporate finance obligation ratings in the categories below ‘CCC’.

A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency. The foregoing securities ratings are subject to change at any time in the discretion of the applicable ratings agency. Numerous factors, including many that are not within the Company’s control, are considered by the ratings agencies in connection with assigning securities ratings.

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company 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, 2015, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $2.2 billion in additional debt and meet the leverage ratio requirement. The Company has at least $1 billion of cushion in equity relating to the minimum net worth requirement.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2015, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $75 million in additional debt and meet the leverage ratio requirement. Centuri has at least $15 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.

Inflation

Inflation can impact the Company’s 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 components of the cost of service, and construction 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.

Southwest Gas Corporation 26

Off-Balance Sheet Arrangements

All Company debt is recorded on its balance sheets. The Company has long-term operating and capital leases, which are described in Note 2—Utility Plant and Leases of the Notes to Consolidated Financial Statements, and included in the Contractual Obligations Table below.

Contractual Obligations

The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, capital leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statements of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Company’s contractual obligations at December 31, 2015 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2016		2017-2018		2019-2020		Thereafter
Operating leases (Note 2)	$	22	$	7	$	8	$	4	$	3
Gas purchase obligations		151		89		55		7		—
Pipeline capacity/storage		1,145		124		211		131		679
Derivatives (Note 13)		5		4		1		—		—
Other commitments		22		12		10		—		—
Long-term debt, including current maturities (Note 7)		1,571		19		57		418		1,077
Interest on long-term debt		899		60		117		111		611
Capital leases (Note 2)		3		2		1		—		—
Other		6		—		1		1		4
Total	$	3,824	$	317	$	461	$	672	$	2,374

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 151 million dekatherms. The fixed-price contracts range in price from slightly under $3 to $4 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 mechanism. 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, consists 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, 2015 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 2016 is $39 million and is not included in the table above.

Southwest Gas Corporation 27

Bonus Depreciation

In December 2015, the 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 deduction after 2019. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provision of the PATH Act deferred the payment of approximately $55 million of federal income taxes for 2015.

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition, going concern, recognition and measurement of financial instruments, the presentation of deferred taxes in the balance sheet, net asset value (“NAV”) used as a practical expedient, and the presentation of debt issuance costs in the balance sheet. See Note 1—Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on the Company’s 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 Company’s 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 of the Company. For more information regarding the significant accounting policies of the Company, 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. The Company reviews its 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 theratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a

Southwest Gas Corporation 28

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

Accounting for Income Taxes

We are subject to income taxes in the United States and Canada. The income tax calculations of the Company 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 Company uses the asset and liability method of accounting 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 the Company 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. The Company 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, the financial position, and/or results of operations of the Company.

Accounting for Pensions and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Company’s 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 $39.5 million and future pension expense by $4 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.5 million and expense by $1.6 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $2 million (but has no impact on the pension obligation).

Southwest Gas Corporation 29

At December 31, 2015, the Company raised the discount rate to 4.50% from a rate of 4.25% at December 31, 2014. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation increased to 3.25% at December 31, 2015 from 2.75% in the prior year. The Company lowered the asset return assumption to 7.25% to be used for 2016 expense from the 7.75% rate used in the previous year. A change to a new actuarial mortality table occurred in 2014, which took into account longer life spans for plan participants; however, just one year later, a decline in the mortality improvement scale was reflected by the same Society of Actuaries, highlighting the nature of estimation. Pension expense for 2016 is estimated to decrease by $6.7 million compared to 2015 because of the new mortality assumption and higher discount rate. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Business Combinations

The amount of goodwill initially recognized in a business combination is based on the excess of the purchase price of the acquired company over the fair value of the other assets acquired and liabilities assumed. The determination of these fair values requires management to make significant estimates and assumptions. For example, assumptions with respect to the timing and amount of future revenues and expenses associated with an asset are used to determine its fair value but the actual timing and amount may differ materially resulting in impairment of the asset’s recorded value. In some cases, the Company engages independent third-party valuation firms to assist in determining the fair values of acquired assets and liabilities assumed. Critical estimates in valuing certain intangible assets include but are not limited to future expected cash flows of the acquired business, trademarks, customer relationships, technology obsolescence, and discount rates. In addition, uncertain tax positions and tax-related valuation allowances assumed in connection with a business combination are initially estimated at the acquisition date. These items are reevaluated quarterly, based upon facts and circumstances that existed at the acquisition date with any adjustments to the preliminary estimates being recorded to goodwill, provided that the Company is within the twelve-month measurement period. Subsequent to the measurement period or the final determination of the estimated value of the tax allowance or contingency, whichever comes first, changes to these uncertain tax positions and tax-related valuation allowances will affect the provision for income taxes in the Consolidated Statements of Income, and could have a material impact on the Company’s results of operations and financial position. The fair value assigned to the intangible assets acquired and liabilities assumed in 2014, and the determination of goodwill associated with the acquisition, are described in Note 17—Acquisition of Construction Services Businesses.

Certifications

The Securities and Exchange Commission (“SEC”) requires the Company to file certifications of its Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to the Company’s periodic filings. The CEO and CFO certifications for the period ended December 31, 2015 are included as exhibits to the 2015 Annual Report on Form 10-K filed with the SEC.

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 the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,”

Southwest Gas Corporation 30

“plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote,” “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest savings, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, bonus depreciation tax deductions, amount and timing for completion of estimated future construction expenditures, including the LNG facility in southern Arizona and the cost of the Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, net earnings impacts from gas infrastructure replacement surcharges, funding sources of cash requirements, amounts generally expected to be reflected in 2016 or future period revenues from regulatory rate proceedings, PTY rate adjustments, ARA rates and other surcharges, PGA, and other rate adjustments, sufficiency of working capital and current credit facilities, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity and the intent and ability to issue the remaining capacity under the Equity Shelf Program, future dividend increases, 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, infrastructure replacement mechanisms and the COYL program, 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 Brigadier will be deductible for tax purposes, the process required with regard to SB 151 legislation and resulting Nevada regulations, the success in securing remaining approvals of the proposed holding company structure or timing of the related reorganization, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, variability in volume of gas or transportation service sold to customers, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, our continued ability to meet consignment and purchase requirements under Cap and Trade regulations, results of Centuri bid work, impacts of structural and management changes at Centuri, Centuri construction expenses, differences between actual and originally expected outcomes of Centuri bid or other fixed-price construction agreements, and ability to successfully procure new work, acquisitions and management’s plans related thereto, competition, our ability to raise capital in external financings, our ability to continue to remain within the ratios and other limits subject to our debt covenants, and ongoing evaluations in regard to goodwill and other intangible assets. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

All forward-looking statements in this annual report are made as of the date hereof, based on information available to the Company as of the date hereof, and the Company assumes no obligation to update or revise any of its

Southwest Gas Corporation 31

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

	2015				2014				Dividends Declared
	High		Low		High		Low		2015		2014
First quarter	$	63.68	$	52.94	$	55.33	$	51.70	$	0.405	$	0.365
Second quarter		59.75		51.69		55.69		50.96		0.405		0.365
Third quarter		58.40		51.26		53.34		47.21		0.405		0.365
Fourth quarter		62.56		50.78		64.20		48.23		0.405		0.365
									$	1.620	$	1.460

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 16, 2016, there were 14,095 holders of record of common stock, and the market price of the common stock was $59.56.

In reviewing dividend policy, the Board of Directors (“Board”) considers the adequacy and sustainability of earnings and cash flows of the Company and its subsidiaries; the strength of the Company’s capital structure; the sustainability of the dividend through all business cycles; and whether the dividend is within a normal payout range for its respective businesses. The quarterly common stock dividend declared was 33 cents per share throughout 2013, 36.5 cents per share throughout 2014, and 40.5 cents per share throughout 2015. As a result of its ongoing review of dividend policy, in February 2016, the Board increased the quarterly dividend from 40.5 cents to 45 cents per share, effective with the June 2016 payment. This marks the tenth consecutive year in which the dividend was increased. The Board’s policy is to target a dividend payout ratio that allows the Company to maintain its strong credit ratings and effectively fund its rate base growth and is consistent with the local distribution company peer group average. The timing and amount of any increases will be based on the Board’s continual review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects.

Southwest Gas Corporation 32

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Southwest Gas Corporation 33

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

December 31,	2015			2014
ASSETS
Utility plant:
Gas plant	$	5,854,917		$	5,556,599
Less: accumulated depreciation		(2,084,007	)		(1,973,098	)
Acquisition adjustments, net		370			550
Construction work in progress		119,805			74,332
Net utility plant (Note 2)		3,891,085			3,658,383
Other property and investments (Note 1)		313,531			326,743
Restricted cash		—			821
Current assets:
Cash and cash equivalents		35,997			39,566
Accounts receivable, net of allowances (Note 3)		314,512			281,824
Accrued utility revenue		74,700			73,900
Income taxes receivable, net		34,175			21,853
Deferred income taxes, net (Note 12)		—			2,109
Deferred purchased gas costs (Note 4)		3,591			87,556
Prepaids and other current assets (Notes 1, 4, and 13)		95,199			99,803
Total current assets		558,174			606,611
Noncurrent assets:
Goodwill (Note 1)		126,145			143,160
Deferred income taxes (Note 12)		428			—
Deferred charges and other assets (Notes 2, 4, and 13)		469,322			472,579
Total noncurrent assets		595,895			615,739
Total assets	$	5,358,685		$	5,208,297

Southwest Gas Corporation 34

CONSOLIDATED BALANCE SHEETS – Continued

December 31,	2015			2014
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—47,377,575 and 46,523,184 shares) (Note 11)	$	49,007		$	48,153
Additional paid-in capital		896,448			851,381
Accumulated other comprehensive income (loss), net (Note 5)		(50,268	)		(50,175	)
Retained earnings		699,221			639,164
Total Southwest Gas Corporation equity		1,594,408			1,488,523
Noncontrolling interest		(2,083	)		(2,257	)
Total equity		1,592,325			1,486,266
Redeemable noncontrolling interest (Note 16)		16,108			20,042
Long-term debt, less current maturities (Note 7)		1,551,204			1,631,374
Total capitalization		3,159,637			3,137,682
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		19,475			19,192
Short-term debt (Note 8)		18,000			5,000
Accounts payable		164,857			167,988
Customer deposits		72,631			71,546
Income taxes payable, net		940			—
Accrued general taxes		47,337			44,339
Accrued interest		16,173			16,468
Deferred purchased gas costs (Note 4)		45,601			—
Other current liabilities (Notes 2, 4, and 13)		150,031			145,584
Total current liabilities		535,045			470,117
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 12)		769,445			723,688
Accumulated removal costs (Note 4)		303,000			304,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 10, and 13)		591,558			572,810
Total deferred income taxes and other credits		1,664,003			1,600,498
Total capitalization and liabilities	$	5,358,685		$	5,208,297

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 35

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

Year Ended December 31,	2015			2014			2013
Operating revenues:
Gas operating revenues	$	1,454,639		$	1,382,087		$	1,300,154
Construction revenues		1,008,986			739,620			650,628
Total operating revenues		2,463,625			2,121,707			1,950,782
Operating expenses:
Net cost of gas sold		563,809			505,356			436,001
Operations and maintenance		393,199			383,732			384,914
Depreciation and amortization		270,111			253,027			236,817
Taxes other than income taxes		49,393			47,252			45,551
Construction expenses		898,781			647,857			573,284
Total operating expenses		2,175,293			1,837,224			1,676,567
Operating income		288,332			284,483			274,215
Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(71,879	)		(72,069	)		(63,700	)
Other income (deductions)		2,879			7,107			12,300
Total other income and (expenses)		(69,000	)		(64,962	)		(51,400	)
Income before income taxes		219,332			219,521			222,815
Income tax expense (Note 12)		79,902			78,373			77,942
Net income		139,430			141,148			144,873
Net income (loss) attributable to noncontrolling interests		1,113			22			(447	)
Net income attributable to Southwest Gas Corporation	$	138,317		$	141,126		$	145,320
Basic earnings per share (Notes 1 and 15)	$	2.94		$	3.04		$	3.14
Diluted earnings per share (Notes 1 and 15)	$	2.92		$	3.01		$	3.11
Average number of common shares outstanding		46,992			46,494			46,318
Average shares outstanding (assuming dilution)		47,383			46,944			46,758

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 36

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

Year Ended December 31,	2015			2014			2013
Net Income	$	139,430		$	141,148		$	144,873
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)		(18,922	)		(107,661	)		62,214
Amortization of prior service cost		828			220			220
Amortization of net actuarial loss		21,316			14,667			21,190
Prior service cost		—			(4,130	)		—
Regulatory adjustment		(3,500	)		86,991			(76,651	)
Net defined benefit pension plans		(278	)		(9,913	)		6,973
Forward-starting interest rate swaps:
Amounts reclassified into net income (Notes 5 and 13)		2,073			2,073			2,074
Net forward-starting interest rate swaps		2,073			2,073			2,074
Foreign currency translation adjustments		(1,954	)		(659	)		—
Total other comprehensive income (loss), net of tax		(159	)		(8,499	)		9,047
Comprehensive income		139,271			132,649			153,920
Comprehensive income (loss) attributable to noncontrolling interests		1,047			—			(447	)
Comprehensive income attributable to Southwest Gas Corporation	$	138,224		$	132,649		$	154,367

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 37

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

Year Ended December 31,	2015			2014			2013
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	139,430		$	141,148		$	144,873
Adjustments to reconcile net income to netcash provided by operating activities:
Depreciation and amortization		270,111			253,027			236,817
Deferred income taxes		48,785			64,309			68,639
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(39,850	)		(3,683	)		(22,556	)
Accrued utility revenue		(800	)		(1,200	)		(700	)
Deferred purchased gas costs		129,566			(69,339	)		(111,143	)
Accounts payable		(3,491	)		(41,499	)		27,668
Accrued taxes		(8,405	)		(13,573	)		925
Other current assets and liabilities		18,300			23,379			5,084
Gains on sale		(3,102	)		(6,171	)		(4,112	)
Changes in undistributed stock compensation		2,914			7,973			6,958
AFUDC		(3,008	)		(1,995	)		(2,274	)
Changes in other assets and deferred charges		(14,166	)		(21,732	)		(21,719	)
Changes in other liabilities and deferred credits		10,863			15,779			17,749
Net cash provided by operating activities		547,147			346,423			346,209

Southwest Gas Corporation 38

CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued

Year Ended December 31,	2015			2014			2013
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(488,000	)		(396,898	)		(364,276	)
Acquisition of businesses, net of cash acquired		(9,261	)		(190,497	)		—
Restricted cash		785			1,233			—
Changes in customer advances		18,300			20,363			7,773
Miscellaneous inflows		8,354			11,611			8,465
Miscellaneous outflows		—			(1,400	)		—
Net cash used in investing activities		(469,822	)		(555,588	)		(348,038	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		35,396			405			1,635
Dividends paid		(74,248	)		(66,275	)		(59,535	)
Centuri distribution to redeemable noncontrolling interest		(99	)		—			—
Issuance of long-term debt, net		135,816			269,228			311,290
Retirement of long-term debt		(187,973	)		(139,155	)		(137,013	)
Change in credit facility and commercial paper		—			140,000			(101,000	)
Change in short-term debt		13,000			5,000			1,999
Principal payments on capital lease obligations		(1,420	)		(434	)		—
Other		41			(1,257	)		—
Net cash provided by (used in) financing activities		(79,487	)		207,512			17,376
Effects of currency translation on cash and cash equivalents		(1,407	)		142			—
Change in cash and cash equivalents		(3,569	)		(1,511	)		15,547
Cash and cash equivalents at beginning of period		39,566			41,077			25,530
Cash and cash equivalents at end of period	$	35,997		$	39,566		$	41,077
Supplemental information:
Interest paid, net of amounts capitalized	$	66,623		$	65,552		$	58,730
Income taxes paid	$	43,225		$	24,247		$	6,850

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 39

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, 2012		46,148	$	47,778	$	828,777	$	(50,745	)	$	484,369		$	(1,681	)	$	1,308,498		$	—
Common stock issuances		208		208		11,744											11,952
Net income (loss)											145,320			(447	)		144,873
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost,net of tax (Notes 5 and 10)								6,973									6,973
Amounts reclassified to net income, net of tax (Notes 5 and 13)								2,074									2,074
Dividends declared
Common: $1.32 per share											(61,975	)					(61,975	)
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	)

Southwest Gas Corporation 40

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
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
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

* At December 31, 2015, 3.6 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 17,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10).

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 41

Notes to Consolidated Financial Statements

Note 1 – Summary of Significant Accounting Policies

Nature of Operations.    Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a 96.6% owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations occur in 20 major markets in the U.S. and within the provinces of British Columbia and Ontario in Canada, and are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). The Company acquired Link-Line, W.S. Nicholls, and Brigadier in October 2014. See Note 17 – Acquisition of Construction Services Businesses for more information.

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 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 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 (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 Company’s investment in Western totaled $14.7 million and $10.8 million at December 31, 2014 and 2015, respectively. Both periods include the impacts of foreign currency exchange translation adjustments. No dividends were paid during 2015. 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

Southwest Gas Corporation 42

$14.7 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 are deemed worthless. Centuri recorded earnings of $310,000 from this investment in 2015 which is included in Other Income (deductions) in the Consolidated Statements of Income.

Centuri, through its subsidiaries, also has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture. Any future changes to the values of these entities will be recorded by Centuri using the equity method.

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 (millions of dollars):

	2015			2014
Centuri property, equipment, and intangibles	$	423		$	405
Centuri accumulated provision for depreciation and amortization		(221	)		(187	)
Net cash surrender value of COLI policies		99			99
Other property		13			10
Total	$	314		$	327

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 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 $24 million in 2015 and $23 million in 2014 (carried at weighted average cost), and also includes natural gas stored underground and liquefied natural gas, in addition to prepaid assets.

Income Taxes.    The Company uses the asset and liability method of accounting 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. 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, 2015, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

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,

Southwest Gas Corporation 43

cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents at December 31, 2015 and 2014 also includes two money market fund investments totaling approximately $250,000 which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

Significant non-cash investing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $3.1 million, $8.1 million, and $9.3 million during 2015, 2014, and 2013, 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.

Goodwill.    Goodwill is assessed for impairment annually in October, 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 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 any reporting unit is less than its carrying amount in 2014 or 2015. Thus, no impairment was recorded in 2014 or 2015. The acquisition date adjustment shown in the table below was recorded in the first quarter of 2015. No acquisition date adjustments occurred subsequently. The business of Brigadier was acquired via asset purchase. Therefore, goodwill assigned to Brigadier is expected to be deductible for tax purposes, resulting in an after-tax value of $4.9 million. All other goodwill associated with the acquisition is not deemed deductible for tax purposes.

	Natural Gas Operations		Construction Services			Consolidated
(In thousands of dollars)
December 31, 2014	$	10,095	$	133,065		$	143,160
Acquisition date adjustment		—		1,380			1,380
Foreign currency translation adjustment		—		(18,395	)		(18,395	)
December 31, 2015	$	10,095	$	116,050		$	126,145

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 the 2014 acquisition of construction services businesses and have finite lives.

Southwest Gas Corporation 44

Centuri has $36.8 million and $48.2 million of intangible assets (varies due to foreign currency translation) at December 31, 2015 and 2014, respectively, as detailed in the following table (thousands of dollars):

December 31, 2015	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
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
December 31, 2014	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	37,059	$	(524	)	$	36,535
Trade names and trademarks		10,208		(241	)		9,967
Customer contracts backlog		1,912		(724	)		1,188
Noncompete agreement		519		(34	)		485
Total	$	49,698	$	(1,523	)	$	48,175

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):

2016	$	2,809
2017		2,809
2018		2,605
2019		1,971
2020		1,906

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 recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals.

Southwest Gas Corporation 45

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. The Company 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, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, acquisition and acquisition-related costs, and office-related fixed costs of Centuri. During 2015, construction expenses were impacted by a loss reserve on an industrial construction project in Canada recognized earlier in the year, in the amount of $7.7 million. Delays in delivery of critical equipment to the job site resulted in production inefficiencies and an increase in total project costs. Work commenced on this project in March 2015 and was completed in the third quarter. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and a loss recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December 2015, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

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.

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. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and

Southwest Gas Corporation 46

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.

	2015		2014		2013
(In thousands)
AFUDC:
Debt portion	$	1,666	$	1,228	$	1,260
Equity portion		3,008		1,995		2,274
AFUDC capitalized as part of utility plant	$	4,674	$	3,223	$	3,534

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):

	2015			2014			2013
Change in COLI policies	$	(500	)	$	5,300		$	12,400
Interest income		2,173			2,602			461
Equity AFUDC		3,008			1,995			2,274
Foreign currency transaction gain (loss)		(824	)		(178	)		—
Equity in earnings of unconsolidated investment - Western		310			107			—
Miscellaneous income and (expense)		(1,288	)		(2,719	)		(2,835	)
Total other income (deductions)	$	2,879		$	7,107		$	12,300

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences.

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

Southwest Gas Corporation 47

Earnings Per Share.    Basic earnings per share (“EPS”) are calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during the period. 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.

	2015		2014		2013
(In thousands)
Average basic shares		46,992		46,494		46,318
Effect of dilutive securities:
Stock options		8		17		26
Performance shares		171		215		231
Restricted stock units		212		218		183
Average diluted shares		47,383		46,944		46,758

Recently Issued Accounting Standards Updates.    In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. In accordance with the update, an entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. In April 2015, the FASB voted to propose, and in July 2015 it approved, a one-year deferral of the effective date (annual periods beginning after December 15, 2017), but to permit entities to adopt one year earlier if they choose (i.e., the original effective date). The FASB decided, based on its outreach to various stakeholders and the forthcoming exposure drafts, which amend the update, that a deferral is necessary to provide adequate time to effectively implement the update. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2018. The Company is evaluating what impact this update might have on its consolidated financial statements and disclosures.

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

In April 2015, the FASB issued the update “Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs.” To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. While balance sheet presentation is impacted by the update, the recognition and measurement of debt issuance costs are not.

Southwest Gas Corporation 48

Retrospective application of the update is required. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2015. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. The Company adopted this update as of December 31, 2015, as permitted. See Note 7 – Long-Term Debt for additional information.

In May 2015, the FASB issued the update “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent).” This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the net asset value per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments that calculate net asset value per share (or its equivalent), but for which the practical expedient is not applied, will continue to be included in the fair value hierarchy. The update removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. A reporting entity should continue to disclose information on investments for which fair value is measured at net asset value as a practical expedient to help users understand the nature and risks of the investments and whether the investments, if sold, are probable of being sold at amounts different from net asset value. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods thereafter. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 10 – Pension and Other Postretirement Benefits for additional information.

In November 2015, the FASB issued the update “Income Taxes (Topic 740)” in order to simplify the presentation of deferred income taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The previous guidance required an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 12 – Income Taxes for additional information.

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 organization to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the organization has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. All entities can early adopt the provision to record fair value changes for financial liabilities under the fair value option resulting from instrument-specific credit risk in other comprehensive income. The Company is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

Southwest Gas Corporation 49

Subsequent Events.    Management of the Company 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, 2015 and 2014 was as follows (thousands of dollars):

December 31,	2015			2014
Gas plant:
Storage	$	22,944		$	22,531
Transmission		312,996			312,300
Distribution		4,935,730			4,655,640
General		365,865			356,072
Software and software-related intangibles		203,323			196,035
Other		14,059			14,021
		5,854,917			5,556,599
Less: accumulated depreciation		(2,084,007	)		(1,973,098	)
Acquisition adjustments, net		370			550
Construction work in progress		119,805			74,332
Net utility plant	$	3,891,085		$	3,658,383

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 2015, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2014 and 2013 also approximated 3.6% on average.

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

	2015		2014		2013
Depreciation and amortization expense	$	201,233	$	194,360	$	185,283

Included in the figures above is amortization of intangibles of $12.7 million in 2015, $11.7 million in 2014, and $10.3 million in 2013.

Operating Leases and Rentals.    The Company leases certain office and construction equipment. 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):

	2015		2014		2013
Southwest Gas	$	4,186	$	5,330	$	8,308
Centuri		45,849		30,012		27,118
Consolidated rental payments/lease expense	$	50,035	$	35,342	$	35,426

Southwest Gas Corporation 50

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	6,836
2017		4,732
2018		2,993
2019		2,110
2020		1,473
Thereafter		3,583
Total minimum lease payments	$	21,727

Capital Leases.    Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2015 and 2014 are as follows (thousands of dollars):

December 31,	2015			2014
Capital leases of equipment	$	4,584		$	5,763
Less: accumulated amortization		(1,043	)		(287	)
Net capital leases	$	3,541		$	5,476

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	1,469
2017		869
2018		494
2019		21
2020		—
Thereafter		—
		2,853
Less: amount representing interest		(223	)
Total minimum lease payments	$	2,630

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, 2015 and 2014, and the percentage of customers in each of the three states.

	December 31, 2015		December 31, 2014
Gas utility customer accounts receivable balance (in thousands)	$	151,775	$	136,148

Southwest Gas Corporation 51

	December 31, 2015
Percent of customers by state
Arizona		53	%
Nevada		37	%
California		10	%

Although the Company 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, 2012	$	2,504
Additions charged to expense		3,583
Accounts written off, less recoveries		(4,362	)
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

At December 31, 2015, the construction services segment (Centuri) had $162 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs have been insignificant and are not reflected in the table above.

Note 4 – Regulatory Assets and Liabilities

Natural gas operations are 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.

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

December 31,	2015			2014
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	384,647		$	390,293
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,486			5,425
Deferred purchased gas costs (3)		3,591			87,556
Accrued purchased gas costs (4)		—			2,600
Unamortized premium on reacquired debt (5)		21,511			20,478
Other (6)		73,022			72,132
		488,257			578,484
Regulatory liabilities:
Deferred purchased gas costs (3)		(45,601	)		—
Accumulated removal costs		(303,000	)		(304,000	)
Accrued purchased gas costs (4)		(10,400	)		—
Deferred gain on southern Nevada division operations facility (7)		—			(115	)
Unamortized gain on reacquired debt (8)		(10,325	)		(10,862	)
Other (9)		(36,631	)		(34,233	)
Net regulatory assets	$	82,300		$	229,274

(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 the Company’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13).

Instrument	Balance Sheet Location	2015		2014
Swaps	Deferred charges and other assets	$	1,219	$	363
Swaps	Prepaids and other current assets		4 ,267		5,062

(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.

(6) Other regulatory assets including deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as margin and interest-tracking accounts, amounts associated with accrued absence time, and deferred post-retirement benefits other than pensions. Recovery periods vary.

(7) The amortization period ended October 2015.

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

(9) Other regulatory liabilities include amounts associated with income tax and gross-up.

Southwest Gas Corporation 53

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)				2015									2014									2013
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214
Amortization of prior service cost		1,335			(507	)		828			355			(135	)		220			355			(135	)		220
Amortization of net actuarial (gain)/loss		34,381			(13,065	)		21,316			23,656			(8,989	)		14,667			34,177			(12,987	)		21,190
Prior service cost		—			—			—			(6,661	)		2,531			(4,130	)		—			—			—
Regulatory adjustment		(5,646	)		2,146			(3,500	)		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)
Pension plans other comprehensive income (loss)		(449	)		171			(278	)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973
Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities):
Amounts reclassified into net income		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
FSIRS other comprehensive income (loss)		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
Foreign currency translation adjustments:
Translation adjustments		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Foreign currency other comprehensive income (loss)		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Total other comprehensive income (loss)	$	941		$	(1,100	)	$	(159	)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047

(1) Tax amounts are calculated using a 38% rate. The Company 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, the Company 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.

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	$	25,000
SERP net actuarial loss		1,400
PBOP net actuarial loss		400
PBOP prior service cost		1,300

Southwest Gas Corporation 54

Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, included in AOCI at December 31, 2015, 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			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit		After- Tax			AOCI
Beginning Balance AOCI December 31, 2014	$	(57,211)		$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)
Net actuarial gain/(loss)		(30,519	)		11,597			(18,922	)		—			—			—			—			—		—			(18,922	)
Translation adjustments		—			—			—			—			—			—			(1,954	)		—		(1,954	)		(1,954	)
Other comprehensive income before reclassifications		(30,519	)		11,597			(18,922	)		—			—			—			(1,954	)		—		(1,954	)		(20,876	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,344			(1,271	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		1,335			(507	)		828			—			—			—			—			—		—			828
Amortization of net actuarial loss (2)		34,381			(13,065	)		21,316			—			—			—			—			—		—			21,316
Regulatory adjustment (3)		(5,646	)		2,146			(3,500	)		—			—			—			—			—		—			(3,500	)
Net current period other comprehensive income (loss)		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,954	)		—		(1,954	)		(159	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(66	)		—		(66	)		(66	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,888	)		—		(1,888	)		(93	)
Ending Balance AOCI December 31, 2015	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)

(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 Benefitsfor 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).

Southwest Gas Corporation 55

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, 2015 and 2014:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2015			2014
Net actuarial (loss) gain	$	(435,269	)	$	(439,131	)
Prior service cost		(7,038	)		(8,373	)
Less: amount recognized in regulatory assets		384,647			390,293
Recognized in AOCI	$	(57,660	)	$	(57,211	)

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 the Company’s common stock from time to time in at-the-market offerings under the prospectus included therein and in accordance with the Sales Agency Agreement, dated March 10, 2015, between the Company and BNY Mellon Capital Markets, LLC (the “Equity Shelf Program”). During 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds to the Company of $35,167,584, net of $355,228 in agent commissions. No sales occurred in the fourth quarter of 2015. As of December 31, 2015, the Company had up to $64,477,188 of common stock available for sale under the program. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

In addition, during 2015, the Company issued approximately 209,000 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, 2015 and December 31, 2014 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within 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

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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,	2015					2014
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	130,273	$	125,000		$	133,403
Notes, 6.1%, due 2041		125,000			141,581		125,000			157,290
Notes, 3.875%, due 2022		250,000			253,600		250,000			262,030
Notes, 4.875%, due 2043		250,000			251,483		250,000			280,903
8% Series, due 2026		75,000			97,035		75,000			102,296
Medium-term notes, 7.59% series, due 2017		25,000			26,253		25,000			27,573
Medium-term notes, 7.78% series, due 2022		25,000			29,855		25,000			31,144
Medium-term notes, 7.92% series, due 2027		25,000			31,890		25,000			33,695
Medium-term notes, 6.76% series, due 2027		7,500			8,684		7,500			9,156
Unamortized discount and debt issuance costs		(6,137	)				(6,604	)
		901,363					900,896
Revolving credit facility and commercial paper		150,000			150,000		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:
5.25% 2003 Series D, due 2038		—			—		20,000			20,277
5.00% 2004 Series B, due 2033		—			—		31,200			31,223
4.85% 2005 Series A, due 2035		100,000			100,452		100,000			100,071
4.75% 2006 Series A, due 2036		24,855			25,130		24,855			25,399
Unamortized discount and debt issuance costs		(3,946	)				(5,964	)
		320,909					370,091
Centuri term loan facility		112,571			112,665		142,071			143,021
Unamortized debt issuance costs		(692	)				(816	)
		111,879					141,255
Centuri secured revolving credit facility		60,627			60,724		57,196			57,320
Centuri other debt obligations		25,901			26,059		31,128			31,127
		1,570,679					1,650,566
Less: current maturities		(19,475	)				(19,192	)
Long-term debt, less current maturities	$	1,551,204				$	1,631,374

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In March 2015, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2019, but was extended to March 2020. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At December 31, 2015, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility, including $50 million in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 1.45% at December 31, 2015. Borrowings under the credit facility ranged from none during the second quarter of 2015 to a high of $180 million during the fourth quarter of 2015. With regard to the short-term portion of the credit facility, there was $18 million outstanding at December 31, 2015 and $5 million outstanding at December 31, 2014. (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, 2015, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 1.01% at December 31, 2015.

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

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

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. In January 2016, administrative amendments were made to the revolving credit and term loan facility with no impact to borrowing capacity, due dates, or interest provisions. 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, 2015 totaled $437 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 the consolidated leverage ratio. The

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commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the revolving credit facility ranged from a low of $60.6 million during December 2015 to a high of $105.2 million during May 2015. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.46% at December 31, 2015.

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

	December 31, 2015			December 31, 2014
2003 Series A		0.87	%		0.85	%
2008 Series A		0.87	%		0.90	%
2009 Series A		0.75	%		0.89	%
Tax-exempt Series A		0.81	%		0.84	%

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

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

2016	$	19,475
2017		42,245
2018		14,906
2019		142,452
2020		275,238

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company 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, 2015, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $2.2 billion in additional debt and meet the leverage ratio requirement. The Company has at least $1 billion of cushion in equity relating to the minimum net worth requirement.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2015, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $75 million in additional debt and meet the leverage ratio requirement. Centuri has at least $15 million of cushion relating to the minimum fixed charge ratio coverage requirement.

Early Adoption of Accounting Standards Update (“ASU”) No. 2015-03. As of December 31, 2015, the Company adopted FASB ASU No. 2015-03 “Interest-Imputation of Interest (subtopic 835-30)”. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The adoption of this update is considered a change in an accounting principle. Upon adoption, the 2014 amounts in the Consolidated Balance Sheets were restated for Long-term debt (from $1,637,592,000 to $1,631,374,000), Deferred charges and other assets (from $478,625,000 to $472,579,000), and Prepaids and other current assets (from $99,975,000 to $99,803,000). The 2014 amounts in the debt listing table for unamortized discount and debt issuance costs for debentures and IDRBs previously included only amounts

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associated with unamortized discount, ($5,223,000) for debentures and ($1,943,000) for IDRBs. The difference between the associated figures in the debt listing table and these figures are amounts associated with unamortized debt issue costs reclassified in accordance with the update.

In a related update, the SEC provided guidance that for line-of-credit (“LOC”) arrangements, companies could elect to present debt issuance costs within assets, regardless of whether there is an outstanding balance on such borrowings. Making such an election may make presentations less confusing as net negative balances would otherwise result in cases when there are no outstanding LOC borrowings but associated issuance costs are still being amortized. Therefore, for LOC arrangements, such as Southwest’s revolving credit facility and Centuri’s secured revolving credit portion of its facility, the Company has elected, as permitted, to continue to recognize unamortized debt issuance costs within its asset categories and no such amounts have been reclassified. The unamortized debt issuance costs associated with the term loan portion of Centuri’s $300 million facility, ($816,000), have been reclassified as a deduction from the related 2014 debt balance. The debt listing table has been updated to reflect these changes based on the elections made.

Note 8 – Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2020, of which $150 million has been designated by management for working capital purposes. The Company had $18 million in short-term borrowings outstanding at December 31, 2015 and $5 million in short-term borrowings outstanding at December 31, 2014. The effective interest rate on the short-term portion of the credit facility was 1.37% 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 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 or results of operations.

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers would be responsible for amounts up to the policy limits. For the policy year August 2015 to July 2016, 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, the Company may determine that certain costs are likely to be incurred in the future related to specific legal matters. In these circumstances and in accordance with accounting policies, the Company will make an accrual, as necessary.

Note 10 – Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches one-half of amounts deferred by employees, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. Centuri has a separate plan, the cost and liability of which are not significant. The cost of the Southwest plan is listed below (in thousands):

	2015		2014		2013
Employee Investment Plan cost	$	5,072	$	4,816	$	4,850

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Southwest has a deferred compensation plan for 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. Southwest matches one-half of amounts deferred by officers, 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.

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

The Company recognizes the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in its 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.

The Company has established a regulatory asset 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.

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 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, 2015, the percentage ranges of the target portfolio are:

Type of Investment	Percentage Range
Equity securities		59 to 71
Debt securities		31 to 37
Other		up to 5

The Company’s 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

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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, the Company 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.

Due to a higher interest rate environment for high-quality fixed income investments, the Company increased the discount rate at December 31, 2015 from 2014. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also raised (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, 2015			December 31, 2014
Discount rate		4.50	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		2.75	%
Asset return assumption		7.25	%		7.75	%

Pension expense for 2016 is estimated to decrease by $6.7 million compared to 2015 notably due to the higher discount rate and lower mortality projection. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

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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.

	2015									2014
	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)	$	1,060,240		$	41,176		$	72,202		$	886,714		$	36,143		$	58,020
Service cost		25,123			320			1,641			21,360			292			1,101
Interest cost		44,229			1,695			2,999			43,440			1,745			2,829
Plan amendments		—			—			—			—			—			6,661
Actuarial loss (gain)		(44,553	)		2,322			(3,251	)		144,606			5,459			4,567
Benefits paid		(40,222	)		(2,793	)		(959	)		(35,880	)		(2,463	)		(976	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,044,817			42,720			72,632			1,060,240			41,176			72,202
Change in plan assets
Market value of plan assets at beginning of year		754,796			—			44,892			719,944			—			42,314
Actual return on plan assets		(13,694	)		—			(1,034	)		34,732			—			2,859
Employer contributions		36,000			2,793			—			36,000			2,463			—
Benefits paid		(40,222	)		(2,793	)		(274	)		(35,880	)		(2,463	)		(281	)
Market value of plan assets at end of year		736,880			—			43,584			754,796			—			44,892
Funded status at year end	$	(307,937	)	$	(42,720	)	$	(29,048	)	$	(305,444	)	$	(41,176	)	$	(27,310	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.50	%		4.50	%		4.50	%		4.25	%		4.25	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		N/A			2.75	%		2.75	%		N/A

Estimated funding for the plans above during calendar year 2016 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, 2015		December 31, 2014
Retirement plan	$	922,992	$	886,215
SERP		39,270		39,125

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

	2016	2017	2018	2019		2020		2021-2025
Pension	$44.0	$45.5	$47.2		$48.9		$50.5		$283.5
PBOP	3.9	4.1	4.3		4.5		4.5		21.3
SERP	2.8	2.8	2.8		2.9		2.9		14.1

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 7.5% declining to 4.5%. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but 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
	2015			2014			2013			2015			2014			2013			2015			2014			2013
(Thousands of dollars)
Service cost	$	25,123		$	21,360		$	23,056		$	320		$	292		$	373		$	1,641		$	1,101		$	1,220
Interest cost		44,229			43,440			37,607			1,695			1,745			1,535			2,999			2,829			2,482
Expected return on plan assets		(57,808	)		(53,342	)		(49,840	)		—			—			—			(3,464	)		(3,264	)		(2,824	)
Amortization of prior service cost		—			—			—			—			—			—			1,335			355			355
Amortization of net actuarial loss		32,743			22,873			32,261			1,293			783			971			345			—			945
Net periodic benefit cost	$	44,287		$	34,331		$	43,084		$	3,308		$	2,820		$	2,879		$	2,856		$	1,021		$	2,178
Weighted-average assumptions (net benefit cost)
Discount rate		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%
Expected return on plan assets		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%		2.75	%		2.75	%		3.25	%		2.75	%		N/A			N/A			N/A

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

	2015												2014												2013
	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)	$	30,519		$	26,949		$	2,322		$	1,248		$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)
Amortization of prior service cost (b)		(1,335	)		—			—			(1,335	)		(355	)		—			—			(355	)		(355	)		—			—			(355	)
Amortization of net actuarial loss (b)		(34,381	)		(32,743	)		(1,293	)		(345	)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)
Prior service cost		—			—			—			—			6,661			—			—			6,661			—			—			—			—
Regulatory adjustment		5,646			5,214			—			432			(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868
Recognized in other comprehensive
(income) loss		449			(580	)		1,029			—			15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—
Net periodic benefit costs recognized in net income		50,451			44,287			3,308			2,856			38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,900		$	43,707		$	4,337		$	2,856		$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178

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.

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, 2015 and December 31, 2014. The SERP has no assets. The FASB issued guidance in 2015, which the Company has adopted early as permitted, removing the requirement to categorize assets in the fair value hierarchy that are measured using the net asset value (“NAV”) practical

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expedient. See note (3) to the table below. Based on this guidance, no Level 3 assets existed (nor are reflected in the table below) at December 31, 2015 and December 31, 2014.

	December 31, 2015								December 31, 2014
	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		$	6,661	$	198	$	6,859
Capital equipment		533			16		549			2,222		66		2,288
Chemicals/materials		3,304			98		3,402			5,233		155		5,388
Consumer goods		41,035			1,221		42,256			41,731		1,238		42,969
Energy and mining		11,066			329		11,395			18,502		549		19,051
Finance/insurance		29,957			892		30,849			20,685		613		21,298
Healthcare		37,930			1,129		39,059			37,846		1,122		38,968
Information technology		29,229			870		30,099			25,881		767		26,648
Services		12,341			367		12,708			28,846		855		29,701
Telecommunications/internet/media		25,883			770		26,653			18,498		549		19,047
Other		9,043			269		9,312			10,958		325		11,283
Real estate investment trusts		5,010			149		5,159			5,713		169		5,882
Mutual funds		87,483			23,985		111,468			86,159		24,567		110,726
Government fixed income securities		33,482			996		34,478			44,694		1,325		46,019
Preferred securities		—			—		—			568		17		585
Futures contracts		(7	)		—		(7	)		—		—		—
Total Level 1 Assets (1)	$	333,310		$	31,300	$	364,610		$	354,197	$	32,515	$	386,712
Level 2 – Significant other observable inputs
Government fixed income and mortgage backed securities	$	49,571		$	1,475	$	51,046		$	48,312	$	1,433	$	49,745
Corporate fixed income securities
Asset-backed and mortgage-backed		23,542			701		24,243			27,071		803		27,874
Banking		20,857			621		21,478			23,289		691		23,980
Insurance		4,896			146		5,042			6,182		183		6,365
Utilities		3,826			114		3,940			4,232		126		4,358
Other		30,995			922		31,917			23,120		686		23,806
Pooled funds and mutual funds		14,808			796		15,604			11,968		984		12,952
Real estate investment trusts		1,949			58		2,007			—		—		—
State and local obligations		950			28		978			1,499		44		1,543
Preferred securities		554			17		571			—		—		—
Convertible securities		196			6		202			—		—		—
Total Level 2 assets (2)	$	152,144		$	4,884	$	157,028		$	145,673	$	4,950	$	150,623
Total Plan assets at fair value	$	485,454		$	36,184	$	521,638		$	499,870	$	37,465	$	537,335
Commingled equity funds (3)		250,511			7,455		257,966			259,235		7,687		266,922
Insurance company general account contracts (4)		3,719			—		3,719			4,003		—		4,003
Total Plan assets (5)	$	739,684		$	43,639	$	783,323		$	763,108	$	45,152	$	808,260

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

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 balanced fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income.

(2) The fair value of investments in debt securities with remaining maturities of one year or more is 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.

The pooled funds and mutual funds are two collective short-term funds that invest in Treasury bills and money market funds. These funds are used as a temporary cash repository for the pension plan’s various investment managers.

(3) The commingled equity funds include 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 include:

• 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 may be redeemed vary among the funds; the notice required ranges from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds requires the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminishes the greater the transaction. Other such funds may impose fees to recover direct costs incurred by the fund at redemption, but are indeterminable prior to redemption.

Early adoption of ASU No. 2015-07: As permitted the Company adopted (earlier than the required adoption date) FASB ASU No. 2015-07 “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent)” as of December 31, 2015. This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the NAV per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the NAV per share practical expedient. The FASB determined that including those assets in the fair value hierarchy is potentially confusing and misleading to financial statement users. The fair value of the commingled equity funds was determined using NAV as an expedient since no significant observable inputs were available (these funds are not publicly traded on an exchange). Because of the requirements of

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this update, the commingled equity funds are no longer included in the above fair value hierarchy table as a Level 3 fair value measurement but instead are disclosed as a reconciling item to the table. The associated Fair Value Measurement Using Significant Unobservable Inputs (Level 3) table is no longer presented due to this change, as the commingled equity funds were the only assets whose values were previously indicated to be Level 3 fair value measurements.

(4) 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.

(5) The assets in the above table exceed 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) and $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) for 2015 and 2014, respectively, 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, 2015, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan which includes a cash award, and a restricted stock/unit plan. 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):

	2015		2014		2013
Stock-based compensation plan expense, net of related tax benefits	$	7,278	$	8,130	$	8,012
Stock-based compensation plan related tax benefits		4,461		4,983		4,910

Under the option plan, the Company previously granted options to purchase shares of common stock, 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 Company common stock on the date of grant and a maximum term of ten years. Therefore, remaining options, if not exercised prior to the anniversary date of the 2006 grant (in 2016), will then expire.

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

	2015					2014					2013
	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		36		$	28.97		52		$	27.57		125		$	28.13
Exercised during the year		(19	)		26.69		(16	)		24.31		(72	)		28.44
Forfeited or expired during the year		—			—		—			—		(1	)		33.07
Outstanding and exercisable at year end		17		$	31.64		36		$	28.97		52		$	27.57

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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):

	2015		2014		2013
Outstanding and exercisable	$	394	$	1,194	$	1,473
Exercised		590		451		1,402

	December 31, 2015		December 31, 2014		December 31, 2013
Market value of Southwest Gas stock	$	55.16	$	61.81	$	55.91

The weighted-average remaining contractual life for outstanding options was less than one year for 2015. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2015 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$29.08 to $33.07		17		0.5 Years	$	31.64

The Company received $523,000 in cash from the exercise of options during 2015 and a corresponding tax benefit of $218,000 which was recorded in additional paid-in capital.

Under the performance share stock plan, the Company may issue performance shares to encourage key employees to remain in its employment 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.

The Company awards restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. 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 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, 2015 (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		271		$	43.71		257		$	41.22
Granted		80			63.09		73			63.09
Dividends		6					7
Forfeited or expired		—			—		—			—
Vested and issued*		(160	)		43.12		(109	)		46.65
Nonvested/unissued at December 31, 2015		197		$	50.63		228		$	44.36

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

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The average grant date fair value of performance shares and restricted stock/units granted in 2014 and 2013 was $53.73 and $44.83, respectively.

As of December 31, 2015, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million.

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,	2015			2014			2013
U.S.	$	221,660		$	221,471		$	222,815
Foreign		(2,328	)		(1,950	)		—
Total income before income taxes	$	219,332		$	219,521		$	222,815

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

Year Ended December 31,	2015			2014			2013
Current:
Federal	$	21,321		$	1,739		$	3,549
State		9,899			5,073			5,107
Foreign		650			2,193			—
		31,870			9,005			8,656
Deferred:
Federal		51,132			71,439			67,414
State		(2,574	)		614			1,872
Foreign		(526	)		(2,685	)		—
		48,032			69,368			69,286
Total income tax expense	$	79,902		$	78,373		$	77,942

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

Year Ended December 31,	2015			2014			2013
Deferred federal and state:
Property-related items	$	65,931		$	52,814		$	62,737
Purchased gas cost adjustments		(32,993	)		15,049			16,189
Employee benefits		623			109			(2,769	)
All other deferred		15,332			2,257			(6,010	)
Total deferred federal and state		48,893			70,229			70,147
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	48,032		$	69,368		$	69,286

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A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2013, 2014, and 2015 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2015			2014			2013
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.8			1.9			2.4
Property-related items		0.1			0.1			0.1
Tax credits		(0.4	)		(0.5	)		(0.4	)
Company owned life insurance		0.1			(1.0	)		(2.1	)
All other differences		(0.2	)		0.2			—
Consolidated effective income tax rate		36.4	%		35.7	%		35.0	%

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

December 31,	2015			2014
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	1,614		$	2,146
Employee benefits		36,923			31,557
Alternative minimum tax credit		4,809			20,172
Net operating losses and credits		868			9,719
Interest rate swap		7,351			8,622
Other		24,636			25,872
Valuation allowance		(499	)		(253	)
		75,702			97,835
Deferred tax liabilities:
Property-related items, including accelerated depreciation		794,850			736,810
Regulatory balancing accounts		743			33,736
Unamortized ITC		2,549			3,410
Debt-related costs		5,497			5,066
Intangibles		9,547			12,792
Other		31,533			27,600
		844,719			819,414
Net deferred tax liabilities		769,017			721,579
Current		—			(2,109	)
Noncurrent		769,017			723,688
Net deferred tax liabilities	$	769,017		$	721,579

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 2011.

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At December 31, 2015, the Company has U.S. federal net capital loss carryforwards of $505,000, which begin to expire in 2016. At December 31, 2015, the Company has an income tax net operating loss carryforward related to Canadian operations of $3 million which begins to expire in 2032.

As of December 31, 2015, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

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

	2015			2014
Unrecognized tax benefits at beginning of year	$	305		$	—
Gross increases-tax positions in prior period		—			305
Gross decreases-tax positions in prior period		(9	)		—
Gross increases-current period tax positions		—			—
Gross decreases-current period tax positions		—			—
Settlements		—			—
Lapse in statute of limitations		—			—
Unrecognized tax benefits at end of year	$	296		$	305

In assessing whether uncertain tax positions should be recognized in its financial statements, Southwest 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, Southwest 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, Southwest 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. Southwest recognizes unrecognized tax benefits 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. Southwest’s measurement of its 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 $0 at December 31, 2015. 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 2015, 2014, and 2013.

Southwest Gas Corporation 72

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. The Company expects the IRS to issue natural gas industry guidance which 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, the Company expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.

Early Adoption of ASU No. 2015-17. As permitted, the Company adopted FASB ASU No. 2015-17 Income Taxes (Topic 740) as of December 31, 2015. This ASU simplifies the presentation of deferred income taxes in that deferred tax liabilities and assets will now be classified as noncurrent in the Consolidated Balance Sheets instead of current and noncurrent. The adoption of this ASU is considered a change in accounting principle. The Company chose to apply the content of the update prospectively as permitted. Prior periods were not retrospectively updated.

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

	December 31, 2015		December 31, 2014
Contract notional amounts		7,407		5,105

In late 2013, the Company suspended using swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

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

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The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2015, 2014, and 2013 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	2015			2014			2013
Swaps	Net cost of gas sold	$	(7,598	)	$	(2,363	)	$	976
Swaps	Net cost of gas sold		7,598	*		2,363	*		(976	)*
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. The second FSIRS terminated in March 2012. Losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) into interest expense.

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

Fair values of derivatives not designated as hedging instruments:

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	)
December 31, 2014 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(5,062	)	$	(5,062	)
Swaps	Other deferred credits		—		(363	)		(363	)
Total		$	—	$	(5,425	)	$	(5,425	)

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

Southwest Gas Corporation 74

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

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

	Year ended December 31, 2015		Year ended December 31, 2014		Year ended December 31, 2013
(Thousands of dollars)
Paid to counterparties	$	7,537	$	829	$	3,148
Received from counterparties	$	—	$	4,713	$	915

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

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
December 31, 2014 Instrument	Balance Sheet Location		Net Total
Swaps		Prepaids and other current assets	$	5,062
Swaps		Deferred charges and other assets		363

Fair Value Measurements.     The estimated fair values of Southwest’s Swaps were determined at December 31, 2015 and 2014 using New York Mercantile Exchange (“NYMEX”) futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measurement.

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The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (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, 2015			December 31, 2014
(Thousands of dollars)
Liabilities at fair value:
Other current liabilities—Swaps	$	(4,267	)	$	(5,062	)
Other deferred credits—Swaps		(1,219	)		(363	)
Net Assets (Liabilities)	$	(5,486	)	$	(5,425	)

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.

Note 14 – Segment Information

Company 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 (market) 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, 2015		December 31, 2014
Accounts receivable for Centuri services	$	10,006	$	9,169

The following table presents the amount of revenues and long-lived assets for both segments by geographic area (thousands of dollars):

	December 31, 2015		December 31, 2014
Revenues (a)
United States	$	2,289,133	$	2,069,513
Canada		174,492		52,194
Total	$	2,463,625	$	2,121,707

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

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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, 2015 is as follows (thousands of dollars):

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
2013	Gas Operations		Construction Services		Adjustments (b)			Total
Revenues from unaffiliated customers	$	1,300,154	$	562,475				$	1,862,629
Intersegment sales		—		88,153					88,153
Total	$	1,300,154	$	650,628				$	1,950,782
Interest revenue	$	456	$	5				$	461
Interest expense	$	62,555	$	1,145				$	63,700
Depreciation and amortization	$	193,848	$	42,969				$	236,817
Income tax expense	$	65,377	$	12,565				$	77,942
Segment net income	$	124,169	$	21,151				$	145,320
Segment assets	$	4,272,029	$	293,811	$	(666	)	$	4,565,174
Capital expenditures	$	314,578	$	49,698				$	364,276

Southwest Gas Corporation 77

(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.

(b) Construction services segment assets included income taxes payable of $666,000 in 2013, which was netted against gas operations segment income taxes receivable, net during consolidation.

Note 15 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30		September 30			December 31
(Thousand of dollars, except per share amounts)
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
2013
Operating revenues	$	613,505	$	411,574	$	387,346		$	538,357
Operating income		138,394		28,908		6,141			100,772
Net income (loss)		80,674		10,067		(3,057	)		57,189
Net income (loss) attributable to Southwest Gas Corporation		80,773		10,108		(2,864	)		57,303
Basic earnings (loss) per common share*		1.75		0.22		(0.06	)		1.24
Diluted earnings (loss) per common share*		1.73		0.22		(0.06	)		1.22

* 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 the operations of the Company. 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

Southwest Gas Corporation 78

discussion of operating results. Additionally, see Note 16 – Construction Services Noncontrolling Interests regarding allocation of earnings and Note 17 – Acquisition of Construction Services Businesses regarding the acquisition in the last quarter of 2014.

Note 16 – Construction Services Noncontrolling Interests

Associated with the agreement reached in conjunction with the acquisition of the Canadian constriction businesses, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses. The agreement, associated with that approximate 10% equity interest, provided 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 continue to be able to exit their investment retained by requiring the purchase of a portion of their interest commencing July 2017 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election beginning in July 2022. Due to the continued ability of the noncontrolling parties to redeem their interest for cash, their interest continues to be presented on the Company’s Consolidated Balance Sheet at December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance. However, that interest, previously associated with the Canadian businesses, is now formally an interest in Centuri.

Significant changes in the value of the redeemable noncontrolling interest are recognized as they occur, and the carrying value is adjusted as necessary at each reporting date. Guidance by the SEC indicates that downward adjustments in the value of redeemable noncontrolling interests are only permitted to the extent that upward adjustments in value were previously recognized. A floor for the noncontrolling interest was originally set at the acquisition date (in October 2014). However, U.S. GAAP generally views changes in ownership interest, where the parent retains its controlling interest, as an equity transaction, whereby the carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. In connection with the exchange rights being exercised during the third quarter, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized, due in part to the exchange option no longer being subject to probability estimates. In light of the U.S. GAAP requirement to adjust the carrying amount, a new floor was set for the redeemable noncontrolling interest at the exchange date (July 31, 2015), with a corresponding adjustment made to additional paid in capital of the Company. Future adjustments to the redemption value are not permitted below the new floor. 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, 2014	$	20,042
Net Income (loss) attributable to redeemable noncontrolling interest		939
Foreign currency exchange translation adjustment		(66	)
Centuri distribution to redeemable noncontrolling interest		(99	)
Adjustment to redemption value		(4,708	)
Balance, December 31, 2015	$	16,108

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

Southwest Gas Corporation 79

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. Prior to the exchange rights being exercised in the third quarter of 2015, a Monte Carlo simulation methodology was used to assign a value to the redeemable noncontrolling interest. 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 negative adjustment to the redemption value in the table above reflects the sum of 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.

Note 17 – Acquisition of Construction Services Businesses

In October 2014, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses. The acquisition extended the construction services operations into Canada and provides additional opportunities for market expansion. Funding for the acquisition was primarily provided by a new $300 million secured revolving credit and term loan facility described in Note 7 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”), (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania (“Brigadier”).

Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed in 2014. The Company’s allocation of the purchase price in 2014 was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. The final purchase accounting has been completed. The October 1, 2014 fair values of assets acquired and liabilities assumed, revised during the first quarter of 2015, are as follows (in millions of dollars):

	Acquisition Date		Measurement Period Adjustments			Revised Acquisition Date
Cash, cash equivalents, and restricted cash	$	3	$	—		$	3
Contracts receivable and other receivables		62		—			62
Property, plant and equipment		17		—			17
Other assets		17		(2	)		15
Intangible assets		52		—			52
Goodwill		130		1			131
Total assets acquired		281		(1	)		280
Current liabilities		39		1			40
Deferred income tax—long-term		17		—			17
Other long-term liabilities		4		—			4
Net assets acquired	$	221	$	(2	)	$	219

Southwest Gas Corporation 80

The Company incurred and expensed acquisition costs of $5 million in 2014; no acquisition costs were incurred during 2015.

The allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill consisted of the value associated with the assembled workforce and consolidation of operations. When acquisition-date values were updated in the first quarter of 2015, as reflected in the table above, there was no significant overall impact to the Company’s Consolidated Balance Sheets.

The unaudited pro forma consolidated financial information for fiscal 2014 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning of fiscal 2014) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31, 2014
Total operating revenues	$	2,295,318
Net income attributable to Southwest Gas Corporation	$	149,588
Basic earnings per share	$	3.22
Diluted earnings per share	$	3.19

Southwest Gas Corporation 81

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company 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 Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation 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 the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2015. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 25, 2016

Southwest Gas Corporation 82

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of cash flows and of equity and redeemable noncontrolling interest present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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.

As discussed in Note 12 to the Consolidated Financial Statements, the Company changed the manner in which it classifies deferred income taxes in 2015.

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.

Southwest Gas Corporation 83

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.

PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 25, 2016

Southwest Gas Corporation 84

EX-21.01

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2015

SUBSIDIARY NAME	STATE OF INCORPORATION OR ORGANIZATION TYPE
Carson Water Company	Nevada
Centuri Construction Group, Inc.	Nevada
Vistus Construction Group, Inc.	Nevada
NPL Construction Co.	Nevada
Brigadier Pipelines Inc.	Delaware
Canyon Pipeline Construction Inc.	Nevada
Lynxus Construction Group Inc.	Ontario, Canada
Link-Line Contractors Ltd.	Ontario, Canada
2018429 Ontario Ltd.	Ontario, Canada
W.S. Nicholls Construction Inc.	Ontario, Canada
W.S. Nicholls Industries Inc.	Ontario, Canada
Paiute Pipeline Company	Nevada
Southwest Gas Transmission Company	Limited partnership between Southwest Gas Corporation and Utility Financial Corp.
Southwest Gas Capital III, IV	Delaware
Utility Financial Corp.	Nevada
The Southwest Companies	Nevada

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-208609, 333-202633) and Form S-8 (Nos. 333-200835, 333-185354, 333-168731, 333-155581, 333-106762) of Southwest Gas Corporation of our report dated February 25, 2016 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 25, 2016 relating to the financial statement schedules, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 25, 2016

EX-31.01

Exhibit 31.01

Certification

I, John P. Hester, certify that:

1. I have reviewed this annual report on Form 10-K of Southwest Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2016

/s/ JOHN P. HESTER

John P. Hester

President and Chief Executive Officer

Southwest Gas Corporation

Certification

I, Roy R. Centrella, certify that:

1. I have reviewed this annual report on Form 10-K of Southwest Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2016

/s/ ROY R. CENTRELLA

Roy R. Centrella

Senior Vice President/Chief Financial Officer

Southwest Gas Corporation

EX-32.01

Exhibit 32.01

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2015 as filed with the Securities and Exchange Commission (the “Report”), I, John P. Hester, the President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1) the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.

Dated: February 25, 2016

/s/ John P. Hester

John P. Hester

President and Chief Executive Officer

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2015 as filed with the Securities and Exchange Commission (the “Report”), I, Roy R. Centrella, Senior Vice President/Chief Financial Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1) the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.

Dated: February 25, 2016

/s/ Roy R. Centrella

Roy R. Centrella

Senior Vice President/Chief Financial Officer

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 16, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Trading Symbol	SWX
Entity Registrant Name	SOUTHWEST GAS CORP
Entity Central Index Key	0000092416
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		47,456,479
Entity Public Float			$ 2,503,122,220

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Utility plant:
Gas plant	$ 5,854,917	$ 5,556,599
Less: accumulated depreciation	(2,084,007)	(1,973,098)
Acquisition adjustments, net	370	550
Construction work in progress	119,805	74,332
Net utility plant (Note 2)	3,891,085	3,658,383
Other property and investments (Note 1)	313,531	326,743
Restricted cash		821
Current assets:
Cash and cash equivalents	35,997	39,566
Accounts receivable, net of allowances (Note 3)	314,512	281,824
Accrued utility revenue	74,700	73,900
Income taxes receivable, net	34,175	21,853
Deferred income taxes, net (Note 12)		2,109
Deferred purchased gas costs (Note 4)	3,591	87,556
Prepaids and other current assets (Notes 1, 4, and 13)	95,199	99,803
Total current assets	558,174	606,611
Noncurrent assets:
Goodwill (Note 1)	126,145	143,160
Deferred income taxes (Note 12)	428
Deferred charges and other assets (Notes 2, 4, and 13)	469,322	472,579
Total noncurrent assets	595,895	615,739
Total assets	5,358,685	5,208,297
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 47,377,575 and 46,523,184 shares) (Note 11)	49,007	48,153
Additional paid-in capital	896,448	851,381
Accumulated other comprehensive income (loss), net (Note 5)	(50,268)	(50,175)
Retained earnings	699,221	639,164
Total Southwest Gas Corporation equity	1,594,408	1,488,523
Noncontrolling interest	(2,083)	(2,257)
Total equity	1,592,325	1,486,266
Redeemable noncontrolling interest (Note 16)	16,108	20,042
Long-term debt, less current maturities (Note 7)	1,551,204	1,631,374
Total capitalization	$ 3,159,637	$ 3,137,682
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)	$ 19,475	$ 19,192
Short-term debt (Note 8)	18,000	5,000
Accounts payable	164,857	167,988
Customer deposits	72,631	71,546
Income taxes payable, net	940
Accrued general taxes	47,337	44,339
Accrued interest	16,173	16,468
Deferred purchased gas costs (Note 4)	45,601
Other current liabilities (Notes 2, 4, and 13)	150,031	145,584
Total current liabilities	535,045	470,117
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 12)	769,445	723,688
Accumulated removal costs (Note 4)	303,000	304,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 10, and 13)	591,558	572,810
Total deferred income taxes and other credits	1,664,003	1,600,498
Total capitalization and liabilities	$ 5,358,685	$ 5,208,297

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, par	$ 1	$ 1
Common stock, authorized	60,000,000	60,000,000
Common stock, issued	47,377,575	46,523,184
Common stock, outstanding	47,377,575	46,523,184

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Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues:
Gas operating revenues	$ 1,454,639	$ 1,382,087	$ 1,300,154
Construction revenues	1,008,986	739,620	650,628
Total operating revenues	2,463,625	2,121,707	1,950,782
Operating expenses:
Net cost of gas sold	563,809	505,356	436,001
Operations and maintenance	393,199	383,732	384,914
Depreciation and amortization	270,111	253,027	236,817
Taxes other than income taxes	49,393	47,252	45,551
Construction expenses	898,781	647,857	573,284
Total operating expenses	2,175,293	1,837,224	1,676,567
Operating income	288,332	284,483	274,215
Other income and (expenses):
Net interest deductions (Notes 7 and 8)	(71,879)	(72,069)	(63,700)
Other income (deductions)	2,879	7,107	12,300
Total other income and (expenses)	(69,000)	(64,962)	(51,400)
Income before income taxes	219,332	219,521	222,815
Income tax expense (Note 12)	79,902	78,373	77,942
Net income	139,430	141,148	144,873
Net income (loss) attributable to noncontrolling interests	1,113	22	(447)
Net income attributable to Southwest Gas Corporation	$ 138,317	$ 141,126	$ 145,320
Basic earnings per share (Notes 1 and 15)	$ 2.94	$ 3.04	$ 3.14
Diluted earnings per share (Notes 1 and 15)	$ 2.92	$ 3.01	$ 3.11
Average number of common shares outstanding	46,992	46,494	46,318
Average shares outstanding (assuming dilution)	47,383	46,944	46,758

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Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net Income	$ 139,430	$ 141,148	$ 144,873
Defined benefit pension plans:
Net actuarial gain (loss)	(18,922)	(107,661)	62,214
Amortization of prior service cost	828	220	220
Amortization of net actuarial loss	21,316	14,667	21,190
Prior service cost		(4,130)
Regulatory adjustment	(3,500)	86,991	(76,651)
Net defined benefit pension plans	(278)	(9,913)	6,973
Forward-starting interest rate swaps:
Amounts reclassified into net income	2,073	2,073	2,074
Net forward-starting interest rate swaps	2,073	2,073	2,074
Foreign currency translation adjustments	(1,954)	(659)
Total other comprehensive income (loss), net of tax	(159)	(8,499)	9,047
Comprehensive income	139,271	132,649	153,920
Comprehensive income (loss) attributable to noncontrolling interests	1,047		(447)
Comprehensive income attributable to Southwest Gas Corporation	$ 138,224	$ 132,649	$ 154,367

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$ 139,430	$ 141,148	$ 144,873
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	270,111	253,027	236,817
Deferred income taxes	48,785	64,309	68,639
Changes in current assets and liabilities:
Accounts receivable, net of allowances	(39,850)	(3,683)	(22,556)
Accrued utility revenue	(800)	(1,200)	(700)
Deferred purchased gas costs	129,566	(69,339)	(111,143)
Accounts payable	(3,491)	(41,499)	27,668
Accrued taxes	(8,405)	(13,573)	925
Other current assets and liabilities	18,300	23,379	5,084
Gains on sale	(3,102)	(6,171)	(4,112)
Changes in undistributed stock compensation	2,914	7,973	6,958
AFUDC	(3,008)	(1,995)	(2,274)
Changes in other assets and deferred charges	(14,166)	(21,732)	(21,719)
Changes in other liabilities and deferred credits	10,863	15,779	17,749
Net cash provided by operating activities	547,147	346,423	346,209
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions	(488,000)	(396,898)	(364,276)
Acquisition of businesses, net of cash acquired	(9,261)	(190,497)
Restricted cash	785	1,233
Changes in customer advances	18,300	20,363	7,773
Miscellaneous inflows	8,354	11,611	8,465
Miscellaneous outflows		(1,400)
Net cash used in investing activities	(469,822)	(555,588)	(348,038)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net	35,396	405	1,635
Dividends paid	(74,248)	(66,275)	(59,535)
Centuri distribution to redeemable noncontrolling interest	(99)
Issuance of long-term debt, net	135,816	269,228	311,290
Retirement of long-term debt	(187,973)	(139,155)	(137,013)
Change in credit facility and commercial paper		140,000	(101,000)
Change in short-term debt	13,000	5,000	1,999
Principal payments on capital lease obligations	(1,420)	(434)
Other	41	(1,257)
Net cash provided by (used in) financing activities	(79,487)	207,512	17,376
Effects of currency translation on cash and cash equivalents	(1,407)	142
Change in cash and cash equivalents	(3,569)	(1,511)	15,547
Cash and cash equivalents at beginning of period	39,566	41,077	25,530
Cash and cash equivalents at end of period	35,997	39,566	41,077
Supplemental information:
Interest paid, net of amounts capitalized	66,623	65,552	58,730
Income taxes paid	$ 43,225	$ 24,247	$ 6,850

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Consolidated Statements of Equity and Redeemable Noncontrolling Interest - USD ($) $ in Thousands	Total	Common Stock [Member]		Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Non-controlling Interest [Member]	Redeemable Noncontrolling Interest (Temporary Equity) [Member]
Balance at Dec. 31, 2012	$ 1,308,498	$ 47,778		$ 828,777	$ (50,745)	$ 484,369	$ (1,681)
Balance, Shares at Dec. 31, 2012		46,148,000
Common stock issuances, Value	11,952	$ 208		11,744
Common stock issuances, Shares		208,000
Net income (loss)	144,873					145,320	(447)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)	6,973				6,973
Amounts reclassified into net income	2,074				2,074
Dividends declared Common	(61,975)					(61,975)
Balance at Dec. 31, 2013	1,412,395	$ 47,986		840,521	(41,698)	567,714	(2,128)
Balance, Shares at Dec. 31, 2013		46,356,000
Common stock issuances, Value	11,027	$ 167		10,860
Common stock issuances, Shares		167,000
Net income (loss)	141,148
Redeemable noncontrolling interest attributable to acquisition								$ 18,952
Net income (loss)	140,997					141,126	(129)
Net income (loss) attributable to temporary equity								151
Redemption value adjustments (Note 16)	(961)					(961)
Redemption value adjustments attributable to temporary equity								961
Foreign currency exchange translation adj.	(637)				(637)
Foreign currency exchange translation adj attributable to temporary equity								(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 into net income	2,073				2,073
Dividends declared Common	(68,715)					(68,715)
Balance at Dec. 31, 2014	$ 1,486,266	$ 48,153		851,381	(50,175)	639,164	(2,257)
Balance, Shares at Dec. 31, 2014	46,523,184	46,523,000
Balance, Attributable to temporary equity	$ 20,042							20,042
Common stock issuances, Value	40,144	$ 854		39,290
Common stock issuances, Shares		854,000
Net income (loss)	139,430
Net income (loss)	138,491					138,317	174
Net income (loss) attributable to temporary equity								939
Redemption value adjustments (Note 16)	4,708			5,777		(1,069)
Redemption value adjustments attributable to temporary equity								(4,708)
Foreign currency exchange translation adj.	(1,888)				(1,888)
Foreign currency exchange translation adj attributable to temporary equity								(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 into net income	2,073				2,073
Centuri distribution to redeemable noncontrolling interest								(99)
Dividends declared Common	(77,191)					(77,191)
Balance at Dec. 31, 2015	$ 1,592,325	$ 49,007		$ 896,448	$ (50,268)	$ 699,221	$ (2,083)
Balance, Shares at Dec. 31, 2015	47,377,575	47,377,000	[1]
Balance, Attributable to temporary equity	$ 16,108							$ 16,108

[1] At December 31, 2015, 3.6 million common shares were registered and available for issuance under provisions of the Company's various stock issuance plans. In addition, approximately 17,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10).

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Consolidated Statements of Equity and Redeemable Noncontrolling Interest (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Dividends declared Common, per share	$ 1.62	$ 1.46	$ 1.32
Shares registered and available for issuance	3,600,000
Common shares registered for issuance upon exercise of options	17,000	36,000	52,000

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 1 – Summary of Significant Accounting Policies

Nature of Operations.    Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a 96.6% owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations occur in 20 major markets in the U.S. and within the provinces of British Columbia and Ontario in Canada, and are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). The Company acquired Link-Line, W.S. Nicholls, and Brigadier in October 2014. See Note 17 – Acquisition of Construction Services Businesses for more information.

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 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 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 (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 Company’s investment in Western totaled $14.7 million and $10.8 million at December 31, 2014 and 2015, respectively. Both periods include the impacts of foreign currency exchange translation adjustments. No dividends were paid during 2015. 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 $14.7 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 are deemed worthless. Centuri recorded earnings of $310,000 from this investment in 2015 which is included in Other Income (deductions) in the Consolidated Statements of Income.

Centuri, through its subsidiaries, also has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture. Any future changes to the values of these entities will be recorded by Centuri using the equity method.

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 (millions of dollars):

	2015			2014
Centuri property, equipment, and intangibles	$	423		$	405
Centuri accumulated provision for depreciation and amortization		(221	)		(187	)
Net cash surrender value of COLI policies		99			99
Other property		13			10
Total	$	314		$	327

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 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 $24 million in 2015 and $23 million in 2014 (carried at weighted average cost), and also includes natural gas stored underground and liquefied natural gas, in addition to prepaid assets.

Income Taxes.    The Company uses the asset and liability method of accounting 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. 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, 2015, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

Cash and Cash Equivalents.    For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents at December 31, 2015 and 2014 also includes two money market fund investments totaling approximately $250,000 which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

Significant non-cash investing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $3.1 million, $8.1 million, and $9.3 million during 2015, 2014, and 2013, 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.

Goodwill.    Goodwill is assessed for impairment annually in October, 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 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 any reporting unit is less than its carrying amount in 2014 or 2015. Thus, no impairment was recorded in 2014 or 2015. The acquisition date adjustment shown in the table below was recorded in the first quarter of 2015. No acquisition date adjustments occurred subsequently. The business of Brigadier was acquired via asset purchase. Therefore, goodwill assigned to Brigadier is expected to be deductible for tax purposes, resulting in an after-tax value of $4.9 million. All other goodwill associated with the acquisition is not deemed deductible for tax purposes.

	Natural Gas  Operations		Construction  Services			Consolidated
(In thousands of dollars)
December 31, 2014	$	10,095	$	133,065		$	143,160
Acquisition date adjustment		—		1,380			1,380
Foreign currency translation adjustment		—		(18,395	)		(18,395	)
December 31, 2015	$	10,095	$	116,050		$	126,145

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 the 2014 acquisition of construction services businesses and have finite lives.

Centuri has $36.8 million and $48.2 million of intangible assets (varies due to foreign currency translation) at December 31, 2015 and 2014, respectively, as detailed in the following table (thousands of dollars):

December 31, 2015	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
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
December 31, 2014	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	37,059	$	(524	)	$	36,535
Trade names and trademarks		10,208		(241	)		9,967
Customer contracts backlog		1,912		(724	)		1,188
Noncompete agreement		519		(34	)		485
Total	$	49,698	$	(1,523	)	$	48,175

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):

2016	$	2,809
2017		2,809
2018		2,605
2019		1,971
2020		1,906

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 recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals.

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. The Company 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, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, acquisition and acquisition-related costs, and office-related fixed costs of Centuri. During 2015, construction expenses were impacted by a loss reserve on an industrial construction project in Canada recognized earlier in the year, in the amount of $7.7 million. Delays in delivery of critical equipment to the job site resulted in production inefficiencies and an increase in total project costs. Work commenced on this project in March 2015 and was completed in the third quarter. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and a loss recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December 2015, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

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.

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. 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 Costsabove.

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.

	2015		2014		2013
(In thousands)
AFUDC:
Debt portion	$	1,666	$	1,228	$	1,260
Equity portion		3,008		1,995		2,274
AFUDC capitalized as part of utility plant	$	4,674	$	3,223	$	3,534

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):

	2015			2014			2013
Change in COLI policies	$	(500	)	$	5,300		$	12,400
Interest income		2,173			2,602			461
Equity AFUDC		3,008			1,995			2,274
Foreign currency transaction gain (loss)		(824	)		(178	)		—
Equity in earnings of unconsolidated investment - Western		310			107			—
Miscellaneous income and (expense)		(1,288	)		(2,719	)		(2,835	)
Total other income (deductions)	$	2,879		$	7,107		$	12,300

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences.

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 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”) are calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during the period. 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.

	2015		2014		2013
(In thousands)
Average basic shares		46,992		46,494		46,318
Effect of dilutive securities:
Stock options		8		17		26
Performance shares		171		215		231
Restricted stock units		212		218		183
Average diluted shares		47,383		46,944		46,758

Recently Issued Accounting Standards Updates.    In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. In accordance with the update, an entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. In April 2015, the FASB voted to propose, and in July 2015 it approved, a one-year deferral of the effective date (annual periods beginning after December 15, 2017), but to permit entities to adopt one year earlier if they choose (i.e., the original effective date). The FASB decided, based on its outreach to various stakeholders and the forthcoming exposure drafts, which amend the update, that a deferral is necessary to provide adequate time to effectively implement the update. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2018. The Company is evaluating what impact this update might have on its consolidated financial statements and disclosures.

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

In April 2015, the FASB issued the update “Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs.” To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. While balance sheet presentation is impacted by the update, the recognition and measurement of debt issuance costs are not. Retrospective application of the update is required. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2015. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. The Company adopted this update as of December 31, 2015, as permitted. See Note 7 – Long-Term Debt for additional information.

In May 2015, the FASB issued the update “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent).” This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the net asset value per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments that calculate net asset value per share (or its equivalent), but for which the practical expedient is not applied, will continue to be included in the fair value hierarchy. The update removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. A reporting entity should continue to disclose information on investments for which fair value is measured at net asset value as a practical expedient to help users understand the nature and risks of the investments and whether the investments, if sold, are probable of being sold at amounts different from net asset value. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods thereafter. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 10 – Pension and Other Postretirement Benefits for additional information.

In November 2015, the FASB issued the update “Income Taxes (Topic 740)” in order to simplify the presentation of deferred income taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The previous guidance required an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 12 – Income Taxes for additional information.

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 organization to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the organization has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. All entities can early adopt the provision to record fair value changes for financial liabilities under the fair value option resulting from instrument-specific credit risk in other comprehensive income. The Company is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

Subsequent Events.    Management of the Company 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.

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Utility Plant and Leases

12 Months Ended

Dec. 31, 2015

Leases [Abstract]

Utility Plant and Leases

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2015 and 2014 was as follows (thousands of dollars):

December 31,	2015			2014
Gas plant:
Storage	$	22,944		$	22,531
Transmission		312,996			312,300
Distribution		4,935,730			4,655,640
General		365,865			356,072
Software and software-related intangibles		203,323			196,035
Other		14,059			14,021
		5,854,917			5,556,599
Less: accumulated depreciation		(2,084,007	)		(1,973,098	)
Acquisition adjustments, net		370			550
Construction work in progress		119,805			74,332
Net utility plant	$	3,891,085		$	3,658,383

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 2015, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2014 and 2013 also approximated 3.6% on average.

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

	2015		2014		2013
Depreciation and amortization expense	$	201,233	$	194,360	$	185,283

Included in the figures above is amortization of intangibles of $12.7 million in 2015, $11.7 million in 2014, and $10.3 million in 2013.

Operating Leases and Rentals.    The Company leases certain office and construction equipment. 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):

	2015		2014		2013
Southwest Gas	$	4,186	$	5,330	$	8,308
Centuri		45,849		30,012		27,118
Consolidated rental payments/lease expense	$	50,035	$	35,342	$	35,426

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	6,836
2017		4,732
2018		2,993
2019		2,110
2020		1,473
Thereafter		3,583
Total minimum lease payments	$	21,727

Capital Leases.    Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2015 and 2014 are as follows (thousands of dollars):

December 31,	2015			2014
Capital leases of equipment	$	4,584		$	5,763
Less: accumulated amortization		(1,043	)		(287	)
Net capital leases	$	3,541		$	5,476

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	1,469
2017		869
2018		494
2019		21
2020		—
Thereafter		—
		2,853
Less: amount representing interest		(223	)
Total minimum lease payments	$	2,630

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Receivables and Related Allowances

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Receivables and Related Allowances

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, 2015 and 2014, and the percentage of customers in each of the three states.

	December 31, 2015		December 31, 2014
Gas utility customer accounts receivable balance (in thousands)	$	151,775	$	136,148

	December 31, 2015
Percent of customers by state
Arizona		53	%
Nevada		37	%
California		10	%

Although the Company 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, 2012	$	2,504
Additions charged to expense		3,583
Accounts written off, less recoveries		(4,362	)
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

At December 31, 2015, the construction services segment (Centuri) had $162 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs have been insignificant and are not reflected in the table above.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

Note 4 – Regulatory Assets and Liabilities

Natural gas operations are 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.

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

December 31,	2015			2014
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	384,647		$	390,293
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,486			5,425
Deferred purchased gas costs (3)		3,591			87,556
Accrued purchased gas costs (4)		—			2,600
Unamortized premium on reacquired debt (5)		21,511			20,478
Other (6)		73,022			72,132
		488,257			578,484
Regulatory liabilities:
Deferred purchased gas costs (3)		(45,601	)		—
Accumulated removal costs		(303,000	)		(304,000	)
Accrued purchased gas costs (4)		(10,400	)		—
Deferred gain on southern Nevada division operations facility (7)		—			(115	)
Unamortized gain on reacquired debt (8)		(10,325	)		(10,862	)
Other (9)		(36,631	)		(34,233	)
Net regulatory assets	$	82,300		$	229,274

(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 the Company’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13).

Instrument	Balance Sheet Location	2015		2014
Swaps	Deferred charges and other assets	$	1,219	$	363
Swaps	Prepaids and other current assets		4 ,267		5,062

(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.

(6) Other regulatory assets including deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as margin and interest-tracking accounts, amounts associated with accrued absence time, and deferred post-retirement benefits other than pensions. Recovery periods vary.

(7) The amortization period ended October 2015.

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

(9) Other regulatory liabilities include amounts associated with income tax and gross-up.

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI")

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI")

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)				2015									2014									2013
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214
Amortization of prior service cost		1,335			(507	)		828			355			(135	)		220			355			(135	)		220
Amortization of net actuarial (gain)/loss		34,381			(13,065	)		21,316			23,656			(8,989	)		14,667			34,177			(12,987	)		21,190
Prior service cost		—			—			—			(6,661	)		2,531			(4,130	)		—			—			—
Regulatory adjustment		(5,646	)		2,146			(3,500	)		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)
Pension plans other comprehensive income (loss)		(449	)		171			(278	)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973
Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities):
Amounts reclassified into net income		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
FSIRS other comprehensive income (loss)		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
Foreign currency translation adjustments:
Translation adjustments		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Foreign currency other comprehensive income (loss)		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Total other comprehensive income (loss)	$	941		$	(1,100	)	$	(159	)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047

(1) Tax amounts are calculated using a 38% rate. The Company 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, the Company 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.

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	$	25,000
SERP net actuarial loss		1,400
PBOP net actuarial loss		400
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, 2015, 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			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit		After- Tax			AOCI
Beginning Balance AOCI December 31, 2014	$	(57,211)		$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)
Net actuarial gain/(loss)		(30,519	)		11,597			(18,922	)		—			—			—			—			—		—			(18,922	)
Translation adjustments		—			—			—			—			—			—			(1,954	)		—		(1,954	)		(1,954	)
Other comprehensive income before reclassifications		(30,519	)		11,597			(18,922	)		—			—			—			(1,954	)		—		(1,954	)		(20,876	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,344			(1,271	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		1,335			(507	)		828			—			—			—			—			—		—			828
Amortization of net actuarial loss (2)		34,381			(13,065	)		21,316			—			—			—			—			—		—			21,316
Regulatory adjustment (3)		(5,646	)		2,146			(3,500	)		—			—			—			—			—		—			(3,500	)
Net current period other comprehensive income (loss)		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,954	)		—		(1,954	)		(159	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(66	)		—		(66	)		(66	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,888	)		—		(1,888	)		(93	)
Ending Balance AOCI December 31, 2015	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)

(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 Benefitsfor 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).

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, 2015 and 2014:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2015			2014
Net actuarial (loss) gain	$	(435,269	)	$	(439,131	)
Prior service cost		(7,038	)		(8,373	)
Less: amount recognized in regulatory assets		384,647			390,293
Recognized in AOCI	$	(57,660	)	$	(57,211	)

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.

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Common Stock

12 Months Ended

Dec. 31, 2015

Text Block [Abstract]

Common Stock

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 the Company’s common stock from time to time in at-the-market offerings under the prospectus included therein and in accordance with the Sales Agency Agreement, dated March 10, 2015, between the Company and BNY Mellon Capital Markets, LLC (the “Equity Shelf Program”). During 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds to the Company of $35,167,584, net of $355,228 in agent commissions. No sales occurred in the fourth quarter of 2015. As of December 31, 2015, the Company had up to $64,477,188 of common stock available for sale under the program. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

In addition, during 2015, the Company issued approximately 209,000 shares of common stock through the Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Note 7 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2015 and December 31, 2014 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within 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 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,	2015					2014
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	130,273	$	125,000		$	133,403
Notes, 6.1%, due 2041		125,000			141,581		125,000			157,290
Notes, 3.875%, due 2022		250,000			253,600		250,000			262,030
Notes, 4.875%, due 2043		250,000			251,483		250,000			280,903
8% Series, due 2026		75,000			97,035		75,000			102,296
Medium-term notes, 7.59% series, due 2017		25,000			26,253		25,000			27,573
Medium-term notes, 7.78% series, due 2022		25,000			29,855		25,000			31,144
Medium-term notes, 7.92% series, due 2027		25,000			31,890		25,000			33,695
Medium-term notes, 6.76% series, due 2027		7,500			8,684		7,500			9,156
Unamortized discount and debt issuance costs		(6,137	)				(6,604	)
		901,363					900,896
Revolving credit facility and commercial paper		150,000			150,000		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:
5.25% 2003 Series D, due 2038		—			—		20,000			20,277
5.00% 2004 Series B, due 2033		—			—		31,200			31,223
4.85% 2005 Series A, due 2035		100,000			100,452		100,000			100,071
4.75% 2006 Series A, due 2036		24,855			25,130		24,855			25,399
Unamortized discount and debt issuance costs		(3,946	)				(5,964	)
		320,909					370,091
Centuri term loan facility		112,571			112,665		142,071			143,021
Unamortized debt issuance costs		(692	)				(816	)
		111,879					141,255
Centuri secured revolving credit facility		60,627			60,724		57,196			57,320
Centuri other debt obligations		25,901			26,059		31,128			31,127
		1,570,679					1,650,566
Less: current maturities		(19,475	)				(19,192	)
Long-term debt, less current maturities	$	1,551,204				$	1,631,374

In March 2015, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2019, but was extended to March 2020. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At December 31, 2015, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility, including $50 million in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 1.45% at December 31, 2015. Borrowings under the credit facility ranged from none during the second quarter of 2015 to a high of $180 million during the fourth quarter of 2015. With regard to the short-term portion of the credit facility, there was $18 million outstanding at December 31, 2015 and $5 million outstanding at December 31, 2014. (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, 2015, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 1.01% at December 31, 2015.

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

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

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. In January 2016, administrative amendments were made to the revolving credit and term loan facility with no impact to borrowing capacity, due dates, or interest provisions. 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, 2015 totaled $437 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 the consolidated leverage ratio. The commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the revolving credit facility ranged from a low of $60.6 million during December 2015 to a high of $105.2 million during May 2015. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.46% at December 31, 2015.

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

	December 31, 2015			December 31, 2014
2003 Series A		0.87	%		0.85	%
2008 Series A		0.87	%		0.90	%
2009 Series A		0.75	%		0.89	%
Tax-exempt Series A		0.81	%		0.84	%

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

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

2016	$	19,475
2017		42,245
2018		14,906
2019		142,452
2020		275,238

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company 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, 2015, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $2.2 billion in additional debt and meet the leverage ratio requirement. The Company has at least $1 billion of cushion in equity relating to the minimum net worth requirement.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2015, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $75 million in additional debt and meet the leverage ratio requirement. Centuri has at least $15 million of cushion relating to the minimum fixed charge ratio coverage requirement.

Early Adoption of Accounting Standards Update (“ASU”) No. 2015-03. As of December 31, 2015, the Company adopted FASB ASU No. 2015-03 “Interest-Imputation of Interest (subtopic 835-30)”. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The adoption of this update is considered a change in an accounting principle. Upon adoption, the 2014 amounts in the Consolidated Balance Sheets were restated for Long-term debt (from $1,637,592,000 to $1,631,374,000), Deferred charges and other assets (from $478,625,000 to $472,579,000), and Prepaids and other current assets (from $99,975,000 to $99,803,000). The 2014 amounts in the debt listing table for unamortized discount and debt issuance costs for debentures and IDRBs previously included only amounts associated with unamortized discount, ($5,223,000) for debentures and ($1,943,000) for IDRBs. The difference between the associated figures in the debt listing table and these figures are amounts associated with unamortized debt issue costs reclassified in accordance with the update.

In a related update, the SEC provided guidance that for line-of-credit (“LOC”) arrangements, companies could elect to present debt issuance costs within assets, regardless of whether there is an outstanding balance on such borrowings. Making such an election may make presentations less confusing as net negative balances would otherwise result in cases when there are no outstanding LOC borrowings but associated issuance costs are still being amortized. Therefore, for LOC arrangements, such as Southwest’s revolving credit facility and Centuri’s secured revolving credit portion of its facility, the Company has elected, as permitted, to continue to recognize unamortized debt issuance costs within its asset categories and no such amounts have been reclassified. The unamortized debt issuance costs associated with the term loan portion of Centuri’s $300 million facility, ($816,000), have been reclassified as a deduction from the related 2014 debt balance. The debt listing table has been updated to reflect these changes based on the elections made.

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Short-Term Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Short-Term Debt

Note 8 – Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2020, of which $150 million has been designated by management for working capital purposes. The Company had $18 million in short-term borrowings outstanding at December 31, 2015 and $5 million in short-term borrowings outstanding at December 31, 2014. The effective interest rate on the short-term portion of the credit facility was 1.37% at December 31, 2015.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 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 or results of operations.

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers would be responsible for amounts up to the policy limits. For the policy year August 2015 to July 2016, 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, the Company may determine that certain costs are likely to be incurred in the future related to specific legal matters. In these circumstances and in accordance with accounting policies, the Company will make an accrual, as necessary.

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits

Note 10 – Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches one-half of amounts deferred by employees, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. Centuri has a separate plan, the cost and liability of which are not significant. The cost of the Southwest plan is listed below (in thousands):

	2015		2014		2013
Employee Investment Plan cost	$	5,072	$	4,816	$	4,850

Southwest has a deferred compensation plan for 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. Southwest matches one-half of amounts deferred by officers, 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.

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

The Company recognizes the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in its 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.

The Company has established a regulatory asset 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.

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 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, 2015, the percentage ranges of the target portfolio are:

Type of Investment	Percentage Range
Equity securities		59 to 71
Debt securities		31 to 37
Other		up to 5

The Company’s 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, the Company 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.

Due to a higher interest rate environment for high-quality fixed income investments, the Company increased the discount rate at December 31, 2015 from 2014. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also raised (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, 2015			December 31, 2014
Discount rate		4.50	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		2.75	%
Asset return assumption		7.25	%		7.75	%

Pension expense for 2016 is estimated to decrease by $6.7 million compared to 2015 notably due to the higher discount rate and lower mortality projection. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

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.

	2015									2014
	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)	$	1,060,240		$	41,176		$	72,202		$	886,714		$	36,143		$	58,020
Service cost		25,123			320			1,641			21,360			292			1,101
Interest cost		44,229			1,695			2,999			43,440			1,745			2,829
Plan amendments		—			—			—			—			—			6,661
Actuarial loss (gain)		(44,553	)		2,322			(3,251	)		144,606			5,459			4,567
Benefits paid		(40,222	)		(2,793	)		(959	)		(35,880	)		(2,463	)		(976	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,044,817			42,720			72,632			1,060,240			41,176			72,202
Change in plan assets
Market value of plan assets at beginning of year		754,796			—			44,892			719,944			—			42,314
Actual return on plan assets		(13,694	)		—			(1,034	)		34,732			—			2,859
Employer contributions		36,000			2,793			—			36,000			2,463			—
Benefits paid		(40,222	)		(2,793	)		(274	)		(35,880	)		(2,463	)		(281	)
Market value of plan assets at end of year		736,880			—			43,584			754,796			—			44,892
Funded status at year end	$	(307,937	)	$	(42,720	)	$	(29,048	)	$	(305,444	)	$	(41,176	)	$	(27,310	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.50	%		4.50	%		4.50	%		4.25	%		4.25	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		N/A			2.75	%		2.75	%		N/A

Estimated funding for the plans above during calendar year 2016 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, 2015		December 31, 2014
Retirement plan	$	922,992	$	886,215
SERP		39,270		39,125

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

	2016	2017	2018	2019		2020		2021-2025
Pension	$44.0	$45.5	$47.2		$48.9		$50.5		$283.5
PBOP	3.9	4.1	4.3		4.5		4.5		21.3
SERP	2.8	2.8	2.8		2.9		2.9		14.1

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 7.5% declining to 4.5%. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but 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
	2015			2014			2013			2015			2014			2013			2015			2014			2013
(Thousands of dollars)
Service cost	$	25,123		$	21,360		$	23,056		$	320		$	292		$	373		$	1,641		$	1,101		$	1,220
Interest cost		44,229			43,440			37,607			1,695			1,745			1,535			2,999			2,829			2,482
Expected return on plan assets		(57,808	)		(53,342	)		(49,840	)		—			—			—			(3,464	)		(3,264	)		(2,824	)
Amortization of prior service cost		—			—			—			—			—			—			1,335			355			355
Amortization of net actuarial loss		32,743			22,873			32,261			1,293			783			971			345			—			945
Net periodic benefit cost	$	44,287		$	34,331		$	43,084		$	3,308		$	2,820		$	2,879		$	2,856		$	1,021		$	2,178
Weighted-average assumptions (net benefit cost)
Discount rate		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%
Expected return on plan assets		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%		2.75	%		2.75	%		3.25	%		2.75	%		N/A			N/A			N/A

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

	2015												2014												2013
	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)	$	30,519		$	26,949		$	2,322		$	1,248		$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)
Amortization of prior service cost (b)		(1,335	)		—			—			(1,335	)		(355	)		—			—			(355	)		(355	)		—			—			(355	)
Amortization of net actuarial loss (b)		(34,381	)		(32,743	)		(1,293	)		(345	)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)
Prior service cost		—			—			—			—			6,661			—			—			6,661			—			—			—			—
Regulatory adjustment		5,646			5,214			—			432			(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868
Recognized in other comprehensive
(income) loss		449			(580	)		1,029			—			15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—
Net periodic benefit costs recognized in net income		50,451			44,287			3,308			2,856			38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,900		$	43,707		$	4,337		$	2,856		$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178

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.

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, 2015 and December 31, 2014. The SERP has no assets. The FASB issued guidance in 2015, which the Company has adopted early as permitted, removing the requirement to categorize assets in the fair value hierarchy that are measured using the net asset value (“NAV”) practical expedient. See note (3) to the table below. Based on this guidance, no Level 3 assets existed (nor are reflected in the table below) at December 31, 2015 and December 31, 2014.

	December 31, 2015								December 31, 2014
	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		$	6,661	$	198	$	6,859
Capital equipment		533			16		549			2,222		66		2,288
Chemicals/materials		3,304			98		3,402			5,233		155		5,388
Consumer goods		41,035			1,221		42,256			41,731		1,238		42,969
Energy and mining		11,066			329		11,395			18,502		549		19,051
Finance/insurance		29,957			892		30,849			20,685		613		21,298
Healthcare		37,930			1,129		39,059			37,846		1,122		38,968
Information technology		29,229			870		30,099			25,881		767		26,648
Services		12,341			367		12,708			28,846		855		29,701
Telecommunications/internet/media		25,883			770		26,653			18,498		549		19,047
Other		9,043			269		9,312			10,958		325		11,283
Real estate investment trusts		5,010			149		5,159			5,713		169		5,882
Mutual funds		87,483			23,985		111,468			86,159		24,567		110,726
Government fixed income securities		33,482			996		34,478			44,694		1,325		46,019
Preferred securities		—			—		—			568		17		585
Futures contracts		(7	)		—		(7	)		—		—		—
Total Level 1 Assets (1)	$	333,310		$	31,300	$	364,610		$	354,197	$	32,515	$	386,712
Level 2 – Significant other observable inputs
Government fixed income and mortgage backed securities	$	49,571		$	1,475	$	51,046		$	48,312	$	1,433	$	49,745
Corporate fixed income securities
Asset-backed and mortgage-backed		23,542			701		24,243			27,071		803		27,874
Banking		20,857			621		21,478			23,289		691		23,980
Insurance		4,896			146		5,042			6,182		183		6,365
Utilities		3,826			114		3,940			4,232		126		4,358
Other		30,995			922		31,917			23,120		686		23,806
Pooled funds and mutual funds		14,808			796		15,604			11,968		984		12,952
Real estate investment trusts		1,949			58		2,007			—		—		—
State and local obligations		950			28		978			1,499		44		1,543
Preferred securities		554			17		571			—		—		—
Convertible securities		196			6		202			—		—		—
Total Level 2 assets (2)	$	152,144		$	4,884	$	157,028		$	145,673	$	4,950	$	150,623
Total Plan assets at fair value	$	485,454		$	36,184	$	521,638		$	499,870	$	37,465	$	537,335
Commingled equity funds (3)		250,511			7,455		257,966			259,235		7,687		266,922
Insurance company general account contracts (4)		3,719			—		3,719			4,003		—		4,003
Total Plan assets (5)	$	739,684		$	43,639	$	783,323		$	763,108	$	45,152	$	808,260

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

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 balanced fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income.

(2) The fair value of investments in debt securities with remaining maturities of one year or more is 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.

The pooled funds and mutual funds are two collective short-term funds that invest in Treasury bills and money market funds. These funds are used as a temporary cash repository for the pension plan’s various investment managers.

(3) The commingled equity funds include 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 include:

• 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 may be redeemed vary among the funds; the notice required ranges from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds requires the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminishes the greater the transaction. Other such funds may impose fees to recover direct costs incurred by the fund at redemption, but are indeterminable prior to redemption.

Early adoption of ASU No. 2015-07: As permitted the Company adopted (earlier than the required adoption date) FASB ASU No. 2015-07 “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent)” as of December 31, 2015. This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the NAV per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the NAV per share practical expedient. The FASB determined that including those assets in the fair value hierarchy is potentially confusing and misleading to financial statement users. The fair value of the commingled equity funds was determined using NAV as an expedient since no significant observable inputs were available (these funds are not publicly traded on an exchange). Because of the requirements of this update, the commingled equity funds are no longer included in the above fair value hierarchy table as a Level 3 fair value measurement but instead are disclosed as a reconciling item to the table. The associated Fair Value Measurement Using Significant Unobservable Inputs (Level 3) table is no longer presented due to this change, as the commingled equity funds were the only assets whose values were previously indicated to be Level 3 fair value measurements.

(4) 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.

(5) The assets in the above table exceed 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) and $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) for 2015 and 2014, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Note 11 – Stock-Based Compensation

At December 31, 2015, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan which includes a cash award, and a restricted stock/unit plan. 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):

	2015		2014		2013
Stock-based compensation plan expense, net of related tax benefits	$	7,278	$	8,130	$	8,012
Stock-based compensation plan related tax benefits		4,461		4,983		4,910

Under the option plan, the Company previously granted options to purchase shares of common stock, 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 Company common stock on the date of grant and a maximum term of ten years. Therefore, remaining options, if not exercised prior to the anniversary date of the 2006 grant (in 2016), will then expire.

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

	2015					2014					2013
	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		36		$	28.97		52		$	27.57		125		$	28.13
Exercised during the year		(19	)		26.69		(16	)		24.31		(72	)		28.44
Forfeited or expired during the year		—			—		—			—		(1	)		33.07
Outstanding and exercisable at year end		17		$	31.64		36		$	28.97		52		$	27.57

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):

	2015		2014		2013
Outstanding and exercisable	$	394	$	1,194	$	1,473
Exercised		590		451		1,402

	December 31, 2015		December 31, 2014		December 31, 2013
Market value of Southwest Gas stock	$	55.16	$	61.81	$	55.91

The weighted-average remaining contractual life for outstanding options was less than one year for 2015. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2015 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$29.08 to $33.07		17		0.5 Years	$	31.64

The Company received $523,000 in cash from the exercise of options during 2015 and a corresponding tax benefit of $218,000 which was recorded in additional paid-in capital.

Under the performance share stock plan, the Company may issue performance shares to encourage key employees to remain in its employment 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.

The Company awards restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. 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 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, 2015 (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		271		$	43.71		257		$	41.22
Granted		80			63.09		73			63.09
Dividends		6					7
Forfeited or expired		—			—		—			—
Vested and issued*		(160	)		43.12		(109	)		46.65
Nonvested/unissued at December 31, 2015		197		$	50.63		228		$	44.36

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

The average grant date fair value of performance shares and restricted stock/units granted in 2014 and 2013 was $53.73 and $44.83, respectively.

As of December 31, 2015, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

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,	2015			2014			2013
U.S.	$	221,660		$	221,471		$	222,815
Foreign		(2,328	)		(1,950	)		—
Total income before income taxes	$	219,332		$	219,521		$	222,815

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

Year Ended December 31,	2015			2014			2013
Current:
Federal	$	21,321		$	1,739		$	3,549
State		9,899			5,073			5,107
Foreign		650			2,193			—
		31,870			9,005			8,656
Deferred:
Federal		51,132			71,439			67,414
State		(2,574	)		614			1,872
Foreign		(526	)		(2,685	)		—
		48,032			69,368			69,286
Total income tax expense	$	79,902		$	78,373		$	77,942

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

Year Ended December 31,	2015			2014			2013
Deferred federal and state:
Property-related items	$	65,931		$	52,814		$	62,737
Purchased gas cost adjustments		(32,993	)		15,049			16,189
Employee benefits		623			109			(2,769	)
All other deferred		15,332			2,257			(6,010	)
Total deferred federal and state		48,893			70,229			70,147
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	48,032		$	69,368		$	69,286

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2013, 2014, and 2015 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2015			2014			2013
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.8			1.9			2.4
Property-related items		0.1			0.1			0.1
Tax credits		(0.4	)		(0.5	)		(0.4	)
Company owned life insurance		0.1			(1.0	)		(2.1	)
All other differences		(0.2	)		0.2			—
Consolidated effective income tax rate		36.4	%		35.7	%		35.0	%

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

December 31,	2015			2014
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	1,614		$	2,146
Employee benefits		36,923			31,557
Alternative minimum tax credit		4,809			20,172
Net operating losses and credits		868			9,719
Interest rate swap		7,351			8,622
Other		24,636			25,872
Valuation allowance		(499	)		(253	)
		75,702			97,835
Deferred tax liabilities:
Property-related items, including accelerated depreciation		794,850			736,810
Regulatory balancing accounts		743			33,736
Unamortized ITC		2,549			3,410
Debt-related costs		5,497			5,066
Intangibles		9,547			12,792
Other		31,533			27,600
		844,719			819,414
Net deferred tax liabilities		769,017			721,579
Current		—			(2,109	)
Noncurrent		769,017			723,688
Net deferred tax liabilities	$	769,017		$	721,579

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 2011.

At December 31, 2015, the Company has U.S. federal net capital loss carryforwards of $505,000, which begin to expire in 2016. At December 31, 2015, the Company has an income tax net operating loss carryforward related to Canadian operations of $3 million which begins to expire in 2032.

As of December 31, 2015, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

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

	2015			2014
Unrecognized tax benefits at beginning of year	$	305		$	—
Gross increases-tax positions in prior period		—			305
Gross decreases-tax positions in prior period		(9	)		—
Gross increases-current period tax positions		—			—
Gross decreases-current period tax positions		—			—
Settlements		—			—
Lapse in statute of limitations		—			—
Unrecognized tax benefits at end of year	$	296		$	305

In assessing whether uncertain tax positions should be recognized in its financial statements, Southwest 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, Southwest 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, Southwest 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. Southwest recognizes unrecognized tax benefits 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. Southwest’s measurement of its 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 $0 at December 31, 2015. 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 2015, 2014, and 2013.

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. The Company expects the IRS to issue natural gas industry guidance which 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, the Company expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.

Early Adoption of ASU No. 2015-17. As permitted, the Company adopted FASB ASU No. 2015-17 Income Taxes (Topic 740) as of December 31, 2015. This ASU simplifies the presentation of deferred income taxes in that deferred tax liabilities and assets will now be classified as noncurrent in the Consolidated Balance Sheets instead of current and noncurrent. The adoption of this ASU is considered a change in accounting principle. The Company chose to apply the content of the update prospectively as permitted. Prior periods were not retrospectively updated.

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Derivatives and Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Fair Value Measurements

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

	December 31, 2015		December 31, 2014
Contract notional amounts		7,407		5,105

In late 2013, the Company suspended using swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

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

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2015, 2014, and 2013 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	2015			2014			2013
Swaps	Net cost of gas sold	$	(7,598	)	$	(2,363	)	$	976
Swaps	Net cost of gas sold		7,598	*		2,363	*		(976	)*
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. The second FSIRS terminated in March 2012. Losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) into interest expense.

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

Fair values of derivatives not designated as hedging instruments:

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	)
December 31, 2014 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(5,062	)	$	(5,062	)
Swaps	Other deferred credits		—		(363	)		(363	)
Total		$	—	$	(5,425	)	$	(5,425	)

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

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

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

	Year ended December 31, 2015		Year ended December 31, 2014		Year ended December 31, 2013
(Thousands of dollars)
Paid to counterparties	$	7,537	$	829	$	3,148
Received from counterparties	$	—	$	4,713	$	915

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

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
December 31, 2014 Instrument	Balance Sheet Location		Net Total
Swaps		Prepaids and other current assets	$	5,062
Swaps		Deferred charges and other assets		363

Fair Value Measurements.     The estimated fair values of Southwest’s Swaps were determined at December 31, 2015 and 2014 using New York Mercantile Exchange (“NYMEX”) futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measurement.

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (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, 2015			December 31, 2014
(Thousands of dollars)
Liabilities at fair value:
Other current liabilities—Swaps	$	(4,267	)	$	(5,062	)
Other deferred credits—Swaps		(1,219	)		(363	)
Net Assets (Liabilities)	$	(5,486	)	$	(5,425	)

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.

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Segment Information

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Segment Information

Note 14 – Segment Information

Company 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 (market) 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, 2015		December 31, 2014
Accounts receivable for Centuri services	$	10,006	$	9,169

The following table presents the amount of revenues and long-lived assets for both segments by geographic area (thousands of dollars):

	December 31, 2015		December 31, 2014
Revenues (a)
United States	$	2,289,133	$	2,069,513
Canada		174,492		52,194
Total	$	2,463,625	$	2,121,707

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

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, 2015 is as follows (thousands of dollars):

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
2013	Gas Operations		Construction Services		Adjustments (b)			Total
Revenues from unaffiliated customers	$	1,300,154	$	562,475				$	1,862,629
Intersegment sales		—		88,153					88,153
Total	$	1,300,154	$	650,628				$	1,950,782
Interest revenue	$	456	$	5				$	461
Interest expense	$	62,555	$	1,145				$	63,700
Depreciation and amortization	$	193,848	$	42,969				$	236,817
Income tax expense	$	65,377	$	12,565				$	77,942
Segment net income	$	124,169	$	21,151				$	145,320
Segment assets	$	4,272,029	$	293,811	$	(666	)	$	4,565,174
Capital expenditures	$	314,578	$	49,698				$	364,276

(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.

(b) Construction services segment assets included income taxes payable of $666,000 in 2013, which was netted against gas operations segment income taxes receivable, net during consolidation.

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data

Note 15 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30		September 30			December 31
(Thousand of dollars, except per share amounts)
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
2013
Operating revenues	$	613,505	$	411,574	$	387,346		$	538,357
Operating income		138,394		28,908		6,141			100,772
Net income (loss)		80,674		10,067		(3,057	)		57,189
Net income (loss) attributable to Southwest Gas Corporation		80,773		10,108		(2,864	)		57,303
Basic earnings (loss) per common share*		1.75		0.22		(0.06	)		1.24
Diluted earnings (loss) per common share*		1.73		0.22		(0.06	)		1.22

* 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 the operations of the Company. 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. Additionally, see Note 16 – Construction Services Noncontrolling Interests regarding allocation of earnings and Note 17 – Acquisition of Construction Services Businesses regarding the acquisition in the last quarter of 2014.

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Construction Services Noncontrolling Interests

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest [Abstract]

Construction Services Noncontrolling Interests

Note 16 – Construction Services Noncontrolling Interests

Associated with the agreement reached in conjunction with the acquisition of the Canadian constriction businesses, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses. The agreement, associated with that approximate 10% equity interest, provided 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 continue to be able to exit their investment retained by requiring the purchase of a portion of their interest commencing July 2017 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election beginning in July 2022. Due to the continued ability of the noncontrolling parties to redeem their interest for cash, their interest continues to be presented on the Company’s Consolidated Balance Sheet at December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance. However, that interest, previously associated with the Canadian businesses, is now formally an interest in Centuri.

Significant changes in the value of the redeemable noncontrolling interest are recognized as they occur, and the carrying value is adjusted as necessary at each reporting date. Guidance by the SEC indicates that downward adjustments in the value of redeemable noncontrolling interests are only permitted to the extent that upward adjustments in value were previously recognized. A floor for the noncontrolling interest was originally set at the acquisition date (in October 2014). However, U.S. GAAP generally views changes in ownership interest, where the parent retains its controlling interest, as an equity transaction, whereby the carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. In connection with the exchange rights being exercised during the third quarter, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized, due in part to the exchange option no longer being subject to probability estimates. In light of the U.S. GAAP requirement to adjust the carrying amount, a new floor was set for the redeemable noncontrolling interest at the exchange date (July 31, 2015), with a corresponding adjustment made to additional paid in capital of the Company. Future adjustments to the redemption value are not permitted below the new floor. 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, 2014	$	20,042
Net Income (loss) attributable to redeemable noncontrolling interest		939
Foreign currency exchange translation adjustment		(66	)
Centuri distribution to redeemable noncontrolling interest		(99	)
Adjustment to redemption value		(4,708	)
Balance, December 31, 2015	$	16,108

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. Prior to the exchange rights being exercised in the third quarter of 2015, a Monte Carlo simulation methodology was used to assign a value to the redeemable noncontrolling interest. 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 negative adjustment to the redemption value in the table above reflects the sum of 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.

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Acquisition of Construction Services Businesses

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisition of Construction Services Businesses

Note 17 – Acquisition of Construction Services Businesses

In October 2014, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses. The acquisition extended the construction services operations into Canada and provides additional opportunities for market expansion. Funding for the acquisition was primarily provided by a new $300 million secured revolving credit and term loan facility described in Note 7 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”), (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania (“Brigadier”).

Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed in 2014. The Company’s allocation of the purchase price in 2014 was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. The final purchase accounting has been completed. The October 1, 2014 fair values of assets acquired and liabilities assumed, revised during the first quarter of 2015, are as follows (in millions of dollars):

	Acquisition Date		Measurement Period Adjustments			Revised Acquisition Date
Cash, cash equivalents, and restricted cash	$	3	$	—		$	3
Contracts receivable and other receivables		62		—			62
Property, plant and equipment		17		—			17
Other assets		17		(2	)		15
Intangible assets		52		—			52
Goodwill		130		1			131
Total assets acquired		281		(1	)		280
Current liabilities		39		1			40
Deferred income tax—long-term		17		—			17
Other long-term liabilities		4		—			4
Net assets acquired	$	221	$	(2	)	$	219

The Company incurred and expensed acquisition costs of $5 million in 2014; no acquisition costs were incurred during 2015.

The allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill consisted of the value associated with the assembled workforce and consolidation of operations. When acquisition-date values were updated in the first quarter of 2015, as reflected in the table above, there was no significant overall impact to the Company’s Consolidated Balance Sheets.

The unaudited pro forma consolidated financial information for fiscal 2014 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning of fiscal 2014) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31, 2014
Total operating revenues	$	2,295,318
Net income attributable to Southwest Gas Corporation	$	149,588
Basic earnings per share	$	3.22
Diluted earnings per share	$	3.19

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Nature of Operations

Nature of Operations.    Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment), a 96.6% owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations occur in 20 major markets in the U.S. and within the provinces of British Columbia and Ontario in Canada, and are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). The Company acquired Link-Line, W.S. Nicholls, and Brigadier in October 2014. See Note 17 – Acquisition of Construction Services Businesses for more information.

Basis of Presentation

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 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 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

Consolidation.    The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries (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 Company’s investment in Western totaled $14.7 million and $10.8 million at December 31, 2014 and 2015, respectively. Both periods include the impacts of foreign currency exchange translation adjustments. No dividends were paid during 2015. 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 $14.7 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 are deemed worthless. Centuri recorded earnings of $310,000 from this investment in 2015 which is included in Other Income (deductions) in the Consolidated Statements of Income.

Centuri, through its subsidiaries, also has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture. Any future changes to the values of these entities will be recorded by Centuri using the equity method.

Net Utility Plant

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

	2015			2014
Centuri property, equipment, and intangibles	$	423		$	405
Centuri accumulated provision for depreciation and amortization		(221	)		(187	)
Net cash surrender value of COLI policies		99			99
Other property		13			10
Total	$	314		$	327

Deferred Purchased Gas Costs

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 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.    Prepaids and other current assets includes gas pipe materials and operating supplies of $24 million in 2015 and $23 million in 2014 (carried at weighted average cost), and also includes natural gas stored underground and liquefied natural gas, in addition to prepaid assets.

Income Taxes

Income Taxes.    The Company uses the asset and liability method of accounting 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. 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, 2015, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

Cash and Cash Equivalents

Cash and Cash Equivalents.    For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents at December 31, 2015 and 2014 also includes two money market fund investments totaling approximately $250,000 which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

Significant non-cash investing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $3.1 million, $8.1 million, and $9.3 million during 2015, 2014, and 2013, 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.

Goodwill

Goodwill.    Goodwill is assessed for impairment annually in October, 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 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 any reporting unit is less than its carrying amount in 2014 or 2015. Thus, no impairment was recorded in 2014 or 2015. The acquisition date adjustment shown in the table below was recorded in the first quarter of 2015. No acquisition date adjustments occurred subsequently. The business of Brigadier was acquired via asset purchase. Therefore, goodwill assigned to Brigadier is expected to be deductible for tax purposes, resulting in an after-tax value of $4.9 million. All other goodwill associated with the acquisition is not deemed deductible for tax purposes.

	Natural Gas Operations		Construction Services			Consolidated
(In thousands of dollars)
December 31, 2014	$	10,095	$	133,065		$	143,160
Acquisition date adjustment		—		1,380			1,380
Foreign currency translation adjustment		—		(18,395	)		(18,395	)
December 31, 2015	$	10,095	$	116,050		$	126,145

Intangible Assets

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 the 2014 acquisition of construction services businesses and have finite lives.

Centuri has $36.8 million and $48.2 million of intangible assets (varies due to foreign currency translation) at December 31, 2015 and 2014, respectively, as detailed in the following table (thousands of dollars):

December 31, 2015	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
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
December 31, 2014	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	37,059	$	(524	)	$	36,535
Trade names and trademarks		10,208		(241	)		9,967
Customer contracts backlog		1,912		(724	)		1,188
Noncompete agreement		519		(34	)		485
Total	$	49,698	$	(1,523	)	$	48,175

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):

2016	$	2,809
2017		2,809
2018		2,605
2019		1,971
2020		1,906

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

Accumulated Removal Costs

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

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 recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals.

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. The Company uses the net classification method to report taxes collected from customers to be remitted to governmental authorities.

Construction Revenues

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

Construction Expenses.    The construction expenses classification in the income statement includes payroll expenses, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, acquisition and acquisition-related costs, and office-related fixed costs of Centuri. During 2015, construction expenses were impacted by a loss reserve on an industrial construction project in Canada recognized earlier in the year, in the amount of $7.7 million. Delays in delivery of critical equipment to the job site resulted in production inefficiencies and an increase in total project costs. Work commenced on this project in March 2015 and was completed in the third quarter. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and a loss recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December 2015, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

Net Cost of Gas Sold

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.

Operations and Maintenance Expense

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

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. 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")

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.

	2015		2014		2013
(In thousands)
AFUDC:
Debt portion	$	1,666	$	1,228	$	1,260
Equity portion		3,008		1,995		2,274
AFUDC capitalized as part of utility plant	$	4,674	$	3,223	$	3,534

Other Income (Deductions)

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):

	2015			2014			2013
Change in COLI policies	$	(500	)	$	5,300		$	12,400
Interest income		2,173			2,602			461
Equity AFUDC		3,008			1,995			2,274
Foreign currency transaction gain (loss)		(824	)		(178	)		—
Equity in earnings of unconsolidated investment - Western		310			107			—
Miscellaneous income and (expense)		(1,288	)		(2,719	)		(2,835	)
Total other income (deductions)	$	2,879		$	7,107		$	12,300

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences.

Foreign Currency Translation

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

Earnings Per Share

Earnings Per Share.    Basic earnings per share (“EPS”) are calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during the period. 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.

	2015		2014		2013
(In thousands)
Average basic shares		46,992		46,494		46,318
Effect of dilutive securities:
Stock options		8		17		26
Performance shares		171		215		231
Restricted stock units		212		218		183
Average diluted shares		47,383		46,944		46,758

Recently Issued Accounting Standards Updates

Recently Issued Accounting Standards Updates.    In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. In accordance with the update, an entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. In April 2015, the FASB voted to propose, and in July 2015 it approved, a one-year deferral of the effective date (annual periods beginning after December 15, 2017), but to permit entities to adopt one year earlier if they choose (i.e., the original effective date). The FASB decided, based on its outreach to various stakeholders and the forthcoming exposure drafts, which amend the update, that a deferral is necessary to provide adequate time to effectively implement the update. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2018. The Company is evaluating what impact this update might have on its consolidated financial statements and disclosures.

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

In April 2015, the FASB issued the update “Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs.” To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. While balance sheet presentation is impacted by the update, the recognition and measurement of debt issuance costs are not. Retrospective application of the update is required. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2015. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. The Company adopted this update as of December 31, 2015, as permitted. See Note 7 – Long-Term Debt for additional information.

In May 2015, the FASB issued the update “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent).” This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the net asset value per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments that calculate net asset value per share (or its equivalent), but for which the practical expedient is not applied, will continue to be included in the fair value hierarchy. The update removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. A reporting entity should continue to disclose information on investments for which fair value is measured at net asset value as a practical expedient to help users understand the nature and risks of the investments and whether the investments, if sold, are probable of being sold at amounts different from net asset value. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods thereafter. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 10 – Pension and Other Postretirement Benefits for additional information.

In November 2015, the FASB issued the update “Income Taxes (Topic 740)” in order to simplify the presentation of deferred income taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The previous guidance required an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 12 – Income Taxes for additional information.

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 organization to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the organization has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. All entities can early adopt the provision to record fair value changes for financial liabilities under the fair value option resulting from instrument-specific credit risk in other comprehensive income. The Company is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

Subsequent Events

Subsequent Events.    Management of the Company 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.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Schedule of Other Property and Investments

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

	2015			2014
Centuri property, equipment, and intangibles	$	423		$	405
Centuri accumulated provision for depreciation and amortization		(221	)		(187	)
Net cash surrender value of COLI policies		99			99
Other property		13			10
Total	$	314		$	327

Schedule of Goodwill

	Natural Gas Operations		Construction Services			Consolidated
(In thousands of dollars)
December 31, 2014	$	10,095	$	133,065		$	143,160
Acquisition date adjustment		—		1,380			1,380
Foreign currency translation adjustment		—		(18,395	)		(18,395	)
December 31, 2015	$	10,095	$	116,050		$	126,145

Summary of Intangible Assets

Centuri has $36.8 million and $48.2 million of intangible assets (varies due to foreign currency translation) at December 31, 2015 and 2014, respectively, as detailed in the following table (thousands of dollars):

December 31, 2015	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
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
December 31, 2014	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	37,059	$	(524	)	$	36,535
Trade names and trademarks		10,208		(241	)		9,967
Customer contracts backlog		1,912		(724	)		1,188
Noncompete agreement		519		(34	)		485
Total	$	49,698	$	(1,523	)	$	48,175

Schedule of Estimated Future Amortization of Intangible Assets

The estimated future amortization of the intangible assets for the next five years is as follows (in thousands):

2016	$	2,809
2017		2,809
2018		2,605
2019		1,971
2020		1,906

Schedule of Capitalized and Debt Portion of AFUDC

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.

	2015		2014		2013
(In thousands)
AFUDC:
Debt portion	$	1,666	$	1,228	$	1,260
Equity portion		3,008		1,995		2,274
AFUDC capitalized as part of utility plant	$	4,674	$	3,223	$	3,534

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):

	2015			2014			2013
Change in COLI policies	$	(500	)	$	5,300		$	12,400
Interest income		2,173			2,602			461
Equity AFUDC		3,008			1,995			2,274
Foreign currency transaction gain (loss)		(824	)		(178	)		—
Equity in earnings of unconsolidated investment - Western		310			107			—
Miscellaneous income and (expense)		(1,288	)		(2,719	)		(2,835	)
Total other income (deductions)	$	2,879		$	7,107		$	12,300

Schedule of Earnings Per Share, Basic and Diluted

A reconciliation of the denominator used in the Basic and Diluted EPS calculations is shown in the following table.

	2015		2014		2013
(In thousands)
Average basic shares		46,992		46,494		46,318
Effect of dilutive securities:
Stock options		8		17		26
Performance shares		171		215		231
Restricted stock units		212		218		183
Average diluted shares		47,383		46,944		46,758

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Utility Plant and Leases (Tables)

12 Months Ended

Dec. 31, 2015

Leases [Abstract]

Schedule of Net Utility Plant

Net utility plant as of December 31, 2015 and 2014 was as follows (thousands of dollars):

December 31,	2015			2014
Gas plant:
Storage	$	22,944		$	22,531
Transmission		312,996			312,300
Distribution		4,935,730			4,655,640
General		365,865			356,072
Software and software-related intangibles		203,323			196,035
Other		14,059			14,021
		5,854,917			5,556,599
Less: accumulated depreciation		(2,084,007	)		(1,973,098	)
Acquisition adjustments, net		370			550
Construction work in progress		119,805			74,332
Net utility plant	$	3,891,085		$	3,658,383

Schedule of Depreciation and Amortization Expense

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

	2015		2014		2013
Depreciation and amortization expense	$	201,233	$	194,360	$	185,283

Schedule of Rental Payments for Operating Leases

The table below presents Southwest’s rental payments and Centuri’s lease payments that are included in operating expenses (in thousands):

	2015		2014		2013
Southwest Gas	$	4,186	$	5,330	$	8,308
Centuri		45,849		30,012		27,118
Consolidated rental payments/lease expense	$	50,035	$	35,342	$	35,426

Schedule of Future Minimum Lease Payments for Operating Leases

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	6,836
2017		4,732
2018		2,993
2019		2,110
2020		1,473
Thereafter		3,583
Total minimum lease payments	$	21,727

Schedule of Capital Leases of Equipment

The amounts associated with capital leases of equipment as of December 31, 2015 and 2014 are as follows (thousands of dollars):

December 31,	2015			2014
Capital leases of equipment	$	4,584		$	5,763
Less: accumulated amortization		(1,043	)		(287	)
Net capital leases	$	3,541		$	5,476

Schedule of Future Minimum Lease Payments for Capital Leases

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, 2015 (thousands of dollars):

Year Ending December 31,
2016	$	1,469
2017		869
2018		494
2019		21
2020		—
Thereafter		—
		2,853
Less: amount representing interest		(223	)
Total minimum lease payments	$	2,630

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Receivables and Related Allowances (Tables)

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Schedule of Accounts Receivable

The table below contains information about the gas utility customer accounts receivable balance (net of allowance) at December 31, 2015 and 2014, and the percentage of customers in each of the three states.

	December 31, 2015		December 31, 2014
Gas utility customer accounts receivable balance (in thousands)	$	151,775	$	136,148

Schedule of Percent of Customers by State

	December 31, 2015
Percent of customers by state
Arizona		53	%
Nevada		37	%
California		10	%

Schedule of Allowance for Uncollectibles

 Activity in the allowance account for uncollectibles is summarized as follows (thousands of dollars):

	Allowance for Uncollectibles
Balance, December 31, 2012	$	2,504
Additions charged to expense		3,583
Accounts written off, less recoveries		(4,362	)
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

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

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

December 31,	2015			2014
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	384,647		$	390,293
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,486			5,425
Deferred purchased gas costs (3)		3,591			87,556
Accrued purchased gas costs (4)		—			2,600
Unamortized premium on reacquired debt (5)		21,511			20,478
Other (6)		73,022			72,132
		488,257			578,484
Regulatory liabilities:
Deferred purchased gas costs (3)		(45,601	)		—
Accumulated removal costs		(303,000	)		(304,000	)
Accrued purchased gas costs (4)		(10,400	)		—
Deferred gain on southern Nevada division operations facility (7)		—			(115	)
Unamortized gain on reacquired debt (8)		(10,325	)		(10,862	)
Other (9)		(36,631	)		(34,233	)
Net regulatory assets	$	82,300		$	229,274

(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 the Company’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13).

Instrument	Balance Sheet Location	2015		2014
Swaps	Deferred charges and other assets	$	1,219	$	363
Swaps	Prepaids and other current assets		4 ,267		5,062

(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.

(6) Other regulatory assets including deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as margin and interest-tracking accounts, amounts associated with accrued absence time, and deferred post-retirement benefits other than pensions. Recovery periods vary.

(7) The amortization period ended October 2015.

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

(9) Other regulatory liabilities include amounts associated with income tax and gross-up.

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

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

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

(Thousands of dollars)				2015									2014									2013
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(30,519	)	$	11,597		$	(18,922	)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214
Amortization of prior service cost		1,335			(507	)		828			355			(135	)		220			355			(135	)		220
Amortization of net actuarial (gain)/loss		34,381			(13,065	)		21,316			23,656			(8,989	)		14,667			34,177			(12,987	)		21,190
Prior service cost		—			—			—			(6,661	)		2,531			(4,130	)		—			—			—
Regulatory adjustment		(5,646	)		2,146			(3,500	)		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)
Pension plans other comprehensive income (loss)		(449	)		171			(278	)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973
Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities):
Amounts reclassified into net income		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
FSIRS other comprehensive income (loss)		3,344			(1,271	)		2,073			3,345			(1,272	)		2,073			3,345			(1,271	)		2,074
Foreign currency translation adjustments:
Translation adjustments		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Foreign currency other comprehensive income (loss)		(1,954	)		—			(1,954	)		(659	)		—			(659	)		—			—			—
Total other comprehensive income (loss)	$	941		$	(1,100	)	$	(159	)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047

(1) Tax amounts are calculated using a 38% rate. The Company 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, the Company 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.

Schedule of Estimated Amounts Amortized from Accumulated Other Comprehensive Income or Regulatory Assets into Net Periodic Benefit Cost

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	$	25,000
SERP net actuarial loss		1,400
PBOP net actuarial loss		400
PBOP prior service cost		1,300

Rollforward of Accumulated Other Comprehensive Income

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			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit		After- Tax			AOCI
Beginning Balance AOCI December 31, 2014	$	(57,211)		$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)
Net actuarial gain/(loss)		(30,519	)		11,597			(18,922	)		—			—			—			—			—		—			(18,922	)
Translation adjustments		—			—			—			—			—			—			(1,954	)		—		(1,954	)		(1,954	)
Other comprehensive income before reclassifications		(30,519	)		11,597			(18,922	)		—			—			—			(1,954	)		—		(1,954	)		(20,876	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,344			(1,271	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		1,335			(507	)		828			—			—			—			—			—		—			828
Amortization of net actuarial loss (2)		34,381			(13,065	)		21,316			—			—			—			—			—		—			21,316
Regulatory adjustment (3)		(5,646	)		2,146			(3,500	)		—			—			—			—			—		—			(3,500	)
Net current period other comprehensive income (loss)		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,954	)		—		(1,954	)		(159	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(66	)		—		(66	)		(66	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(449	)		171			(278	)		3,344			(1,271	)		2,073			(1,888	)		—		(1,888	)		(93	)
Ending Balance AOCI December 31, 2015	$	(57,660	)	$	21,911		$	(35,749	)	$	(19,344	)	$	7,350		$	(11,994	)	$	(2,525	)	$	—	$	(2,525	)	$	(50,268	)

(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 Benefitsfor 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).

Amount Recognized Before Income Tax in Accumulated Other Comprehensive Income

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, 2015 and 2014:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2015			2014
Net actuarial (loss) gain	$	(435,269	)	$	(439,131	)
Prior service cost		(7,038	)		(8,373	)
Less: amount recognized in regulatory assets		384,647			390,293
Recognized in AOCI	$	(57,660	)	$	(57,211	)

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt

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,	2015					2014
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	130,273	$	125,000		$	133,403
Notes, 6.1%, due 2041		125,000			141,581		125,000			157,290
Notes, 3.875%, due 2022		250,000			253,600		250,000			262,030
Notes, 4.875%, due 2043		250,000			251,483		250,000			280,903
8% Series, due 2026		75,000			97,035		75,000			102,296
Medium-term notes, 7.59% series, due 2017		25,000			26,253		25,000			27,573
Medium-term notes, 7.78% series, due 2022		25,000			29,855		25,000			31,144
Medium-term notes, 7.92% series, due 2027		25,000			31,890		25,000			33,695
Medium-term notes, 6.76% series, due 2027		7,500			8,684		7,500			9,156
Unamortized discount and debt issuance costs		(6,137	)				(6,604	)
		901,363					900,896
Revolving credit facility and commercial paper		150,000			150,000		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:
5.25% 2003 Series D, due 2038		—			—		20,000			20,277
5.00% 2004 Series B, due 2033		—			—		31,200			31,223
4.85% 2005 Series A, due 2035		100,000			100,452		100,000			100,071
4.75% 2006 Series A, due 2036		24,855			25,130		24,855			25,399
Unamortized discount and debt issuance costs		(3,946	)				(5,964	)
		320,909					370,091
Centuri term loan facility		112,571			112,665		142,071			143,021
Unamortized debt issuance costs		(692	)				(816	)
		111,879					141,255
Centuri secured revolving credit facility		60,627			60,724		57,196			57,320
Centuri other debt obligations		25,901			26,059		31,128			31,127
		1,570,679					1,650,566
Less: current maturities		(19,475	)				(19,192	)
Long-term debt, less current maturities	$	1,551,204				$	1,631,374

Summary of Effective Interest Rates on Variable-Rate IDRBs

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

	December 31, 2015			December 31, 2014
2003 Series A		0.87	%		0.85	%
2008 Series A		0.87	%		0.90	%
2009 Series A		0.75	%		0.89	%
Tax-exempt Series A		0.81	%		0.84	%

Estimated Maturities of Long-Term Debt

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

2016	$	19,475
2017		42,245
2018		14,906
2019		142,452
2020		275,238

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Pension and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Cost of Retirement Plan

The cost of the Southwest plan is listed below (in thousands):

	2015		2014		2013
Employee Investment Plan cost	$	5,072	$	4,816	$	4,850

Schedule of Allocation of Plan Assets

 At December 31, 2015, the percentage ranges of the target portfolio are:

Type of Investment	Percentage Range
Equity securities		59 to 71
Debt securities		31 to 37
Other		up to 5

Schedule of Assumptions Used

The rates are presented in the table below:

	December 31, 2015			December 31, 2014
Discount rate		4.50	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		2.75	%
Asset return assumption		7.25	%		7.75	%

Schedule of Amounts Recognized in Balance Sheet and Income Statement

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.

	2015									2014
	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)	$	1,060,240		$	41,176		$	72,202		$	886,714		$	36,143		$	58,020
Service cost		25,123			320			1,641			21,360			292			1,101
Interest cost		44,229			1,695			2,999			43,440			1,745			2,829
Plan amendments		—			—			—			—			—			6,661
Actuarial loss (gain)		(44,553	)		2,322			(3,251	)		144,606			5,459			4,567
Benefits paid		(40,222	)		(2,793	)		(959	)		(35,880	)		(2,463	)		(976	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,044,817			42,720			72,632			1,060,240			41,176			72,202
Change in plan assets
Market value of plan assets at beginning of year		754,796			—			44,892			719,944			—			42,314
Actual return on plan assets		(13,694	)		—			(1,034	)		34,732			—			2,859
Employer contributions		36,000			2,793			—			36,000			2,463			—
Benefits paid		(40,222	)		(2,793	)		(274	)		(35,880	)		(2,463	)		(281	)
Market value of plan assets at end of year		736,880			—			43,584			754,796			—			44,892
Funded status at year end	$	(307,937	)	$	(42,720	)	$	(29,048	)	$	(305,444	)	$	(41,176	)	$	(27,310	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.50	%		4.50	%		4.50	%		4.25	%		4.25	%		4.25	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		N/A			2.75	%		2.75	%		N/A

Schedule of Accumulated Benefit Obligation

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

	December 31, 2015		December 31, 2014
Retirement plan	$	922,992	$	886,215
SERP		39,270		39,125

Schedule of Expected Benefit Payments

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

	2016	2017	2018	2019		2020		2021-2025
Pension	$44.0	$45.5	$47.2		$48.9		$50.5		$283.5
PBOP	3.9	4.1	4.3		4.5		4.5		21.3
SERP	2.8	2.8	2.8		2.9		2.9		14.1

Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2015			2014			2013			2015			2014			2013			2015			2014			2013
(Thousands of dollars)
Service cost	$	25,123		$	21,360		$	23,056		$	320		$	292		$	373		$	1,641		$	1,101		$	1,220
Interest cost		44,229			43,440			37,607			1,695			1,745			1,535			2,999			2,829			2,482
Expected return on plan assets		(57,808	)		(53,342	)		(49,840	)		—			—			—			(3,464	)		(3,264	)		(2,824	)
Amortization of prior service cost		—			—			—			—			—			—			1,335			355			355
Amortization of net actuarial loss		32,743			22,873			32,261			1,293			783			971			345			—			945
Net periodic benefit cost	$	44,287		$	34,331		$	43,084		$	3,308		$	2,820		$	2,879		$	2,856		$	1,021		$	2,178
Weighted-average assumptions (net benefit cost)
Discount rate		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%		4.25	%		5.00	%		4.25	%
Expected return on plan assets		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%		7.75	%		7.75	%		8.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%		2.75	%		2.75	%		3.25	%		2.75	%		N/A			N/A			N/A

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

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

	2015												2014												2013
	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)	$	30,519		$	26,949		$	2,322		$	1,248		$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)
Amortization of prior service cost (b)		(1,335	)		—			—			(1,335	)		(355	)		—			—			(355	)		(355	)		—			—			(355	)
Amortization of net actuarial loss (b)		(34,381	)		(32,743	)		(1,293	)		(345	)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)
Prior service cost		—			—			—			—			6,661			—			—			6,661			—			—			—			—
Regulatory adjustment		5,646			5,214			—			432			(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868
Recognized in other comprehensive
(income) loss		449			(580	)		1,029			—			15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—
Net periodic benefit costs recognized in net income		50,451			44,287			3,308			2,856			38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,900		$	43,707		$	4,337		$	2,856		$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178

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.

Schedule of Fair Value of Plan Assets

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, 2015 and December 31, 2014. The SERP has no assets. The FASB issued guidance in 2015, which the Company has adopted early as permitted, removing the requirement to categorize assets in the fair value hierarchy that are measured using the net asset value (“NAV”) practical expedient. See note (3) to the table below. Based on this guidance, no Level 3 assets existed (nor are reflected in the table below) at December 31, 2015 and December 31, 2014.

	December 31, 2015								December 31, 2014
	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		$	6,661	$	198	$	6,859
Capital equipment		533			16		549			2,222		66		2,288
Chemicals/materials		3,304			98		3,402			5,233		155		5,388
Consumer goods		41,035			1,221		42,256			41,731		1,238		42,969
Energy and mining		11,066			329		11,395			18,502		549		19,051
Finance/insurance		29,957			892		30,849			20,685		613		21,298
Healthcare		37,930			1,129		39,059			37,846		1,122		38,968
Information technology		29,229			870		30,099			25,881		767		26,648
Services		12,341			367		12,708			28,846		855		29,701
Telecommunications/internet/media		25,883			770		26,653			18,498		549		19,047
Other		9,043			269		9,312			10,958		325		11,283
Real estate investment trusts		5,010			149		5,159			5,713		169		5,882
Mutual funds		87,483			23,985		111,468			86,159		24,567		110,726
Government fixed income securities		33,482			996		34,478			44,694		1,325		46,019
Preferred securities		—			—		—			568		17		585
Futures contracts		(7	)		—		(7	)		—		—		—
Total Level 1 Assets (1)	$	333,310		$	31,300	$	364,610		$	354,197	$	32,515	$	386,712
Level 2 – Significant other observable inputs
Government fixed income and mortgage backed securities	$	49,571		$	1,475	$	51,046		$	48,312	$	1,433	$	49,745
Corporate fixed income securities
Asset-backed and mortgage-backed		23,542			701		24,243			27,071		803		27,874
Banking		20,857			621		21,478			23,289		691		23,980
Insurance		4,896			146		5,042			6,182		183		6,365
Utilities		3,826			114		3,940			4,232		126		4,358
Other		30,995			922		31,917			23,120		686		23,806
Pooled funds and mutual funds		14,808			796		15,604			11,968		984		12,952
Real estate investment trusts		1,949			58		2,007			—		—		—
State and local obligations		950			28		978			1,499		44		1,543
Preferred securities		554			17		571			—		—		—
Convertible securities		196			6		202			—		—		—
Total Level 2 assets (2)	$	152,144		$	4,884	$	157,028		$	145,673	$	4,950	$	150,623
Total Plan assets at fair value	$	485,454		$	36,184	$	521,638		$	499,870	$	37,465	$	537,335
Commingled equity funds (3)		250,511			7,455		257,966			259,235		7,687		266,922
Insurance company general account contracts (4)		3,719			—		3,719			4,003		—		4,003
Total Plan assets (5)	$	739,684		$	43,639	$	783,323		$	763,108	$	45,152	$	808,260

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

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 balanced fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income.

(2) The fair value of investments in debt securities with remaining maturities of one year or more is 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.

The pooled funds and mutual funds are two collective short-term funds that invest in Treasury bills and money market funds. These funds are used as a temporary cash repository for the pension plan’s various investment managers.

(3) The commingled equity funds include 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 include:

• 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 may be redeemed vary among the funds; the notice required ranges from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds requires the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminishes the greater the transaction. Other such funds may impose fees to recover direct costs incurred by the fund at redemption, but are indeterminable prior to redemption.

Early adoption of ASU No. 2015-07: As permitted the Company adopted (earlier than the required adoption date) FASB ASU No. 2015-07 “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent)” as of December 31, 2015. This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the NAV per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the NAV per share practical expedient. The FASB determined that including those assets in the fair value hierarchy is potentially confusing and misleading to financial statement users. The fair value of the commingled equity funds was determined using NAV as an expedient since no significant observable inputs were available (these funds are not publicly traded on an exchange). Because of the requirements of this update, the commingled equity funds are no longer included in the above fair value hierarchy table as a Level 3 fair value measurement but instead are disclosed as a reconciling item to the table. The associated Fair Value Measurement Using Significant Unobservable Inputs (Level 3) table is no longer presented due to this change, as the commingled equity funds were the only assets whose values were previously indicated to be Level 3 fair value measurements.

(4) 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.

(5) The assets in the above table exceed 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) and $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) for 2015 and 2014, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Stock-Based Plan Compensation Expense, Including Cash Award

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):

	2015		2014		2013
Stock-based compensation plan expense, net of related tax benefits	$	7,278	$	8,130	$	8,012
Stock-based compensation plan related tax benefits		4,461		4,983		4,910

Schedule of Stock Options Activity

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

	2015					2014					2013
	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		36		$	28.97		52		$	27.57		125		$	28.13
Exercised during the year		(19	)		26.69		(16	)		24.31		(72	)		28.44
Forfeited or expired during the year		—			—		—			—		(1	)		33.07
Outstanding and exercisable at year end		17		$	31.64		36		$	28.97		52		$	27.57

Schedule of Aggregate Intrinsic Value of Outstanding and Exercisable Options

The aggregate intrinsic value of outstanding and exercisable options, and options that were exercised, are presented in the table below (in thousands):

	2015		2014		2013
Outstanding and exercisable	$	394	$	1,194	$	1,473
Exercised		590		451		1,402

Summary of Market Prices of Common Stock

	December 31, 2015		December 31, 2014		December 31, 2013
Market value of Southwest Gas stock	$	55.16	$	61.81	$	55.91

Schedule of Stock Options Outstanding and Exercisable

The following table summarizes information about stock options outstanding at December 31, 2015 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$29.08 to $33.07		17		0.5 Years	$	31.64

Schedule of Nonvested Performance and Restricted Stock Unit Plans

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2015 (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		271		$	43.71		257		$	41.22
Granted		80			63.09		73			63.09
Dividends		6					7
Forfeited or expired		—			—		—			—
Vested and issued*		(160	)		43.12		(109	)		46.65
Nonvested/unissued at December 31, 2015		197		$	50.63		228		$	44.36

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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Summary of Income Before Taxes and Noncontrolling Interest for Domestic and Foreign Operations

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

Year ended December 31,	2015			2014			2013
U.S.	$	221,660		$	221,471		$	222,815
Foreign		(2,328	)		(1,950	)		—
Total income before income taxes	$	219,332		$	219,521		$	222,815

Summary of Income Tax Expense (Benefit)

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

Year Ended December 31,	2015			2014			2013
Current:
Federal	$	21,321		$	1,739		$	3,549
State		9,899			5,073			5,107
Foreign		650			2,193			—
		31,870			9,005			8,656
Deferred:
Federal		51,132			71,439			67,414
State		(2,574	)		614			1,872
Foreign		(526	)		(2,685	)		—
		48,032			69,368			69,286
Total income tax expense	$	79,902		$	78,373		$	77,942

Significant Components of Deferred Income Tax Expense (Benefit)

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

Year Ended December 31,	2015			2014			2013
Deferred federal and state:
Property-related items	$	65,931		$	52,814		$	62,737
Purchased gas cost adjustments		(32,993	)		15,049			16,189
Employee benefits		623			109			(2,769	)
All other deferred		15,332			2,257			(6,010	)
Total deferred federal and state		48,893			70,229			70,147
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	48,032		$	69,368		$	69,286

Reconciliation of U.S Federal Statutory Rate to Consolidated Effective Tax Rate

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2013, 2014, and 2015 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2015			2014			2013
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.8			1.9			2.4
Property-related items		0.1			0.1			0.1
Tax credits		(0.4	)		(0.5	)		(0.4	)
Company owned life insurance		0.1			(1.0	)		(2.1	)
All other differences		(0.2	)		0.2			—
Consolidated effective income tax rate		36.4	%		35.7	%		35.0	%

Deferred Tax Assets and Liabilities

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

December 31,	2015			2014
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	1,614		$	2,146
Employee benefits		36,923			31,557
Alternative minimum tax credit		4,809			20,172
Net operating losses and credits		868			9,719
Interest rate swap		7,351			8,622
Other		24,636			25,872
Valuation allowance		(499	)		(253	)
		75,702			97,835
Deferred tax liabilities:
Property-related items, including accelerated depreciation		794,850			736,810
Regulatory balancing accounts		743			33,736
Unamortized ITC		2,549			3,410
Debt-related costs		5,497			5,066
Intangibles		9,547			12,792
Other		31,533			27,600
		844,719			819,414
Net deferred tax liabilities		769,017			721,579
Current		—			(2,109	)
Noncurrent		769,017			723,688
Net deferred tax liabilities	$	769,017		$	721,579

Reconciliation of Unrecognized Tax Benefits

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

	2015			2014
Unrecognized tax benefits at beginning of year	$	305		$	—
Gross increases-tax positions in prior period		—			305
Gross decreases-tax positions in prior period		(9	)		—
Gross increases-current period tax positions		—			—
Gross decreases-current period tax positions		—			—
Settlements		—			—
Lapse in statute of limitations		—			—
Unrecognized tax benefits at end of year	$	296		$	305

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Derivatives and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Notional Amounts under Swaps Contracts

The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):

	December 31, 2015		December 31, 2014
Contract notional amounts		7,407		5,105

Amount of Gain or Losses Recognized in Income on Derivatives

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2015, 2014, and 2013 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	2015			2014			2013
Swaps	Net cost of gas sold	$	(7,598	)	$	(2,363	)	$	976
Swaps	Net cost of gas sold		7,598	*		2,363	*		(976	)*
Total		$	—		$	—		$	—

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

Fair Values of Swaps in Consolidated Balance Sheets

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

Fair values of derivatives not designated as hedging instruments:

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	)
December 31, 2014 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(5,062	)	$	(5,062	)
Swaps	Other deferred credits		—		(363	)		(363	)
Total		$	—	$	(5,425	)	$	(5,425	)

Paid to and Received from Counterparties for Settlements of Matured Swaps

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

	Year ended December 31, 2015		Year ended December 31, 2014		Year ended December 31, 2013
(Thousands of dollars)
Paid to counterparties	$	7,537	$	829	$	3,148
Received from counterparties	$	—	$	4,713	$	915

Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Condensed Consolidated Balance Sheets

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

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
December 31, 2014 Instrument	Balance Sheet Location		Net Total
Swaps		Prepaids and other current assets	$	5,062
Swaps		Deferred charges and other assets		363

Significant Other Observable Inputs

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (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, 2015			December 31, 2014
(Thousands of dollars)
Liabilities at fair value:
Other current liabilities—Swaps	$	(4,267	)	$	(5,062	)
Other deferred credits—Swaps		(1,219	)		(363	)
Net Assets (Liabilities)	$	(5,486	)	$	(5,425	)

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Accounts Receivable for Services

Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).

	December 31, 2015		December 31, 2014
Accounts receivable for Centuri services	$	10,006	$	9,169

Schedule of Revenues and Long-Lived Assets by Geographic Area

The following table presents the amount of revenues and long-lived assets for both segments by geographic area (thousands of dollars):

	December 31, 2015		December 31, 2014
Revenues (a)
United States	$	2,289,133	$	2,069,513
Canada		174,492		52,194
Total	$	2,463,625	$	2,121,707

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

Schedule of Segment Reporting Information

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, 2015 is as follows (thousands of dollars):

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
2013	Gas Operations		Construction Services		Adjustments (b)			Total
Revenues from unaffiliated customers	$	1,300,154	$	562,475				$	1,862,629
Intersegment sales		—		88,153					88,153
Total	$	1,300,154	$	650,628				$	1,950,782
Interest revenue	$	456	$	5				$	461
Interest expense	$	62,555	$	1,145				$	63,700
Depreciation and amortization	$	193,848	$	42,969				$	236,817
Income tax expense	$	65,377	$	12,565				$	77,942
Segment net income	$	124,169	$	21,151				$	145,320
Segment assets	$	4,272,029	$	293,811	$	(666	)	$	4,565,174
Capital expenditures	$	314,578	$	49,698				$	364,276

(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.

(b) Construction services segment assets included income taxes payable of $666,000 in 2013, which was netted against gas operations segment income taxes receivable, net during consolidation.

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

	Quarter Ended
	March 31		June 30		September 30			December 31
(Thousand of dollars, except per share amounts)
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
2013
Operating revenues	$	613,505	$	411,574	$	387,346		$	538,357
Operating income		138,394		28,908		6,141			100,772
Net income (loss)		80,674		10,067		(3,057	)		57,189
Net income (loss) attributable to Southwest Gas Corporation		80,773		10,108		(2,864	)		57,303
Basic earnings (loss) per common share*		1.75		0.22		(0.06	)		1.24
Diluted earnings (loss) per common share*		1.73		0.22		(0.06	)		1.22

* 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.

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Construction Services Noncontrolling Interests (Tables)

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest [Abstract]

Summary of Redeemable Noncontrolling Interest

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, 2014	$	20,042
Net Income (loss) attributable to redeemable noncontrolling interest		939
Foreign currency exchange translation adjustment		(66	)
Centuri distribution to redeemable noncontrolling interest		(99	)
Adjustment to redemption value		(4,708	)
Balance, December 31, 2015	$	16,108

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Acquisition of Construction Services Businesses (Tables)

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Revised Fair Values of Assets Acquired and Liabilities Assumed

The October 1, 2014 fair values of assets acquired and liabilities assumed, revised during the first quarter of 2015, are as follows (in millions of dollars):

	Acquisition Date		Measurement Period Adjustments			Revised Acquisition Date
Cash, cash equivalents, and restricted cash	$	3	$	—		$	3
Contracts receivable and other receivables		62		—			62
Property, plant and equipment		17		—			17
Other assets		17		(2	)		15
Intangible assets		52		—			52
Goodwill		130		1			131
Total assets acquired		281		(1	)		280
Current liabilities		39		1			40
Deferred income tax—long-term		17		—			17
Other long-term liabilities		4		—			4
Net assets acquired	$	221	$	(2	)	$	219

Schedule of Unaudited Pro Forma Consolidated Financial Information

The unaudited pro forma consolidated financial information for fiscal 2014 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning of fiscal 2014) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31, 2014
Total operating revenues	$	2,295,318
Net income attributable to Southwest Gas Corporation	$	149,588
Basic earnings per share	$	3.22
Diluted earnings per share	$	3.19

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Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($) Segment Markets	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Significant Accounting Policies [Line Items]
Number of segments | Segment	2
Earnings from equity method investment	$ 310,000	$ 107,000
Non-cash construction advances - non-cash investing item	3,100,000	8,100,000	$ 9,300,000
Non-cash investing outflow activity		10,800,000
Goodwill impairment charges	0	0
Acquisition date adjustments to goodwill	1,380,000
Brigadier [Member]
Significant Accounting Policies [Line Items]
Goodwill assigned for deductible tax purpose	$ 4,900,000
Non-controlling Interest [Member]
Significant Accounting Policies [Line Items]
Non-cash investing outflow activity		18,900,000
Intellichoice Energy, LLC [Member]
Significant Accounting Policies [Line Items]
Subsidiaries holding interest percentage	65.00%
W.S. Nicholls Western Construction LTD. [Member]
Significant Accounting Policies [Line Items]
Investment amount	$ 10,800,000	14,700,000
Dividends	0
Exposure to loss as a result of its investment	14,700,000
Earnings from equity method investment	$ 310,000
Matheson-Nicholls Joint Venture [Member]
Significant Accounting Policies [Line Items]
Subsidiaries holding interest percentage	50.00%
CCI-TBN Toronto, Inc [Member]
Significant Accounting Policies [Line Items]
Subsidiaries holding interest percentage	25.00%
Centuri Construction Group Inc [Member]
Significant Accounting Policies [Line Items]
Ownership percentage in subsidiary	96.60%
Number of major markets | Markets	20
Intangible assets	$ 36,773,000	48,175,000
Construction expenses	7,700,000
Final settlement amount	4,000,000
Loss on construction contract	$ 3,400,000
Centuri Construction Group Inc [Member] | W.S. Nicholls Western Construction LTD. [Member]
Significant Accounting Policies [Line Items]
Subsidiaries holding interest percentage	50.00%
Pooled Funds and Mutual Funds [Member] | Level 2 - Significant Other Observable Inputs [Member]
Significant Accounting Policies [Line Items]
Money market fund investments	$ 250,000	250,000
Gas Pipe Materials and Supplies [Member]
Significant Accounting Policies [Line Items]
Gas pipe inventory and operating supplies	$ 24,000,000	$ 23,000,000

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Summary of Significant Accounting Policies - Schedule of Other Property and Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Investment [Line Items]
Net cash surrender value of COLI policies	$ 99,000	$ 99,000
Other property	13,000	10,000
Total	313,531	326,743
Centuri Construction Group Inc [Member]
Investment [Line Items]
Centuri property, equipment, and intangibles	423,000	405,000
Centuri accumulated provision for depreciation and amortization	$ (221,000)	$ (187,000)

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Summary of Significant Accounting Policies - Schedule of Goodwill (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Goodwill [Line Items]
Goodwill, Beginning balance	$ 143,160
Acquisition date adjustment	1,380
Foreign currency translation adjustment	(18,395)
Goodwill, Ending balance	126,145
Natural Gas Operations [Member]
Goodwill [Line Items]
Goodwill, Beginning balance	10,095
Acquisition date adjustment	0
Foreign currency translation adjustment	0
Goodwill, Ending balance	10,095
Construction Services [Member]
Goodwill [Line Items]
Goodwill, Beginning balance	133,065
Acquisition date adjustment	1,380
Foreign currency translation adjustment	(18,395)
Goodwill, Ending balance	$ 116,050

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Summary of Significant Accounting Policies - Summary of Intangible Assets (Detail) - Centuri Construction Group Inc [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 41,890	$ 49,698
Accumulated Amortization	(5,117)	(1,523)
Net Carrying Amount	36,773	48,175
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	31,226	37,059
Accumulated Amortization	(2,070)	(524)
Net Carrying Amount	29,156	36,535
Trade Names and Trademarks [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	8,621	10,208
Accumulated Amortization	(1,331)	(241)
Net Carrying Amount	7,290	9,967
Customer Contracts Backlog [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	1,606	1,912
Accumulated Amortization	(1,606)	(724)
Net Carrying Amount		1,188
Non-compete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	437	519
Accumulated Amortization	(110)	(34)
Net Carrying Amount	$ 327	$ 485

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Summary of Significant Accounting Policies - Schedule of Estimated Future Amortization of Intangible Assets (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2016	$ 2,809
2017	2,809
2018	2,605
2019	1,971
2020	$ 1,906

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Summary of Significant Accounting Policies - Schedule of Capitalized and Debt Portion of AFUDC (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Debt portion	$ 1,666	$ 1,228	$ 1,260
Equity portion	3,008	1,995	2,274
AFUDC capitalized as part of utility plant	$ 4,674	$ 3,223	$ 3,534

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Summary of Significant Accounting Policies - Other Income (Deductions) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Income and Expenses [Abstract]
Change in COLI policies	$ (500)	$ 5,300	$ 12,400
Interest income	2,173	2,602	461
Equity AFUDC	3,008	1,995	2,274
Foreign currency transaction gain (loss)	(824)	(178)
Equity in earnings of unconsolidated investment - Western	310	107
Miscellaneous income and (expense)	(1,288)	(2,719)	(2,835)
Total other income (deductions)	$ 2,879	$ 7,107	$ 12,300

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Summary of Significant Accounting Policies - Schedule of Earnings Per Share, Basic and Diluted (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Average basic shares	46,992	46,494	46,318
Stock options	8	17	26
Performance shares	171	215	231
Restricted stock units	212	218	183
Average diluted shares	47,383	46,944	46,758

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Utility Plant and Leases - Schedule of Net Utility Plant (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 5,854,917	$ 5,556,599
Less: accumulated depreciation	(2,084,007)	(1,973,098)
Acquisition adjustments, net	370	550
Construction work in progress	119,805	74,332
Net utility plant	3,891,085	3,658,383
Software and Software-related Intangibles [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	203,323	196,035
Storage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	22,944	22,531
Transmission [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	312,996	312,300
Distribution [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	4,935,730	4,655,640
General [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	365,865	356,072
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 14,059	$ 14,021

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Utility Plant and Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Annual depreciation and amortization expense percentage	3.60%	3.60%	3.60%
Gas plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Amortization of intangibles	$ 12.7	$ 11.7	$ 10.3

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Utility Plant and Leases - Schedule of Depreciation and Amortization Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 270,111	$ 253,027	$ 236,817
Gas plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 201,233	$ 194,360	$ 185,283

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Utility Plant and Leases - Schedule of Rental Payments for Operating Leases (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	$ 50,035	$ 35,342	$ 35,426
Southwest Gas [Member]
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	4,186	5,330	8,308
Centuri Construction Group Inc [Member]
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	$ 45,849	$ 30,012	$ 27,118

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Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Operating Leases (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Leases [Abstract]
2016	$ 6,836
2017	4,732
2018	2,993
2019	2,110
2020	1,473
Thereafter	3,583
Total minimum lease payments	$ 21,727

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Utility Plant and Leases - Schedule of Capital Leases of Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Leases [Abstract]
Capital leases of equipment	$ 4,584	$ 5,763
Less: accumulated amortization	(1,043)	(287)
Net capital leases	$ 3,541	$ 5,476

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Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Capital Leases (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Leases [Abstract]
2016	$ 1,469
2017	869
2018	494
2019	21
2020	0
Thereafter	0
Future minimum lease payments due	2,853
Less: amount representing interest	(223)
Total minimum lease payments	$ 2,630

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Receivables and Related Allowances - Schedule of Accounts Receivable (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Gas utility customer accounts receivable balance	$ 151,775	$ 136,148

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Receivables and Related Allowances - Schedule of Percent of Customers by State (Detail)	12 Months Ended
	Dec. 31, 2015
Arizona [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	53.00%
Nevada [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	37.00%
California [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	10.00%

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Receivables and Related Allowances - Schedule of Allowance for Uncollectibles (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Receivables [Abstract]
Beginning Balance	$ 2,255	$ 1,725	$ 2,504
Additions charged to expense	4,113	4,146	3,583
Accounts written off, less recoveries	(4,098)	(3,616)	(4,362)
Ending Balance	$ 2,270	$ 2,255	$ 1,725

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Receivables and Related Allowances - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Receivables And Related Allowances [Line Items]
Customer accounts receivable	$ 314,512	$ 281,824
Centuri Construction Group Inc [Member]
Receivables And Related Allowances [Line Items]
Customer accounts receivable	$ 162,000

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	$ 488,257	$ 578,484
Net regulatory assets	82,300	229,274
Accrued Pension and Other Postretirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	384,647	390,293
Unrealized Net Loss on Non-trading Derivatives (Swaps) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	5,486	5,425
Deferred Purchased Gas Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	3,591	87,556
Regulatory liabilities, total	(45,601)
Accrued Purchased Gas Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total		2,600
Regulatory liabilities, total	(10,400)
Unamortized Premium on Reacquired Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	21,511	20,478
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	73,022	72,132
Accumulated Removal Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(303,000)	(304,000)
Deferred Gain on Southern Nevada Division Operations Facility [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total		(115)
Unamortized Gain on Reacquired Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(10,325)	(10,862)
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	$ (36,631)	$ (34,233)

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Parenthetical) (Detail) - Swaps [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Charges and Other Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	$ 1,219	$ 363
Prepaids and Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	$ 4,267	$ 5,062

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Net actuarial gain/(loss), Before-Tax Amount	$ (30,519)	$ (173,646)	$ 100,345
Amortization of prior service cost, Before-Tax Amount	1,335	355	355
Amortization of net actuarial (gain)/loss, Before-Tax Amount	34,381	23,656	34,177
Prior service cost, Before-Tax Amount	0	(6,661)	0
Regulatory adjustment, Before-Tax Amount	(5,646)	140,308	(123,630)
Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax	(449)	(15,988)	11,247
Amounts reclassified into net income, Before-Tax Amount	3,344	3,345	3,345
FSIRS other comprehensive income (loss), Before-Tax Amount	3,344	3,345	3,345
Translation adjustments, Before-Tax Amount	(1,954)	(659)	0
Foreign currency other comprehensive income (loss), Before-Tax Amount	(1,954)	(659)	0
Total other comprehensive income (loss), Before-Tax Amount	941	(13,302)	14,592
Net actuarial gain/(loss), Tax (Expense) or Benefit	11,597	65,985	(38,131)
Amortization of prior service cost, Tax (Expense) or Benefit	(507)	(135)	(135)
Amortization of net actuarial (gain)/loss, Tax (Expense) or Benefit	(13,065)	(8,989)	(12,987)
Prior service cost, Tax (Expense) or Benefit	0	2,531	0
Regulatory adjustment, Tax (Expense) or Benefit	2,146	(53,317)	46,979
Pension plans other comprehensive income (loss), Tax (Expense) or Benefit	171	6,075	(4,274)
Amounts reclassified into net income, Tax (Expense) or Benefit	(1,271)	(1,272)	(1,271)
FSIRS other comprehensive income (loss), Tax (Expense) or Benefit	(1,271)	(1,272)	(1,271)
Translation adjustments, Tax (Expense) or Benefit	0	0	0
Foreign currency other comprehensive income (loss), Tax (Expense) or Benefit	0	0	0
Total other comprehensive income (loss), Tax (Expense) or Benefit	(1,100)	4,803	(5,545)
Net actuarial gain/(loss), Net-of-Tax Amount	(18,922)	(107,661)	62,214
Amortization of prior service cost, Net-of-Tax Amount	828	220	220
Amortization of net actuarial (gain)/loss, Defined Benefit Plans After-Tax	21,316	14,667	21,190
Prior service cost, Net-of-Tax Amount		(4,130)
Regulatory adjustment, Net-of-Tax Amount	(3,500)	86,991	(76,651)
Pension plans other comprehensive income (loss), Net-of-Tax Amount	(278)	(9,913)	6,973
Amounts reclassified into net income	2,073	2,073	2,074
FSIRS other comprehensive income (loss), Net-of-Tax Amount	2,073	2,073	2,074
Translation adjustments, Net-of-Tax Amount	(1,954)	(659)
Foreign currency other comprehensive income (loss), Net-of-Tax Amount	(1,954)	(659)
Total other comprehensive income (loss), net of tax	$ (159)	$ (8,499)	$ 9,047

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($)
Equity [Abstract]
Other comprehensive income loss, effective income tax rate	38.00%
Tax expense or benefit for currency translation adjustment	$ 0

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Schedule of Estimated Amounts Amortized from Accumulated Other Comprehensive Income or Regulatory Assets into Net Periodic Benefit Cost (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	$ 25,000
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	1,400
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	400
PBOP prior service cost	$ 1,300

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Rollforward of Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Beginning Balance AOCI December 31, 2014, Defined Benefit Plans Before-Tax	$ (57,211)
Net actuarial gain/(loss), Defined Benefit Plans Before-Tax	(30,519)	$ (173,646)	$ 100,345
Translation adjustments, Defined Benefit Plans Before-Tax	0
Other comprehensive income before reclassifications, Defined Benefit Plans Before-Tax	(30,519)
Amortization of prior service cost, Defined Benefit Plans Before-Tax	1,335	355	355
Amortization of net actuarial loss, Defined Benefit Plans Before-Tax	34,381	23,656	34,177
Regulatory adjustment, Defined Benefit Plans Before-Tax	(5,646)	140,308	(123,630)
Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax	(449)	(15,988)	11,247
Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans Before-Tax	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans Before-Tax	(449)
Ending Balance AOCI December 31, 2015, Defined Benefit Plans Before-Tax	(57,660)	(57,211)
Beginning Balance AOCI December 31, 2014, Defined Benefit Plans Tax (Expense) Benefit	21,740
Net actuarial gain/(loss), Tax (Expense) or Benefit	11,597	65,985	(38,131)
Translation adjustments, Defined Benefit Plans Tax (Expense) Benefit	0
Other comprehensive income before reclassifications, Defined Benefit Plans Tax (Expense) Benefit	11,597
Amortization of prior service cost, Defined Benefit Plans Tax (Expense) Benefit	(507)	(135)	(135)
Amortization of net actuarial loss, Defined Benefit Plans Tax (Expense) Benefit	(13,065)	(8,989)	(12,987)
Regulatory adjustment, Defined Benefit Plans Tax (Expense) Benefit	2,146	(53,317)	46,979
Pension plans other comprehensive income (loss), Tax (Expense) or Benefit	171	6,075	(4,274)
Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans Tax (Expense) Benefit	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans Tax (Expense) Benefit	171
Ending Balance AOCI December 31, 2015, Defined Benefit Plans Tax (Expense) Benefit	21,911	21,740
Beginning Balance AOCI December 31, 2014, Defined Benefit Plans After-Tax	(35,471)
Net actuarial gain/(loss), Defined Benefit Plans After-Tax	(18,922)	(107,661)	62,214
Translation adjustments, Defined Benefit Plans After-Tax	0
Other comprehensive income before reclassifications, Defined Benefit Plans After-Tax	(18,922)
Amortization of prior service cost, Defined Benefit Plans After-Tax	828	220	220
Amortization of net actuarial (gain)/loss, Defined Benefit Plans After-Tax	21,316	14,667	21,190
Regulatory adjustment, Defined Benefit Plans After-Tax	(3,500)
Net defined benefit pension plans	(278)	(9,913)	6,973
Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans After-Tax	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans After-Tax	(278)
Ending Balance AOCI December 31, 2015, Defined Benefit Plans After-Tax	(35,749)	35,471
Beginning Balance AOCI December 31, 2014, FSIRS - Before-Tax	(22,688)
Translation adjustments, FSIRS - Before-Tax	0
Other comprehensive income before reclassifications, FSIRS - Before-Tax	0
FSIRS amounts reclassified from AOCI, FSIRS - Before-Tax	3,344	3,345	3,345
Net current period other comprehensive income (loss), FSIRS - Before-Tax	3,344	3,345	3,345
Less: Translation adjustment attributable to redeemable noncontrolling interest, FSIRS - Before-Tax	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - Before-Tax	3,344
Ending Balance AOCI December 31, 2015, FSIRS - Before-Tax	(19,344)	(22,688)
Beginning Balance AOCI December 31, 2014, FSIRS - Tax (Expense) Benefit	8,621
Translation adjustments, FSIRS - Tax (Expense) Benefit	0
Other comprehensive income before reclassifications, FSIRS - Tax (Expense) Benefit	0
FSIRS amounts reclassified from AOCI, FSIRS - Tax (Expense) Benefit	(1,271)	(1,272)	(1,271)
Net current period other comprehensive income (loss), FSIRS - Tax (Expense) Benefit	(1,271)	(1,272)	(1,271)
Less: Translation adjustment attributable to redeemable noncontrolling interest, FSIRS - Tax (Expense) Benefit	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - Tax (Expense) Benefit	(1,271)
Ending Balance AOCI December 31, 2015, FSIRS - Tax (Expense) Benefit	7,350	8,621
Beginning Balance AOCI December 31, 2014, FSIRS - After-Tax	(14,067)
Translation adjustments, FSIRS - After-Tax	0
Other comprehensive income before reclassifications	0
FSIRS amounts reclassified from AOCI, FSIRS - After-Tax	2,073	2,073	2,074
Net current period other comprehensive income (loss)	2,073	2,073	2,074
Less: Translation adjustment attributable to redeemable noncontrolling interest	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - After-Tax	2,073
Ending Balance AOCI December 31, 2015, FSIRS - After-Tax	(11,994)	(14,067)
Beginning Balance AOCI December 31, 2014, Foreign Currency Items Before-Tax	(637)
Net actuarial gain (loss)	0
Translation adjustments, Foreign Currency Items Before-Tax	(1,954)	(659)	0
Other comprehensive income before reclassifications	(1,954)	(659)	0
FSIRS amounts reclassified from AOCI, Foreign Currency Items Before-Tax	0
Amortization of prior service cost, Foreign Currency Items Before-Tax	0
Amortization of net actuarial loss, Foreign Currency Items Before-Tax	0
Regulatory adjustment, Foreign Currency Items Before-Tax	0
Net current period other comprehensive income (loss)	(1,954)
Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency Items Before-Tax	(66)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items Before-Tax	(1,888)	(637)
Ending Balance AOCI December 31, 2015	(2,525)	(637)
Beginning Balance AOCI December 31, 2014, Foreign Currency items - Tax (Expense) Benefit	0
Net actuarial gain (loss)	0
Translation adjustments, Foreign Currency items - Tax (Expense) Benefit	0	0	0
Other comprehensive income before reclassifications, Foreign Currency items - Tax (Expense) Benefit	0
FSIRS amounts reclassified from AOCI, Foreign Currency items - Tax (Expense) Benefit	0
Amortization of prior service cost ,Foreign Currency items - Tax (Expense) Benefit	0
Amortization of net actuarial loss, Foreign Currency items - Tax (Expense) Benefit	0
Regulatory adjustment, Foreign Currency items - Tax (Expense) Benefit	0
Net current period other comprehensive income (loss), Foreign Currency items - Tax (Expense) Benefit	0
Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency items - Tax (Expense) Benefit	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency items - Tax (Expense) Benefit	0	0	0
Ending Balance AOCI December 31, 2015, Foreign Currency items - Tax (Expense) Benefit	0	0
Beginning Balance AOCI December 31, 2014, Foreign Currency items - After-Tax	(637)
Net actuarial gain (loss)	0
Translation adjustments, Foreign Currency items - After-Tax	(1,954)	(659)
Other comprehensive income before reclassifications, Foreign Currency items - After-Tax	(1,954)	(659)
FSIRS amounts reclassified from AOCI, Foreign Currency items - After-Tax	0
Amortization of prior service cost, Foreign Currency items - After-Tax	0
Amortization of net actuarial loss, Foreign Currency items - After-Tax	0
Regulatory adjustment, Foreign Currency items - After-Tax	0
Net current period other comprehensive income (loss), Foreign Currency items - After-Tax	(1,954)
Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency items - After-Tax	(66)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items - After-Tax	(1,888)
Ending Balance AOCI December 31, 2015, Foreign Currency items - After-Tax	(2,525)	(637)
Beginning Balance AOCI December 31, 2014, AOCI	(50,175)
Net actuarial gain (loss)	(18,922)	(107,661)	62,214
Translation adjustments, AOCI	(1,954)
Other comprehensive income before reclassifications, AOCI	(20,876)
Amounts reclassified into net income	2,073	2,073	2,074
Amortization of prior service cost, AOCI	828	220	220
Amortization of net actuarial loss	21,316	14,667	21,190
Regulatory adjustment, AOCI	(3,500)
Total other comprehensive income (loss), net of tax	(159)	(8,499)	$ 9,047
Less: Translation adjustment attributable to redeemable noncontrolling interest, AOCI	(66)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, AOCI	(93)
Ending Balance AOCI December 31, 2015, AOCI	$ (50,268)	$ (50,175)

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Additional Information (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Equity [Abstract]
Amount of FSIRS existing AOCI losses expected to reclassified income in next twelve months	$ 2.1

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Amount Recognized Before Income Tax Associated with Defined Benefit Plans in Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Less: amount recognized in regulatory assets	$ 488,257	$ 578,484
Recognized in AOCI	57,660	57,211
Defined Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net actuarial (loss) gain	(435,269)	(439,131)
Prior service cost	(7,038)	(8,373)
Less: amount recognized in regulatory assets	384,647	390,293
Recognized in AOCI	$ (57,660)	$ (57,211)

XML

Common Stock - Additional Information (Detail) - USD ($)		3 Months Ended	12 Months Ended
	Mar. 10, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Value of common stock	$ 100,000,000
Net proceeds to Company			$ 35,396,000	$ 405,000	$ 1,635,000
Common stock issued through Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan			209,000
BNY Mellon Capital Markets, LLC [Member]
Common stock sold through agent		0	645,225
Net proceeds to Company			$ 35,167,584
Agent commissions			355,228
Common stock available for sale under the program		$ 64,477,188	$ 64,477,188

XML

Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ (816,000)
Long-term Debt, Current and Noncurrent Abstract
Less: current maturities	$ (19,475,000)	(19,192,000)
Long-term debt, less current maturities	1,551,204,000	1,631,374,000
Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	50,000,000	50,000,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Unamortized debt issuance costs	(692,000)	(816,000)
Total long-term debt	1,570,679,000	1,650,566,000
Long-term Debt, Current and Noncurrent Abstract
Less: current maturities	(19,475,000)	(19,192,000)
Long-term debt, less current maturities	1,551,204,000	1,631,374,000
Total long-term debt	1,570,679,000	1,650,566,000
Carrying Amount [Member] | Centuri Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Centuri term loan/secured revolving credit facility	60,627,000	57,196,000
Carrying Amount [Member] | IDRBs [Member]
Debt Instrument [Line Items]
Centuri term loan/secured revolving credit facility	111,879,000	141,255,000
Unsecured debt	320,909,000	370,091,000
Carrying Amount [Member] | Centuri Term Loan Facility [Member]
Debt Instrument [Line Items]
Centuri term loan/secured revolving credit facility	112,571,000	142,071,000
Carrying Amount [Member] | Centuri Other Debt Obligations [Member]
Debt Instrument [Line Items]
Centuri other debt obligations	25,901,000	31,128,000
Carrying Amount [Member] | Debentures [Member]
Debt Instrument [Line Items]
Unamortized discount and debt issuance costs	(6,137,000)	(6,604,000)
Notes payable	901,363,000	900,896,000
Carrying Amount [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Notes payable	125,000,000	125,000,000
Carrying Amount [Member] | Debentures [Member] | Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Notes payable	125,000,000	125,000,000
Carrying Amount [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	250,000,000	250,000,000
Carrying Amount [Member] | Debentures [Member] | Notes, 4.875%, due 2043 [Member]
Debt Instrument [Line Items]
Notes payable	250,000,000	250,000,000
Carrying Amount [Member] | Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Notes payable	75,000,000	75,000,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable	25,000,000	25,000,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	25,000,000	25,000,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable	25,000,000	25,000,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable	7,500,000	7,500,000
Carrying Amount [Member] | Debentures [Member] | Revolving Credit Facility and Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit facility	150,000,000	150,000,000
Carrying Amount [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000,000	50,000,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000,000	50,000,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000,000	50,000,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000,000	50,000,000
Carrying Amount [Member] | Fixed-Rate Bonds [Member]
Debt Instrument [Line Items]
Unamortized discount and debt issuance costs	(3,946,000)	(5,964,000)
Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt		20,000,000
Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Unsecured debt		31,200,000
Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Unsecured debt	100,000,000	100,000,000
Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Unsecured debt	24,855,000	24,855,000
Market Value [Member]
Debt Instrument [Line Items]
Centuri term loan/secured revolving credit facility	112,665,000	143,021,000
Centuri other debt obligations	26,059,000	31,127,000
Market Value [Member] | Centuri Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Centuri term loan/secured revolving credit facility	60,724,000	57,320,000
Market Value [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	130,273,000	133,403,000
Market Value [Member] | Debentures [Member] | Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	141,581,000	157,290,000
Market Value [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	253,600,000	262,030,000
Market Value [Member] | Debentures [Member] | Notes, 4.875%, due 2043 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	251,483,000	280,903,000
Market Value [Member] | Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	97,035,000	102,296,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	26,253,000	27,573,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	29,855,000	31,144,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	31,890,000	33,695,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	8,684,000	9,156,000
Market Value [Member] | Debentures [Member] | Revolving Credit Facility and Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	150,000,000	150,000,000
Market Value [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	50,000,000	50,000,000
Market Value [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	50,000,000	50,000,000
Market Value [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	50,000,000	50,000,000
Market Value [Member] | Fixed-Rate Bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value		20,277,000
Market Value [Member] | Fixed-Rate Bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value		31,223,000
Market Value [Member] | Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	100,452,000	100,071,000
Market Value [Member] | Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Unsecured debt, fair value	$ 25,130,000	$ 25,399,000

XML

Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Parenthetical) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	May. 31, 2015
5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	5.25%
Debt instrument due date	Dec. 01, 2038
5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate				5.00%
Debt instrument due date	Dec. 01, 2033
Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		4.45%	4.45%
Debt instrument due date		Dec. 01, 2020	Dec. 01, 2020
Debentures [Member] | Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		6.10%	6.10%
Debt instrument due date		Feb. 15, 2041	Feb. 15, 2041
Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		3.875%	3.875%
Debt instrument due date		Apr. 01, 2022	Apr. 01, 2022
Debentures [Member] | Notes, 4.875%, due 2043 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		4.875%	4.875%
Debt instrument due date		Oct. 01, 2043	Oct. 01, 2043
Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		8.00%	8.00%
Debt instrument due date		Aug. 01, 2026	Aug. 01, 2026
Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		7.59%	7.59%
Debt instrument due date		Jan. 17, 2017	Jan. 17, 2017
Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		7.78%	7.78%
Debt instrument due date		Feb. 03, 2022	Feb. 03, 2022
Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		7.92%	7.92%
Debt instrument due date		Jun. 04, 2027	Jun. 04, 2027
Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		6.76%	6.76%
Debt instrument due date		Sep. 24, 2027	Sep. 24, 2027
Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument due date		Dec. 01, 2028	Dec. 01, 2028
Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Debt instrument due date		Mar. 01, 2038	Mar. 01, 2038
Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Debt instrument due date		Mar. 01, 2038	Mar. 01, 2038
Variable-rate bonds [Member] | Market Value [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Debt instrument due date		Dec. 01, 2039	Dec. 01, 2039
Fixed-Rate Bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		5.25%	5.25%
Debt instrument due date		Mar. 01, 2038	Mar. 01, 2038
Fixed-Rate Bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		5.00%	5.00%
Debt instrument due date		Dec. 01, 2033	Dec. 01, 2033
Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		4.85%	4.85%
Debt instrument due date		Oct. 01, 2035	Oct. 01, 2035
Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		4.75%	4.75%
Debt instrument due date		Sep. 01, 2036	Sep. 01, 2036

XML

Long-Term Debt - Additional Information (Detail) - USD ($)	1 Months Ended		3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2015	May. 31, 2015	Dec. 31, 2015	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2014
Debt Instrument [Line Items]
Line of credit designated for working capital purposes			$ 150,000,000			$ 150,000,000
Minimum current borrowing usage				$ 0
Maximum current borrowing usage			180,000,000
Redemption of long term debt						$ 187,973,000	$ 139,155,000	$ 137,013,000
Debt instrument covenant description						Certain Company 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, 2015, the Company is in compliance with all of its covenants.
Issuance of additional debt						$ 2,200,000,000
Minimum net worth						1,000,000,000
Long-term debt, less current maturities			1,551,204,000			1,551,204,000	1,631,374,000
Deferred charges and other assets			469,322,000			469,322,000	472,579,000
Prepaids and other current assets			95,199,000			95,199,000	99,803,000
Unamortized debt issuance costs							816,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Long-term debt, less current maturities			1,551,204,000			1,551,204,000	1,631,374,000
Unamortized debt issuance costs			692,000			692,000	816,000
Carrying Amount [Member] | Debentures [Member]
Debt Instrument [Line Items]
Unamortized discount							(5,223,000)
Carrying Amount [Member] | Fixed-Rate Bonds [Member]
Debt Instrument [Line Items]
Unamortized discount							(1,943,000)
Short-Term Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings outstanding under facility			18,000,000			$ 18,000,000	5,000,000
Adjustments for New Accounting Principle, Early Adoption [Member]
Debt Instrument [Line Items]
Long-term debt, less current maturities							1,631,374,000
Deferred charges and other assets							472,579,000
Prepaids and other current assets							$ 99,803,000
Secured Revolving Credit and Term Loan Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity									$ 300,000,000
Effective interest rate						2.46%
Minimum current borrowing usage						$ 60,600,000
Maximum current borrowing usage		$ 105,200,000
Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Commitment fee						0.15%
Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commitment fee						0.40%
Secured Revolving Credit and Term Loan Facility [Member] | LIBOR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin						1.00%
Secured Revolving Credit and Term Loan Facility [Member] | LIBOR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin						2.25%
Secured Revolving Credit and Term Loan Facility [Member] | CDOR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin						1.00%
Secured Revolving Credit and Term Loan Facility [Member] | CDOR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin						2.25%
Secured Revolving Credit and Term Loan Facility [Member] | Alternate Base Rate or Canadian Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin						0.00%
Secured Revolving Credit and Term Loan Facility [Member] | Alternate Base Rate or Canadian Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin						1.25%
Centuri Construction Group Inc [Member]
Debt Instrument [Line Items]
Debt instrument covenant description						Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2015, Centuri is in compliance with all of its covenants.
Issuance of additional debt						$ 75,000,000
Equity cushion relating to minimum fixed charge ratio coverage requirement						15,000,000
Centuri Construction Group Inc [Member] | Secured Revolving Credit and Term Loan Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			300,000,000			$ 300,000,000
Credit facility expiration date						Oct. 31, 2019
Debt secured by assets			437,000,000			$ 437,000,000
Centuri Construction Group Inc [Member] | Centuri Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			150,000,000			150,000,000
Southwest Gas Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			300,000,000			300,000,000
Line of credit designated as long term debt			150,000,000			150,000,000
Line of credit designated for working capital purposes			150,000,000			$ 150,000,000
Credit facility expiration date						Mar. 01, 2020
Borrowings outstanding under facility			$ 150,000,000			$ 150,000,000
Effective interest rate						1.45%
Southwest Gas Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Applicable margin						1.00%
Southwest Gas Credit Facility [Member] | Alternative Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin						0.00%
Southwest Gas Credit Facility [Member] | Before Amendment [Member]
Debt Instrument [Line Items]
Credit facility expiration date						Mar. 01, 2019
5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Redemption of long term debt		$ 31,200,000
Debt instrument interest rate		5.00%
Debt instrument original due date					Dec. 01, 2033
5.00% 2004 Series B, due 2033 [Member] | Fixed-Rate Bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate			5.00%			5.00%	5.00%
Debt instrument original due date						Dec. 01, 2033	Dec. 01, 2033
5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Redemption of long term debt	$ 20,000,000
Debt instrument interest rate	5.25%				5.25%
Debt instrument original due date					Dec. 01, 2038
5.25% 2003 Series D, due 2038 [Member] | Fixed-Rate Bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate			5.25%			5.25%	5.25%
Debt instrument original due date						Mar. 01, 2038	Mar. 01, 2038
Commercial Paper Program [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 50,000,000			$ 50,000,000
Borrowings outstanding under facility			50,000,000			$ 50,000,000
Commercial Paper Program [Member] | Short-Term Credit Facility [Member]
Debt Instrument [Line Items]
Effective interest rate						1.01%
Centuri Term Loan Facility [Member] | Centuri Construction Group Inc [Member]
Debt Instrument [Line Items]
Credit facility, face amount			$ 150,000,000			$ 150,000,000

XML

Long-Term Debt - Summary of Effective Interest Rates on Variable-Rate IDRBs (Detail)	Dec. 31, 2015	Dec. 31, 2014
2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.87%	0.85%
2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.87%	0.90%
2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.75%	0.89%
Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.81%	0.84%

XML

Long-Term Debt - Estimated Maturities of Long-Term Debt (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Debt Disclosure [Abstract]
2016	$ 19,475
2017	42,245
2018	14,906
2019	142,452
2020	$ 275,238

XML

Short-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Line of credit designated for working capital purposes	$ 150,000
Short-term borrowings outstanding on the credit facility	$ 18,000	$ 5,000
Effective interest rate on short-term borrowings	1.37%
March 2019 [Member]
Short-term Debt [Line Items]
Current borrowing capacity	$ 300,000
Credit facility expiration date	Mar. 01, 2020

XML

Commitments and Contingencies - Additional Information (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Self-insured retention amount associated with general liability claims	$ 1
Additional self-insured retention amount of general liability	$ 4

XML

Pension and Other Postretirement Benefits - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) BasisPoint
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Maximum contribution of employer	3.50%
Deferment of annual cash compensation	100.00%
Matching contribution of employer	3.50%
Deferred compensation payments on retirement	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.
Additional Deferred Compensation Payment Options, period of payment, years	5 years
Deferred compensation, percentage of multiple interest rate	150.00%
Increments of changes to the discount rate, basis points | BasisPoint	25
Estimated decrease in pension expense	$ 6.7
Future estimated funding amount	39.0
Future estimated funding amount of retirement plan	$ 36.0
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	7.50%
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	4.50%

XML

Pension and Other Postretirement Benefits - Cost of Retirement Plan (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Employee Investment Plan cost	$ 5,072	$ 4,816	$ 4,850

XML

Pension and Other Postretirement Benefits - Schedule of Allocation of Plan Assets (Detail)	12 Months Ended
	Dec. 31, 2015
Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Investment percentage range, minimum	59.00%
Investment percentage range, maximum	71.00%
Debt Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Investment percentage range, minimum	31.00%
Investment percentage range, maximum	37.00%
Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Investment percentage range, maximum	5.00%

XML

Pension and Other Postretirement Benefits - Schedule of Assumptions Used (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Discount rate	4.50%	4.25%
Weighted-average rate of compensation increase	3.25%	2.75%
Asset return assumption	7.25%	7.75%

XML

Pension and Other Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet and Income Statement (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Qualified Retirement Plan [Member]
Change in benefit obligations
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$ 1,060,240	$ 886,714
Service cost	25,123	21,360	$ 23,056
Interest cost	44,229	43,440	37,607
Net actuarial loss (gain)	(44,553)	144,606
Benefits paid	(40,222)	(35,880)
Benefit obligation at end of year (PBO/PBO/APBO)	1,044,817	1,060,240	886,714
Change in plan assets
Market value of plan assets, beginning balance	754,796	719,944
Actual return on plan assets	(13,694)	34,732
Employer contributions	36,000	36,000
Benefits paid	(40,222)	(35,880)
Market value of plan assets, ending balance	736,880	754,796	719,944
Funded status at year end	$ (307,937)	$ (305,444)
Weighted-average assumptions (benefit obligation)
Discount rate	4.50%	4.25%
Weighted-average rate of compensation increase	3.25%	2.75%
SERP [Member]
Change in benefit obligations
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$ 41,176	$ 36,143
Service cost	320	292	373
Interest cost	1,695	1,745	1,535
Net actuarial loss (gain)	2,322	5,459
Benefits paid	(2,793)	(2,463)
Benefit obligation at end of year (PBO/PBO/APBO)	42,720	41,176	36,143
Change in plan assets
Employer contributions	2,793	2,463
Benefits paid	(2,793)	(2,463)
Funded status at year end	$ (42,720)	$ (41,176)
Weighted-average assumptions (benefit obligation)
Discount rate	4.50%	4.25%
Weighted-average rate of compensation increase	3.25%	2.75%
PBOP [Member]
Change in benefit obligations
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$ 72,202	$ 58,020
Service cost	1,641	1,101	1,220
Interest cost	2,999	2,829	2,482
Plan amendments		6,661
Net actuarial loss (gain)	(3,251)	4,567
Benefits paid	(959)	(976)
Benefit obligation at end of year (PBO/PBO/APBO)	72,632	72,202	58,020
Change in plan assets
Market value of plan assets, beginning balance	44,892	42,314
Actual return on plan assets	(1,034)	2,859
Benefits paid	(274)	(281)
Market value of plan assets, ending balance	43,584	44,892	$ 42,314
Funded status at year end	$ (29,048)	$ (27,310)
Weighted-average assumptions (benefit obligation)
Discount rate	4.50%	4.25%

XML

Pension and Other Postretirement Benefits - Schedule of Accumulated Benefit Obligation (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 922,992	$ 886,215
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 39,270	$ 39,125

XML

Pension and Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) $ in Millions	Dec. 31, 2015 USD ($)
Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	$ 44.0
2017	45.5
2018	47.2
2019	48.9
2020	50.5
2021-2025	283.5
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	3.9
2017	4.1
2018	4.3
2019	4.5
2020	4.5
2021-2025	21.3
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2016	2.8
2017	2.8
2018	2.8
2019	2.9
2020	2.9
2021-2025	$ 14.1

XML

Pension and Other Postretirement Benefits - Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 50,451	$ 38,172	$ 48,141
Weighted-average assumptions (net benefit cost)
Discount rate	4.50%	4.25%
Expected return on plan assets	7.25%	7.75%
Weighted-average rate of compensation increase	3.25%	2.75%
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 25,123	$ 21,360	23,056
Interest cost	44,229	43,440	37,607
Expected return on plan assets	(57,808)	(53,342)	(49,840)
Amortization of net actuarial loss	32,743	22,873	32,261
Net periodic benefit cost	$ 44,287	$ 34,331	$ 43,084
Weighted-average assumptions (net benefit cost)
Discount rate	4.25%	5.00%	4.25%
Expected return on plan assets	7.75%	7.75%	8.00%
Weighted-average rate of compensation increase	2.75%	3.25%	2.75%
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 320	$ 292	$ 373
Interest cost	1,695	1,745	1,535
Amortization of net actuarial loss	1,293	783	971
Net periodic benefit cost	$ 3,308	$ 2,820	$ 2,879
Weighted-average assumptions (net benefit cost)
Discount rate	4.25%	5.00%	4.25%
Expected return on plan assets	7.75%	7.75%	8.00%
Weighted-average rate of compensation increase	2.75%	3.25%	2.75%
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1,641	$ 1,101	$ 1,220
Interest cost	2,999	2,829	2,482
Expected return on plan assets	(3,464)	(3,264)	(2,824)
Amortization of prior service cost	1,335	355	355
Amortization of net actuarial loss	345		945
Net periodic benefit cost	$ 2,856	$ 1,021	$ 2,178
Weighted-average assumptions (net benefit cost)
Discount rate	4.25%	5.00%	4.25%
Expected return on plan assets	7.75%	7.75%	8.00%

XML

Pension and Other Postretirement Benefits - Schedule of Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	$ 30,519	$ 173,646	$ (100,345)
Amortization of prior service cost	(1,335)	(355)	(355)
Amortization of net actuarial loss	(34,381)	(23,656)	(34,177)
Prior service cost	0	6,661	0
Regulatory adjustment	5,646	(140,308)	123,630
Recognized in other comprehensive (income) loss	449	15,988	(11,247)
Net periodic benefit costs recognized in net income	50,451	38,172	48,141
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	50,900	54,160	36,894
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	26,949	163,215	(91,115)
Amortization of net actuarial loss	(32,743)	(22,872)	(32,261)
Regulatory adjustment	5,214	(129,031)	113,762
Recognized in other comprehensive (income) loss	(580)	11,312	(9,614)
Net periodic benefit costs recognized in net income	44,287	34,331	43,084
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	43,707	45,643	33,470
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	2,322	5,460	(662)
Amortization of net actuarial loss	(1,293)	(784)	(971)
Recognized in other comprehensive (income) loss	1,029	4,676	(1,633)
Net periodic benefit costs recognized in net income	3,308	2,820	2,879
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	4,337	7,496	1,246
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	1,248	4,971	(8,568)
Amortization of prior service cost	(1,335)	(355)	(355)
Amortization of net actuarial loss	(345)		(945)
Prior service cost		6,661
Regulatory adjustment	432	(11,277)	9,868
Net periodic benefit costs recognized in net income	2,856	1,021	2,178
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$ 2,856	$ 1,021	$ 2,178

XML

Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, including insurance contracts	$ 783,323	$ 808,260
Assets at Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	521,638	537,335
Commingled Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	257,966	266,922
Insurance Company General Account Contracts (Member]
Defined Benefit Plan Disclosure [Line Items]
Contract value of insurance contracts	3,719	4,003
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	364,610	386,712
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,230	6,859
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	549	2,288
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,402	5,388
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	42,256	42,969
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11,395	19,051
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,849	21,298
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39,059	38,968
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,099	26,648
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,708	29,701
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26,653	19,047
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,312	11,283
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,159	5,882
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	111,468	110,726
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,478	46,019
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		585
Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Futures Contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(7)
Level 2 - Significant Other Observable Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	157,028	150,623
Level 2 - Significant Other Observable Inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,917	23,806
Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,007
Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	571
Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	51,046	49,745
Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24,243	27,874
Level 2 - Significant Other Observable Inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	21,478	23,980
Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,042	6,365
Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,940	4,358
Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	15,604	12,952
Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	978	1,543
Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	202
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	736,880	754,796	$ 719,944
Fair value of plan assets, including insurance contracts	739,684	763,108
Qualified Retirement Plan [Member] | Assets at Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	485,454	499,870
Qualified Retirement Plan [Member] | Commingled Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	250,511	259,235
Qualified Retirement Plan [Member] | Insurance Company General Account Contracts (Member]
Defined Benefit Plan Disclosure [Line Items]
Contract value of insurance contracts	3,719	4,003
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	333,310	354,197
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,021	6,661
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	533	2,222
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,304	5,233
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	41,035	41,731
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	11,066	18,502
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29,957	20,685
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	37,930	37,846
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29,229	25,881
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,341	28,846
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	25,883	18,498
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,043	10,958
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,010	5,713
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	87,483	86,159
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	33,482	44,694
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		568
Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Futures Contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	(7)
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	152,144	145,673
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,995	23,120
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,949
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	554
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	49,571	48,312
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	23,542	27,071
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,857	23,289
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,896	6,182
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,826	4,232
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	14,808	11,968
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	950	1,499
Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	196
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	43,584	44,892	$ 42,314
Fair value of plan assets, including insurance contracts	43,639	45,152
PBOP [Member] | Assets at Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	36,184	37,465
PBOP [Member] | Commingled Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,455	7,687
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,300	32,515
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	209	198
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16	66
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	155
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,221	1,238
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	329	549
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	892	613
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,129	1,122
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	870	767
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	367	855
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	770	549
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	269	325
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	149	169
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	23,985	24,567
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	996	1,325
PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		17
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,884	4,950
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	922	686
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	58
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,475	1,433
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	701	803
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	621	691
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	146	183
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	114	126
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	796	984
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	$ 44
PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 6

XML

Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	$ 2,859,000	$ 8,572,000
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	2,803,000	8,312,000
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	$ 56,000	$ 260,000
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notice period	1 day
Impact fee on redemptions and subscriptions of $5 million or more	$ 5,000,000
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notice period		30 days

XML

Stock-Based Compensation - Schedule of Stock-Based Plan Compensation Expense, Including Cash Award (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation plan expense, net of related tax benefits	$ 7,278	$ 8,130	$ 8,012
Stock-based compensation plan related tax benefits	$ 4,461	$ 4,983	$ 4,910

XML

Stock-Based Compensation - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 $ / shares	Dec. 31, 2013 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, maximum term, years	10 years
Cash received from exercise of stock options	$ 523,000
Tax benefit realized from exercise of stock options	$ 218,000
Percentage of restricted stock/units vested during first year	0.40
Percentage of restricted stock/units vested during second and third years	0.30
Average grant date fair value of performance shares and restricted stock/units granted | $ / shares		$ 53.73	$ 44.83
Total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized	$ 3,300,000
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average remaining contractual life of outstanding options, years	1 year

XML

Stock-Based Compensation - Schedule of Stock Options Activity (Detail) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of options, Outstanding at the beginning of the year	36	52	125
Number of options, Exercised during the year	(19)	(16)	(72)
Number of options, Forfeited or expired during the year			(1)
Number of options, Outstanding and exercisable at year end	17	36	52
Weighted-average exercise price, Outstanding at the beginning of the year	$ 28.97	$ 27.57	$ 28.13
Weighted-average exercise price, Exercised during the year	26.69	24.31	28.44
Weighted-average exercise price, Forfeited or expired during the year			33.07
Weighted-average exercise price, Outstanding and exercisable at year end	$ 31.64	$ 28.97	$ 27.57

XML

Stock-Based Compensation - Schedule of Aggregate Intrinsic Value of Outstanding and Exercisable Options (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Outstanding and exercisable	$ 394	$ 1,194	$ 1,473
Exercised	$ 590	$ 451	$ 1,402

XML

Stock-Based Compensation - Summary of Market Prices of Common Stock (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Market value of Southwest Gas stock	$ 55.16	$ 61.81	$ 55.91

XML

Stock-Based Compensation - Schedule of Stock Options Outstanding and Exercisable (Detail) - $29.08 to $33.07 [Member] shares in Thousands	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Price, Lower limit	$ 29.08
Range of Exercise Price, Upper limit	$ 33.07
Number outstanding | shares	17
Weighted-remaining average contractual life, years	6 months
Weighted-average exercise price	$ 31.64

XML

Stock-Based Compensation - Schedule of Nonvested Performance and Restricted Stock Unit Plans (Detail) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant date fair value, Granted		$ 53.73	$ 44.83
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested/unissued, Number of Units, at beginning of year	271
Nonvested, Number of Units, Granted	80
Nonvested, Number of Units, Dividends	6
Nonvested, Number of Units, Forfeited or expired	0
Nonvested, Number of Units, Vested and issued	(160)
Nonvested/unissued, Number of Units, Ending balance	197	271
Weighted-average grant date fair value, Beginning balance	$ 43.71
Weighted-average grant date fair value, Granted	63.09
Weighted-average grant date fair value, Dividends	0
Weighted-average grant date fair value, Forfeited or expired	0
Weighted-average grant date fair value, Vested and issued	43.12
Weighted-average grant date fair value, Ending balance	$ 50.63	$ 43.71
Restricted Stock/Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested/unissued, Number of Units, at beginning of year	257
Nonvested, Number of Units, Granted	73
Nonvested, Number of Units, Dividends	7
Nonvested, Number of Units, Forfeited or expired	0
Nonvested, Number of Units, Vested and issued	(109)
Nonvested/unissued, Number of Units, Ending balance	228	257
Weighted-average grant date fair value, Beginning balance	$ 41.22
Weighted-average grant date fair value, Granted	63.09
Weighted-average grant date fair value, Dividends	0
Weighted-average grant date fair value, Forfeited or expired	0
Weighted-average grant date fair value, Vested and issued	46.65
Weighted-average grant date fair value, Ending balance	$ 44.36	$ 41.22

XML

Income Taxes - Summary of Income Before Taxes and Noncontrolling Interest for Domestic and Foreign Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax [Line Items]
Total income before income taxes	$ 219,332	$ 219,521	$ 222,815
Foreign [Member]
Income Tax [Line Items]
Total income before income taxes	(2,328)	(1,950)
United States [Member]
Income Tax [Line Items]
Total income before income taxes	$ 221,660	$ 221,471	$ 222,815

XML

Income Taxes - Summary of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 21,321	$ 1,739	$ 3,549
State	9,899	5,073	5,107
Foreign	650	2,193
Income tax expense (benefit), Current	31,870	9,005	8,656
Deferred:
Federal	51,132	71,439	67,414
State	(2,574)	614	1,872
Foreign	(526)	(2,685)
Total deferred income tax expense	48,032	69,368	69,286
Total income tax expense	$ 79,902	$ 78,373	$ 77,942

XML

Income Taxes - Significant Components of Deferred Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred federal and state:
Total deferred federal and state	$ 48,893	$ 70,229	$ 70,147
Deferred ITC, net	(861)	(861)	(861)
Total deferred income tax expense	48,032	69,368	69,286
Property-related Items [Member]
Deferred federal and state:
Total deferred federal and state	65,931	52,814	62,737
Purchased Gas Cost Adjustments [Member]
Deferred federal and state:
Total deferred federal and state	(32,993)	15,049	16,189
Employee Benefits [Member]
Deferred federal and state:
Total deferred federal and state	623	109	(2,769)
All Other Deferred [Member]
Deferred federal and state:
Total deferred federal and state	$ 15,332	$ 2,257	$ (6,010)

XML

Income Taxes - Reconciliation of U.S Federal Statutory Rate to Consolidated Effective Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
U.S. federal statutory income tax rate	35.00%	35.00%	35.00%
Net state taxes	1.80%	1.90%	2.40%
Property-related items	0.10%	0.10%	0.10%
Tax credits	(0.40%)	(0.50%)	(0.40%)
Company owned life insurance	0.10%	(1.00%)	(2.10%)
All other differences	(0.20%)	0.20%
Consolidated effective income tax rate	36.40%	35.70%	35.00%

XML

Income Taxes - Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$ 1,614	$ 2,146
Employee benefits	36,923	31,557
Alternative minimum tax credit	4,809	20,172
Net operating losses and credits	868	9,719
Interest rate swap	7,351	8,622
Other	24,636	25,872
Valuation allowance	(499)	(253)
Deferred tax assets, total	75,702	97,835
Deferred tax liabilities:
Property-related items, including accelerated depreciation	794,850	736,810
Regulatory balancing accounts	743	33,736
Unamortized ITC	2,549	3,410
Debt-related costs	5,497	5,066
Intangibles	9,547	12,792
Other	31,533	27,600
Deferred tax liabilities, total	844,719	819,414
Net deferred tax liabilities	769,017	721,579
Current		(2,109)
Noncurrent	769,017	723,688
Net deferred tax liabilities	$ 769,017	$ 721,579

XML

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Line Items]
Undistributed foreign earnings	$ 0
Unrecognized tax benefits that, if recognized, would affect the effective tax rate	0
Significant increases or decreases in unrecognized tax benefit within the next 12 months	0
Tax-related interest income	$ 0	$ 0	$ 0
Minimum [Member]
Income Tax Disclosure [Line Items]
Amount of benefit being recognized in financial statements upon ultimate settlement, Percentage	50.00%
United States [Member]
Income Tax Disclosure [Line Items]
Federal net capital loss carryforward	$ 505,000
Net capital loss carryforward expiration year	2016
Canada [Member]
Income Tax Disclosure [Line Items]
Federal net operating loss carryforward	$ 3,000,000
Net operating loss carryforward expiration year	2032

XML

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Unrecognized tax benefits at beginning of year	$ 305
Gross increases - tax positions in prior period		$ 305
Gross decreases - tax positions in prior period	(9)
Gross increases - current period tax positions	0	0
Gross decreases - current period tax positions	0	0
Settlements	0	0
Lapse in statute of limitations	0	0
Unrecognized tax benefits at end of year	$ 296	$ 305

XML

Derivatives and Fair Value Measurements - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gains (losses) recognized in income or other comprehensive income for derivative designated cash flow hedges	$ 2,073,000	$ 2,073,000	$ 2,074,000
Derivative instrument loss at settlement amortization period	10 years
Cash Flow Hedging [Member]
Derivative [Line Items]
Gains (losses) recognized in income or other comprehensive income for derivative designated cash flow hedges	$ 0
Minimum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	Jan. 31, 2016
Maximum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	Mar. 31, 2018
Arizona [Member]
Derivative [Line Items]
Natural gas portfolios, maximum % rate	25.00%
California [Member]
Derivative [Line Items]
Natural gas portfolios, maximum % rate	25.00%

XML

Derivatives and Fair Value Measurements - Notional Amounts under Swaps Contracts (Detail) - MMBTU	Dec. 31, 2015	Dec. 31, 2014
Offsetting [Abstract]
Contract notional amounts	7,407,000	5,105,000

XML

Derivatives and Fair Value Measurements - Amount of Gain or Losses Recognized in Income on Derivatives (Detail) - Cash Flow Hedging [Member] - Net Cost of Gas Sold [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$ (7,598)	$ (2,363)	$ 976
Regulatory Deferral Accounting Treatment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$ 7,598	$ 2,363	$ (976)

XML

Derivatives and Fair Value Measurements - Fair Values of Swaps in Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	$ 4
Liability derivatives not designated as hedging instruments	(5,490)	$ (5,425)
Net total not designated as hedging instruments	(5,486)	(5,425)
Swaps [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives not designated as hedging instruments	(4,267)	(5,062)
Net total not designated as hedging instruments	(4,267)	(5,062)
Swaps [Member] | Other Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	4
Liability derivatives not designated as hedging instruments	(1,223)	(363)
Net total not designated as hedging instruments	$ (1,219)	$ (363)

XML

Derivatives and Fair Value Measurements - Paid to and Received from Counterparties for Settlements of Matured Swaps (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Paid to counterparties	$ 7,537	$ 829	$ 3,148
Received from counterparties		$ 4,713	$ 915

XML

Derivatives and Fair Value Measurements - Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Condensed Consolidated Balance Sheets (Detail) - Swaps [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Prepaids and Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ 4,267	$ 5,062
Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ 1,219	$ 363

XML

Derivatives and Fair Value Measurements - Significant Other Observable Inputs (Detail) - Level 2 - Significant Other Observable Inputs [Member] - Swaps [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Net Assets (Liabilities)	$ (5,486)	$ (5,425)
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	(4,267)	(5,062)
Other Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	$ (1,219)	$ (363)

XML

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Long-lived assets	Over 99% of the total Company’s long-lived assets are in the United States.

XML

Segment Information - Accounts Receivable for Services (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Centuri Construction Group Inc [Member]
Segment Reporting Information [Line Items]
Accounts receivable for Centuri services	$ 10,006	$ 9,169

XML

Segment Information - Schedule of Revenues and Long-Lived Assets by Geographic Area (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total Revenues	$ 685,405	$ 505,396	$ 538,604	$ 734,220	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 2,463,625	$ 2,121,707	$ 1,950,782
United States [Member]
Segment Reporting Information [Line Items]
Total Revenues													2,289,133	2,069,513
Canada [Member]
Segment Reporting Information [Line Items]
Total Revenues													$ 174,492	$ 52,194

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Segment Information - Schedule of Segment Reporting Information (Detail) - USD ($) $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total operating revenues	$ 685,405	$ 505,396	$ 538,604	$ 734,220	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 2,463,625	$ 2,121,707	$ 1,950,782
Interest revenue													2,173	2,602	461
Interest expense													71,879	72,069	63,700
Depreciation and amortization													270,111	253,027	236,817
Income tax expense													79,902	78,373	77,942
Segment net income	66,119	$ (4,734)	$ 4,949	$ 71,983	58,746	$ 1,970	$ 9,627	$ 70,783	57,303	$ (2,864)	$ 10,108	$ 80,773	138,317	141,126	145,320
Segment assets	5,358,685				5,208,297				4,565,174				5,358,685	5,208,297	4,565,174
Capital expenditures													488,000	396,898	364,276
Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													2,359,509	2,029,519	1,862,629
Intersegment sales [Member]
Segment Reporting Information [Line Items]
Revenues													104,116	92,188	88,153
Natural Gas Operations [Member]
Segment Reporting Information [Line Items]
Total operating revenues													1,454,639	1,382,087	1,300,154
Interest revenue													1,754	2,596	456
Interest expense													64,095	68,299	62,555
Depreciation and amortization													213,455	204,144	193,848
Income tax expense													61,355	63,597	65,377
Segment net income													111,625	116,872	124,169
Segment assets	4,822,845				4,652,307				4,272,029				4,822,845	4,652,307	4,272,029
Capital expenditures													438,289	350,025	314,578
Natural Gas Operations [Member] | Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													1,454,639	1,382,087	1,300,154
Construction Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues													1,008,986	739,620	650,628
Interest revenue													419	6	5
Interest expense													7,784	3,770	1,145
Depreciation and amortization													56,656	48,883	42,969
Income tax expense													18,547	14,776	12,565
Segment net income													26,692	24,254	21,151
Segment assets	$ 535,840				566,589				293,811				535,840	566,589	293,811
Capital expenditures													49,711	46,873	49,698
Construction Services [Member] | Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													904,870	647,432	562,475
Construction Services [Member] | Intersegment sales [Member]
Segment Reporting Information [Line Items]
Revenues													$ 104,116	92,188	88,153
Adjustments [Member]
Segment Reporting Information [Line Items]
Segment assets					$ (10,599)				$ (666)					$ (10,599)	$ (666)

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Segment Information - Schedule of Segment Reporting Information (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Income tax payable netted			$ 666,000
Long-term deferred tax benefit	$ 48,032,000	$ 69,368,000	$ 69,286,000
Natural Gas Operations [Member]
Segment Reporting Information [Line Items]
Deferred income tax liability		4,500,000
Construction Services [Member]
Segment Reporting Information [Line Items]
Income tax payable netted		3,300,000
Deferred income tax liability		1,400,000
Long-term deferred tax benefit		$ 1,400,000

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Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 685,405	$ 505,396	$ 538,604	$ 734,220	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 2,463,625	$ 2,121,707	$ 1,950,782
Operating income	117,586	16,143	25,047	129,556	112,373	18,290	26,755	127,065	100,772	6,141	28,908	138,394	288,332	284,483	274,215
Net income (loss)	66,698	(4,210)	5,063	71,879	58,897	1,927	9,627	70,697	57,189	(3,057)	10,067	80,674	139,430	141,148	144,873
Net income (loss) attributable to Southwest Gas Corporation	$ 66,119	$ (4,734)	$ 4,949	$ 71,983	$ 58,746	$ 1,970	$ 9,627	$ 70,783	$ 57,303	$ (2,864)	$ 10,108	$ 80,773	$ 138,317	$ 141,126	$ 145,320
Basic earnings (loss) per common share	$ 1.40	$ (0.10)	$ 0.11	$ 1.54	$ 1.26	$ 0.04	$ 0.21	$ 1.52	$ 1.24	$ (0.06)	$ 0.22	$ 1.75	$ 2.94	$ 3.04	$ 3.14
Diluted earnings (loss) per common share	$ 1.38	$ (0.10)	$ 0.10	$ 1.53	$ 1.25	$ 0.04	$ 0.21	$ 1.51	$ 1.22	$ (0.06)	$ 0.22	$ 1.73	$ 2.92	$ 3.01	$ 3.11

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Construction Services Noncontrolling Interests - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Oct. 31, 2014	Dec. 31, 2015
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member]
Noncontrolling Interest [Line Items]
Equity interest percentage	10.00%
Description of equity interest		The agreement, associated with that approximate 10% equity interest, provided 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 has 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 that original agreement. No new rights were conveyed to the noncontrolling parties as a result of the exchange and no new consideration was involved. The ability of the sellers to redeem their holdings for cash at specified dates remains intact. The previous owners may exit their investment retained by requiring the purchase of a portion of their interest commencing July 2017 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election beginning in July 2022.
Equity interest dividend rights, percentage of dividends paid by Centuri	3.40%
First redemption date to exchange holdings for cash		2017-07
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Construction Services [Member]
Noncontrolling Interest [Line Items]
Equity interest exchangeable percentage in Centuri	3.40%
Percentage of earnings attribution by Centuri to previous owners	3.40%
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Construction Services [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Percentage of retained interest may elect to sell to centuri		100.00%
Intellichoice Energy, LLC [Member]
Noncontrolling Interest [Line Items]
Subsidiaries holding interest percentage		65.00%

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Construction Services Noncontrolling Interests - Summary of Redeemable Noncontrolling Interest (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Redeemable Noncontrolling Interest [Line Items]
Balance, December 31, 2014	$ 20,042
Balance, December 31, 2015	16,108	$ 20,042
Redeemable Noncontrolling Interest (Temporary Equity) [Member]
Redeemable Noncontrolling Interest [Line Items]
Balance, December 31, 2014	20,042
Net Income (loss) attributable to redeemable noncontrolling interest	939	151
Foreign currency exchange translation adjustment	(66)	(22)
Centuri distribution to redeemable noncontrolling interest	(99)
Adjustment to redemption value	(4,708)
Balance, December 31, 2015	$ 16,108	$ 20,042

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Acquisition of Construction Services Businesses - Additional Information (Detail)	1 Months Ended	12 Months Ended
	Oct. 31, 2014 USD ($) Business	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Number of business acquisitions | Business	3
Business acquisition cost		$ 0	$ 5,000,000
Secured Revolving Credit and Term Loan Facility [Member]
Business Acquisition [Line Items]
Credit facility maximum borrowing capacity	$ 300,000,000

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Acquisition of Construction Services Businesses - Revised Fair Values of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Goodwill	$ 126,145		$ 143,160
Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Acquisition [Line Items]
Cash, cash equivalents, and restricted cash		$ 3,000
Contracts receivable and other receivables		62,000
Property, plant and equipment		17,000
Other assets		15,000
Intangible assets		52,000
Goodwill		131,000
Total assets acquired		280,000
Current liabilities		40,000
Deferred income tax - long-term		17,000
Other long-term liabilities		4,000
Net assets acquired		219,000
Link-Line, W.S. Nicholls, and Brigadier [Member] | Acquisition Date [Member]
Business Acquisition [Line Items]
Cash, cash equivalents, and restricted cash		3,000
Contracts receivable and other receivables		62,000
Property, plant and equipment		17,000
Other assets		17,000
Intangible assets		52,000
Goodwill		130,000
Total assets acquired		281,000
Current liabilities		39,000
Deferred income tax - long-term		17,000
Other long-term liabilities		4,000
Net assets acquired		221,000
Link-Line, W.S. Nicholls, and Brigadier [Member] | Measurement Period Adjustments [Member]
Business Acquisition [Line Items]
Cash, cash equivalents, and restricted cash		0
Contracts receivable and other receivables		0
Property, plant and equipment		0
Other assets		(2,000)
Intangible assets		0
Goodwill		1,000
Total assets acquired		(1,000)
Current liabilities		1,000
Deferred income tax - long-term		0
Other long-term liabilities		0
Net assets acquired		$ (2,000)

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Acquisition of Construction Services Businesses - Schedule of Unaudited Pro Forma Consolidated Financial Information (Detail) - Link-Line, W.S. Nicholls, and Brigadier [Member] $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($) $ / shares
Business Acquisition [Line Items]
Total operating revenues | $	$ 2,295,318
Net income attributable to Southwest Gas Corporation | $	$ 149,588
Basic earnings per share | $ / shares	$ 3.22
Diluted earnings per share | $ / shares	$ 3.19