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, 2014

Commission File Number 1-7850

SOUTHWEST GAS CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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:

$2,454,899,230 as of June 30, 2014

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 46,637,647 shares as of February 17, 2015

DOCUMENTS INCORPORATED BY REFERENCE

Description	Part Into Which Incorporated
Annual Report to Shareholders for the Year Ended December 31, 2014 2015 Proxy Statement	Parts I, II, and IV Part III

TABLE OF CONTENTS

PART I		1
Item 1.	BUSINESS	1
	NATURAL GAS OPERATIONS	2
	General Description	2
	Rates and Regulation	2
	Demand for Natural Gas	3
	Natural Gas Supply	4
	Competition	5
	Environmental Matters	6
	Employees	7
	CONSTRUCTION SERVICES	7
Item 1A.	RISK FACTORS	8
Item 1B.	UNRESOLVED STAFF COMMENTS	12
Item 2.	PROPERTIES	12
Item 3.	LEGAL PROCEEDINGS	12
Item 4.	MINE SAFETY DISCLOSURES	12
Item 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	13
PART II		13
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	13
Item 6.	SELECTED FINANCIAL DATA	13
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	13
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	14
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	14
Item 9A.	CONTROLS AND PROCEDURES	14
Item 9B.	OTHER INFORMATION	15
PART III		15
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	15
Item 11.	EXECUTIVE COMPENSATION	17
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	17
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	19
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	19
PART IV		19
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	19
	LIST OF EXHIBITS	20
SIGNATURES		24

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.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co. (“NPL”), completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. The acquisition extends the construction services operations into Canada and provides additional opportunities for market expansion. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”) that provides construction and maintenance services for the Canadian utility industry, with operations primarily in Ontario, Canada; (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating in the North Eastern portion of the United States as a specialty midstream pipeline contractor (“Brigadier”). Centuri Construction Group Inc. (“Centuri”), through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company.

In October 2014, coincident with the acquisition, the Company restructured its ownership of NPL and Carson Water Company (an inactive wholly owned subsidiary) creating a holding company, a direct subsidiary of Carson Water Company. In January 2015, the holding company was renamed Centuri. Two direct holding companies exist under Centuri: Vistus Construction Group Inc. (“Vistus”, U.S. operations) and Lynxus Construction Group Inc. (“Lynxus”, Canadian operations). Three subsidiaries exist under Vistus: NPL, Southwest Administrators, and Brigadier. Link-Line and W.S. Nicholls are subsidiaries of Lynxus. Previous owners of the acquired companies retained an approximate 10% stock ownership interest in Lynxus. However, their underlying equity agreements include dividend participation rights equal to 3.4% of dividends declared at the level of Centuri. Additionally, these same agreements include, among other terms, the ability of the prior owners to exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021. Furthermore, the equity agreements include an exchange feature such that the interest retained in Lynxus may be convertible into shares equivalent to a 3.4% interest in Centuri. Additional discussion is included in Notes 15 and 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Report to Shareholders, which is incorporated herein by reference. References to Centuri below fully encompass activities and impacts from any of the businesses that are included in the Centuri organization structure. References to “construction services” will also mean the activities, individually or in the aggregate, in the Centuri organization structure. Centuri, a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and develops industrial construction solutions.

Financial information concerning the Company’s business segments is included in Note 13 of the Notes to Consolidated Financial Statements, which is included in the 2014 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.

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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, 2014, Southwest purchased and distributed or transported natural gas to 1,930,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. Southwest added 26,000 net new customers during 2014. Southwest expects similar customer growth in 2015.

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, 2014		85	%		4	%		11	%
December 31, 2013		85	%		4	%		11	%
December 31, 2012		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 47% of total system throughput in 2014. Customers who utilized this service transported 91 million dekatherms in 2014, 104 million dekatherms in 2013, and 100 million dekatherms in 2012. Although these volumes are significant, these customers provided a much smaller proportionate share of operating margin.

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

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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 2014 Annual Report to Shareholders.

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 2014	January 2015
Northern and Southern	General rate case	December 2012	June 2014
Nevada:
Northern and Southern	General rate case	April 2012	November 2012
FERC:
Paiute	General rate case	February 2014	February 2015
Paiute	General rate case	February 2009	April 2010

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 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. 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.

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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 2014, Southwest acquired natural gas from 46 suppliers. Southwest regularly monitors the number of suppliers, their performance, and their relative contribution to the overall customer supply 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 participation by suppliers who have 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.

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 (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) 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 further fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada territories. The Nevada VMP suspension is forward looking and did not impact Nevada VMP purchase transactions that occurred prior to the suspension (for delivery up to and including March 2015). 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 the 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 2014/2015 heating season, fixed-price purchases ranged from approximately $4 to $5 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 not known until the month or day of purchase.

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.

4

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 has received preapproval 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 connected directly to its distribution system. Construction is expected to be complete within approximately 24 to 30 months from the date of approval.

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.

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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.

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 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 its 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. Of those allowances, Southwest must consign 25% into quarterly allowance auctions and the remaining allowances can be used to meet the triennial compliance obligation to cover the quantity of GHG emissions that occur during each triennial compliance period. The amount Southwest must consign increases by 5% annually. Given those levels of consignment, Southwest must also purchase allowances to meet its triennial compliance period obligations. Those purchases can be made through auctions or reserve sales that are hosted by the CARB, or through over the counter (“OTC”) purchases with other market participants. In addition to allowances, Southwest can purchase up to 8% of its annual GHG emissions with 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.

By September of each year, Southwest must inform the CARB of the percentage of Southwest’s annual allocation that are to be placed in Southwest’s Limited Use Holding Account (“LUHA”) for consignment to the quarterly auctions. In August 2014, Southwest filed the necessary paperwork with the CARB to place 25% of the allocated allowances in the LUHA. In December 2014, Southwest applied to participate in the quarterly auction to be held in February 2015 the results of which are still pending. Program costs or credits received are expected to receive regulatory treatment and not have an impact to earnings.

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Employees

At December 31, 2014, the natural gas operations segment had 2,196 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 (consisting of NPL and the October 2014 acquired companies of Link-Line, W.S. Nicholls, and Brigadier) 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 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 Pipeline and Hazardous Materials Safety Administration 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 provided for by the Small Jobs Act of 2010 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010. The American Tax Payer Relief Act of 2012 extended 50% bonus depreciation deduction tax incentives for 2013. The Tax Increase Prevention Act of 2014 extended 50% bonus depreciation deduction tax incentives for 2014. 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 2014, approximately 88% of revenue was earned under unit-price contracts. As of December 31, 2014, a backlog of approximately $46.2 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 minimal 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 2014, Centuri served over 100 customers, with Southwest accounting for approximately 12% of total revenues. Additionally, two customers 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, 2014, Centuri had 4,036 regular full-time equivalent employees. Employment peaked in October 2014 when there were 4,911 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.

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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 consolidates Lynxus, for accounting purposes, (including its wholly owned subsidiaries) as a majority owned subsidiary. Western is a variable interest entity, for which the Company is not the primary beneficiary, that specializes in construction of underground aviation fueling systems and storage tanks. 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 operating results.

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. We received regulatory approval of a settlement in our most recent Arizona general rate case filing in which we agreed to not file a general rate case in Arizona until April 30, 2016. This could result in gradual earnings deterioration as costs increase for the duration of the stay-out period. If, despite rate establishment surrounding the decoupling mechanism, approval of the mechanism is rescinded by Arizona regulators, the prohibition against filing a general rate case for the remainder of the stay-out period would be eliminated.

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

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time. We intend 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.

Our operating results may be adversely impacted by a prolonged economic downturn.

The most recent 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 the recent slowdown have eased in our service territories yet effects remain such that the economy has not returned to the levels seen prior to the slowdown. 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, 2014 of approximately $241 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, 2014 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 2014, Southwest recognized $5.3 million in Other income (deductions) due to increases in the cash surrender values of its company-owned life insurance policies and net death benefits recognized (compared to an increase of $12.4 million due to increases in cash surrender values and net death benefits recognized in 2013). 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 would result in increased contributions and higher pension expense which would have a negative impact on our cash flows and results of operations.

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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 2015, 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 dollars (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.

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. With the recent acquisition of utility construction businesses that operate in Canada, additional adverse weather impacts could occur.

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.

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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 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.

Use of technologies presents a risk for attacks on our information systems and the stability of our operations.

Over the last several years we have undertaken a variety of initiatives to integrate, standardize, centralize and streamline our operations. These efforts have resulted in greater reliance on technological tools. The failure of any of these technologies, or our inability to have technologies supported, updated, expanded or integrated into other technologies, could adversely impact our operations. Additionally, we could experience breaches of security pertaining to sensitive customer, employee and vendor information maintained by us in the normal course of business, which could adversely affect the utility’s reputation, diminish customer confidence, disrupt operations, and subject us to possible financial liability or increased regulation or litigation, any of which could adversely affect our financial condition and results of operations.

Furthermore, we rely on information technology systems in our natural gas operations segment for our distribution and storage operations. There are various risks associated with these systems including hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other inadvertent errors or deliberate human acts. In particular, cyber security attacks, terrorism or other malicious acts could damage, destroy or disrupt our business systems. Any failure of information technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. As these potential cyber security attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems.

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

During 2014, 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.

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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.

We may not be able to successfully integrate our acquisition of construction services businesses.

The integration of acquisitions requires significant time and resources. We plan to make investments of resources to support the 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 the companies we acquired, we may not realize the benefits expected from the transaction and the goodwill recorded as a result of the acquisition could be impaired. Any impairment recorded would reduce operating results of future periods.

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, 2014 was $5.6 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.

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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.

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 17, 2015, there were 14,686 holders of record of common stock, and the market price of the common stock was $56.73. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2014 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

In February 2015, the Board of Directors (“Board”) increased the quarterly dividend payout to 40.5 cents per share, effective with the June 2015 payment. This marks the ninth consecutive year in which the dividend was increased. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average, while maintaining the Company’s stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Board’s continued review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects. The quarterly common stock dividend declared was 29.5 cents per share throughout 2012, 33 cents per share throughout 2013, and 36.5 cents per share throughout 2014.

Item 6. SELECTED FINANCIAL DATA

Information required by this item is included in the 2014 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 2014 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 2015 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 (for the 2014/2015 heating season, currently up to 25%, depending on the jurisdiction) 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 further swaps and fixed-price purchases pursuant to the Volatility Mitigation Program for its Nevada service territories. The decision did not impact previously executed purchase arrangements which relate to delivery periods up to and including March 2015. The Company along with its regulators will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

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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 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, 2014 and 2013, Southwest had $205 million and $60 million, respectively, in variable-rate debt outstanding, excluding the IDRBs noted above. 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 $2,050,000. As of December 31, 2014, Centuri had approximately $200 million in variable-rate debt outstanding. Centuri had no variable-rate debt outstanding at December 31, 2013. 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 $2,000,000.

Foreign Currency Exchange Rate Risk

In October 2014, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses. Of these businesses, the two largest companies operate in Canada. The new investment in Canada exposed the Company 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 2014, 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 Notes thereto, together with the report of PricewaterhouseCoopers LLP, are included in the 2014 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

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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.

On October 1, 2014, the Company completed the acquisition of three privately held, affiliated construction businesses: Link-Line Contractors, W.S. Nicholls Construction, and Brigadier Pipelines. The acquired businesses represent 5% of consolidated total assets and 3% of consolidated revenues for the year ended December 31, 2014 and are not significant to the Company’s consolidated financial statements. As permitted by SEC guidance for newly acquired businesses, the Company’s management elected to exclude Link-Line Contractors, W.S. Nicholls Construction, and Brigadier Pipelines from its evaluation of disclosure controls and procedures and management’s report on changes in internal control over financial reporting from the date of such acquisition through December 31, 2014. The Company’s management is in the process of reviewing the operations of Link-Line Contractors, W.S. Nicholls Construction, and Brigadier Pipelines and implementing the Company’s internal control structure over the acquired operations. This review will be completed in 2015.

Based on the most recent evaluation, as of December 31, 2014, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Company’s disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.

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 2014 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 84.

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 2014 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 85.

Controls over accounting for business combinations, and the valuation of certain assets and liabilities acquired, were added during the fourth quarter of 2014 but did not materially affect the Company’s internal control over financial reporting. There have been no other changes in the Company’s internal controls over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) 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.

Item 9B. OTHER INFORMATION

None.

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 2015 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, 2014 are as follows:

Name	Age	Position	Period Position Held
Jeffrey W. Shaw	56	Chief Executive Officer President and Chief Executive Officer Chief Executive Officer	2014-Present * 2012-2014 2010-2012
John P. Hester	52	President Executive Vice President Senior Vice President/Regulatory Affairs & Energy Resources	2014-Present 2013-2014 2010-2013
William N. Moody	58	Executive Vice President Senior Vice President/Staff Operations & Technology Vice President/Gas Resources	2013-Present 2012-2013 2010-2012
Roy R. Centrella	57	Senior Vice President/Chief Financial Officer Vice President/Controller and Chief Accounting Officer	2010-Present 2010
Eric DeBonis	47	Senior Vice President/Operations Senior Vice President/Staff Operations & Technology Vice President/Special Projects Vice President/Central Arizona Division	2012-Present 2011-2012 2010-2011 2010
Karen S. Haller	51	Senior Vice President/General Counsel and Corporate Secretary Vice President/General Counsel, Compliance Officer, and Corporate Secretary Vice President/General Counsel and Compliance Officer	2012-Present 2010-2012 2010
Laura Lopez Hobbs	55	Senior Vice President/Human Resources and Administration Vice President/Administration Vice President/Human Resources	2012-2014 ** 2010-2012 2010
Edward A. Janov	60	Senior Vice President/Corporate Development Senior Vice President/Finance	2010-Present 2010
Anita M. Romero	52	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 2010-2011
Kenneth J. Kenny	52	Vice President/Finance/Treasurer Vice President/Treasurer	2010-Present 2010
Gregory J. Peterson	55	Vice President/Controller and Chief Accounting Officer Assistant Controller	2010-Present 2010

* Will retire March 1, 2015

** Retired January 1, 2015

(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 2015 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 2015 Proxy Statement, which by this reference is incorporated herein.

16

(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 2015 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 2014 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 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 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 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 2015 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 2015 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 2015 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 2015 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 2015 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, 2014, 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.

17

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		36	$	28.97		—
Equity compensation plans not approved by security holders		—		—		—
Total		36	$	28.97		—

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.

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		271	$	43.71		878
Equity compensation plans not approved by security holders		—		—		—
Total		271	$	43.71		878

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		257	$	41.22		83
Equity compensation plans not approved by security holders		—		—		—
Total		257	$	41.22		83

18

Additional information regarding the three equity compensation plans is included in Note 10 of the Notes to Consolidated Financial Statements in the 2014 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 2015 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 2015 Proxy Statement, which by this reference is incorporated herein.

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 2014 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	84
Report of Independent Registered Public Accounting Firm	85

(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.

19

LIST OF EXHIBITS

Exhibit Number	Description of Document
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 between Clark County, Nevada, and BNY Midwest Trust Company as Trustee, dated as of October 1, 2004, with respect to the issuance of $75,000,000 Industrial Development Refunding Revenue Bonds (Southwest Gas Corporation), Series 2004B, due 2033. Incorporated herein by reference to Exhibit 4.01 to Form 10-K for the year ended December 31, 2004, 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 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.

20

Exhibit Number	Description of Document
4.12	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.
4.13	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.
4.14	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.
4.15	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.
4.16	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.
4.17	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.
4.18	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.
4.19	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.
4.20	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.
4.21	Indenture, dated March 23, 2012, 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 March 20, 2012, File No. 1-07850.
4.22	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. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 1, 2013. File No. 1-07850.
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.

21

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	Financing Agreement dated as of October 1, 2004 by and between the Company and Clark County, Nevada, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2004B. Incorporated herein by reference to Exhibit 10.01 to Form 10-K for the year ended December 31, 2004, File No. 1-07850.
10.12	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.
10.13	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.
10.14	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.

22

Exhibit Number	Description of Document
10.15	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.
10.16	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.
10.17	$300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 15, 2012, File No. 1-07850.
10.18	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 31, 2014, 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 $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.
12.01	Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.
13.01	Portions of 2014 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, 2014, 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

23

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 26, 2015	By	/S/ JEFFREY W. SHAW
		Jeffrey W. Shaw
		Chief Executive Officer

24

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 26, 2015
/S/ JOSÉ A. CÁRDENAS (José A. Cárdenas)	Director	February 26, 2015
/S/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	February 26, 2015
/S/ STEPHEN C. COMER (Stephen C. Comer)	Director	February 26, 2015
/S/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	February 26, 2015
/S/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director	February 26, 2015
/S/ ANNE L. MARIUCCI (Anne L. Mariucci)	Director	February 26, 2015
/S/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Chairman of the Board of Directors	February 26, 2015
/S/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director, Chief Executive Officer	February 26, 2015
/S/ A. RANDALL THOMAN (A. Randall Thoman)	Director	February 26, 2015
/S/ THOMAS A. THOMAS (Thomas A. Thomas)	Director	February 26, 2015
/S/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	February 26, 2015
/S/ ROY R. CENTRELLA (Roy R. Centrella)	Senior Vice President/ Chief Financial Officer	February 26, 2015
/S/ GREGORY J. PETERSON (Gregory J. Peterson)	Vice President, Controller, and Chief Accounting Officer	February 26, 2015

25

EX-12.01

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)

	December 31,
	2014		2013		2012		2011		2010
1. Fixed charges:
A) Interest expense	$	71,234	$	62,958	$	67,148	$	68,183	$	75,481
B) Amortization		2,063		2,002		2,001		2,137		2,620
C) Interest portion of rentals		11,802		11,809		10,605		8,943		6,455
Total fixed charges	$	85,099	$	76,769	$	79,754	$	79,263	$	84,556
2. Earnings (as defined):
D) Pretax income from continuing operations	$	219,521	$	222,815	$	207,915	$	175,066	$	158,378
Fixed Charges (1. above)		85,099		76,769		79,754		79,263		84,556
Total earnings as defined	$	304,620	$	299,584	$	287,669	$	254,329	$	242,934
		3.58		3.90		3.61		3.21		2.87

EX-13.01

Exhibit 13.01

Consolidated Selected Financial Statistics

Year Ended December 31,	2014			2013			2012			2011			2010
(Thousands of dollars, except per share amounts)
Operating revenues	$	2,121,707		$	1,950,782		$	1,927,778		$	1,887,188		$	1,830,371
Operating expenses		1,837,224			1,676,567			1,656,254			1,637,108			1,598,254
Operating income	$	284,483		$	274,215		$	271,524		$	250,080		$	232,117
Net income	$	141,126		$	145,320		$	133,331		$	112,287		$	103,877
Total assets at year end	$	5,214,515		$	4,565,174		$	4,488,057		$	4,276,007		$	3,984,193
Capitalization at year end
Total equity	$	1,486,266		$	1,412,395		$	1,308,498		$	1,225,031		$	1,166,996
Redeemable noncontrolling interest		20,042			—			—			—			—
Long-term debt, excluding current maturities		1,637,592			1,381,327			1,268,373			930,858			1,124,681
	$	3,143,900		$	2,793,722		$	2,576,871		$	2,155,889		$	2,291,677
Current maturities of long-term debt	$	19,192		$	11,105		$	50,137		$	322,618		$	75,080
Common stock data
Common equity percentage of capitalization		47.3	%		50.6	%		50.8	%		56.8	%		50.9	%
Return on average common equity		9.7	%		10.6	%		10.4	%		9.3	%		9.1	%
Basic earnings per share	$	3.04		$	3.14		$	2.89		$	2.45		$	2.29
Diluted earnings per share	$	3.01		$	3.11		$	2.86		$	2.43		$	2.27
Dividends declared per share	$	1.46		$	1.32		$	1.18		$	1.06		$	1.00
Payout ratio		48	%		42	%		41	%		43	%		44	%
Book value per share at year end	$	32.03		$	30.51		$	28.39		$	26.68		$	25.60
Market value per share at year end	$	61.81		$	55.91		$	42.41		$	42.49		$	36.67
Market value per share to book value per share		193	%		183	%		149	%		159	%		143	%
Common shares outstanding at year end (000)		46,523			46,356			46,148			45,956			45,599
Number of common shareholders at year end		14,749			15,359			16,028			16,834			17,821
Ratio of earnings to fixed charges		3.58			3.90			3.61			3.21			2.87

8    |    Southwest Gas Corporation

Natural Gas Operations

Year Ended December 31,	2014			2013			2012			2011			2010
(Thousands of dollars)
Operating revenue		1,382,087			1,300,154			1,321,728			1,403,366			1,511,907
Net cost of gas sold		505,356			436,001			479,602			613,489			736,175
Operating margin		876,731			864,153			842,126			789,877			775,732
Expenses
Operations and maintenance		383,732			384,914			369,979			358,498			354,943
Depreciation and amortization		204,144			193,848			186,035			175,253			170,456
Taxes other than income taxes		47,252			45,551			41,728			40,949			38,869
Operating income	$	241,603		$	239,840		$	244,384		$	215,177		$	211,464
Contribution to consolidated net income	$	116,872		$	124,169		$	116,619		$	91,420		$	91,382
Total assets at year end	$	4,657,709		$	4,272,029		$	4,204,948		$	4,048,613		$	3,845,111
Net gas plant at year end	$	3,658,383		$	3,486,108		$	3,343,794		$	3,218,944		$	3,072,436
Construction expenditures and property additions	$	350,025		$	314,578		$	308,951		$	305,542		$	188,379
Cash flow, net
From operating activities	$	288,534		$	265,290		$	344,441		$	216,745		$	342,522
From (used in) investing activities		(328,645	)		(304,189	)		(296,886	)		(289,234	)		(178,685	)
From (used in) financing activities		23,413			44,947			(43,453	)		(2,327	)		(107,779	)
Net change in cash	$	(16,698	)	$	6,048		$	4,102		$	(74,816	)	$	56,058
Total throughput (thousands of therms)
Residential		617,377			741,327			655,046			718,765			704,693
Small commercial		276,582			298,045			270,665			303,923			300,940
Large commercial		94,391			102,761			116,582			112,256			111,833
Industrial/Other		32,374			50,210			47,830			50,208			58,922
Transportation		906,691			1,037,916			998,095			941,544			998,600
Total throughput		1,927,415			2,230,259			2,088,218			2,126,696			2,174,988
Weighted average cost of gas purchased ($/therm)	$	0.55		$	0.42		$	0.42		$	0.58		$	0.62
Customers at year end		1,930,000			1,904,000			1,876,000			1,859,000			1,837,000
Employees at year end		2,196			2,220			2,245			2,298			2,349
Customer to employee ratio		879			858			836			809			782
Degree days – actual		1,416			1,918			1,740			2,002			1,998
Degree days – ten-year average		1,816			1,876			1,866			1,888			1,876

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, 2014, Southwest had 1,930,000 residential, commercial, industrial, and other natural gas customers, of which 1,033,000 customers were located in Arizona, 708,000 in Nevada, and 189,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2014, 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 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.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co. (“NPL”), completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating Centuri Construction Group Inc. (“Centuri” or the “construction services” segment), a direct subsidiary of Carson Water Company. In addition, two direct subsidiaries were created under Centuri: Vistus Construction Group Inc. (“Vistus,” U.S. operations) and Lynxus Construction Group Inc. (“Lynxus,” Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line Contractors Ltd. and W.S. Nicholls Construction Inc. are subsidiaries of Lynxus. References to the name Centuri or the term construction services will relate to results or activities of the businesses, individually or in the aggregate, included in the Centuri organization.

Centuri, a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems,

10    |    Southwest Gas Corporation

and develops industrial construction solutions. Centuri operates in 20 major markets in the United States (primarily under the NPL name) and in 2 major markets in Canada (under the Link-Line and W.S. Nicholls names). Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented or modified pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the U.S. Generally, revenues are lowest during the first quarter of the year due to less favorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. This is expected in both the U.S. and Canadian markets. In certain circumstances, such as with large, longer duration bid contracts, 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 85% 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,	2014		2013		2012
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	116,872	$	124,169	$	116,619
Construction services		24,254		21,151		16,712
Consolidated	$	141,126	$	145,320	$	133,331
Average number of common shares outstanding		46,494		46,318		46,115
Basic earnings per share
Consolidated	$	3.04	$	3.14	$	2.89
Natural Gas Operations
Operating margin	$	876,731	$	864,153	$	842,126

2014 Overview

Consolidated results for 2014 decreased compared to 2013 due to lower results from the natural gas operations segment, partially offset by improved results from the construction services segment. Basic earnings per share were $3.04 in 2014 compared to basic earnings per share of $3.14 in 2013.

Natural gas operations highlights include the following:

• Operating margin increased $13 million, or 1%, compared to the prior year

• Operating expenses increased $11 million, or 2%, between years

• Net financing costs increased $6 million between 2014 and 2013

Southwest Gas Corporation    |     11

• COLI income decreased from $12.4 million to $5.3 million between years

• Credit facility expiration date extended two years to March 2019

• Decision reached in the California general rate case

• Settlement reached in the Paiute Pipeline Company rate case

• The Company’s credit rating was upgraded from Baa1 to A3 by Moody’s Investors Service in January 2014 and downgraded from A- to BBB+ by Standard and Poor’s in October 2014

Construction services highlights include the following:

• Completed acquisition of three construction services businesses in October 2014

• Revenues in 2014 increased $89 million, or 14%, compared to 2013

• Construction expenses increased $75 million or 13%, compared to 2013, and included $5 million in transaction costs

• Contribution to net income increased $3 million compared to 2013

Customer Growth.    Southwest completed 20,000 first-time meter sets, but realized 26,000 net new customers during 2014, an increase of 1.4%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for 2015.

Company-Owned Life Insurance (“COLI”).    Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $241 million at December 31, 2014. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $99 million at December 31, 2014 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. As indicated in Note 1 of the Notes to Consolidated Financial Statements, income due to changes in cash surrender values of COLI policies (including incremental death benefits) was $5.3 million in 2014 and $12.4 million in 2013. Management currently expects average returns of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized.

Liquidity.    Southwest believes its liquidity position is solid. Southwest has a $300 million credit facility maturing in March 2019. 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 2014 was $165 million. In November 2014, the Company redeemed the $65 million 5.25% 2004 Series A Industrial Development Revenue Bonds (“IDRBs”) using the credit facility to fund the redemption. At December 31, 2014, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $5 million was outstanding on the short-term portion of the credit facility. Southwest has no significant debt maturities prior to 2017.

12    |    Southwest Gas Corporation

Construction Services.    Centuri’s contribution to net income for 2014 was $24.3 million, a $3.1 million increase over the results for 2013. Acquisition costs of $5 million were included in construction expenses in 2014. Gains on sale of equipment in the current year were $6.2 million compared to $4.1 million in the prior year. The prior year also included $4 million in legal-related expenses.

Results of Natural Gas Operations

Year Ended December 31,	2014		2013		2012
(Thousands of dollars)
Gas operating revenues	$	1,382,087	$	1,300,154	$	1,321,728
Net cost of gas sold		505,356		436,001		479,602
Operating margin		876,731		864,153		842,126
Operations and maintenance expense		383,732		384,914		369,979
Depreciation and amortization		204,144		193,848		186,035
Taxes other than income taxes		47,252		45,551		41,728
Operating income		241,603		239,840		244,384
Other income (deductions)		7,165		12,261		4,165
Net interest deductions		68,299		62,555		66,957
Income before income taxes		180,469		189,546		181,592
Income tax expense		63,597		65,377		64,973
Contribution to consolidated net income	$	116,872	$	124,169	$	116,619

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 (see Rates and Regulatory Proceedings). New customers contributed $8 million of the increase during 2014 as approximately 26,000 net new customers were added during the last twelve months. 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 planned $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 the current year 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

Southwest Gas Corporation    |     13

$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 periods due to higher property taxes in Arizona and Nevada.

Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, decreased $5.1 million between 2014 and 2013. The current year reflects $5.3 million of income associated with COLI policy cash surrender value increases, while the prior year included $12.4 million of COLI-related income. Interest income increased $2.1 million between years. Under-collected PGA balances and the associated interest income thereon rose significantly in the current year (see PGA Filings for more information).

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 the prior year associated with PGA balances, which were in an over-collected status for the majority of 2013.

2013 vs. 2012

Contribution to consolidated net income from natural gas operations increased by $8 million between 2013 and 2012. The improvement was primarily due to increases in operating margin and other income and a decrease in net interest deductions, partially offset by higher operating expenses.

Operating margin increased $22 million between years. Rate relief provided $8 million of the increase in operating margin (including general rate relief in Nevada and net attrition amounts in California). New customers contributed $7 million of the increase in operating margin during 2013. Incremental margin from customers outside the decoupling mechanisms and other miscellaneous revenues (including amounts associated with recoveries of Arizona regulatory assets) contributed the remainder of the increase.

Operations and maintenance expense increased $14.9 million, or 4%, between years primarily due to higher general costs, employee-related costs (including a majority of the $6.4 million increase in pension costs), uncollectible expense, and pipeline integrity management programs, partially offset by lower legal claims and expenses.

Depreciation and amortization expense increased $7.8 million, or 4%. Average gas plant in service for 2013 increased $230 million, or 5%, compared to 2012. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in Nevada (effective November 2012). Amortization associated with the recovery of Arizona regulatory assets, new conservation and energy efficiency programs in Nevada, and other amortization collectively increased $6.2 million.

Taxes other than income taxes increased $3.8 million between periods due to higher property taxes in Arizona and changes resulting from the last Nevada general rate case, whereby modified business and mill taxes became components of operating expenses.

Other income increased $8.1 million between 2013 and 2012. Cash surrender values of COLI policies (including net death benefits recognized) increased $12.4 million in 2013, while COLI-related income was $6.6 million in the prior year. In addition, Arizona non-recoverable pipe replacement costs were $2.5 million lower in 2013 as compared to 2012 because this pipe replacement activity was substantially completed in 2012.

14    |    Southwest Gas Corporation

Net interest deductions decreased $4.4 million between 2013 and 2012 primarily due to cost savings from refinancing, redemptions, and lower interest expense associated with deferred PGA balances payable. The decrease was partially offset by the October 2013 issuance of $250 million of 4.875% senior notes. The prior year included a temporary increase in debt outstanding for approximately two months associated with debt refinancing that occurred in the first half of 2012.

Outlook for 2015

Operating margin for 2015 is expected to be favorably influenced by customer growth similar to 2014. Incremental margin (attrition) associated with the 2014 California rate case decision as well as the Paiute rate case decision, and new rates established to recover Nevada infrastructure programs (see Rates and Regulatory Proceedings) collectively should approximate the customer growth amount. Combined, total operating margin is estimated to increase nearly 2%.

Operations and maintenance expense will be negatively impacted by a proportionate share (approximately 80%) of an expected $10 million increase in pension costs. Other costs, net, are expected to be relatively flat. Depreciation and general taxes should increase consistent with the growth in gas plant in service (approximately 5% to 6%). Overall, operating expenses are anticipated to increase by 3% to 4% compared to 2014.

COLI-related income was $5.3 million in 2014, which is at the upper end of the expected range of average returns, as Southwest generally anticipates longer term normal changes in COLI cash surrender values to range from $3 million to $5 million on an annual basis. However, individual quarterly and annual periods will continue to be subject to volatility.

Southwest anticipates that net interest deductions for 2015 will approximate the $68 million recorded in 2014.

Results of Construction Services

Year Ended December 31,	2014			2013			2012
(Thousands of dollars)
Construction revenues	$	739,620		$	650,628		$	606,050
Operating expenses:
Construction expenses		647,857			573,284			541,523
Depreciation and amortization		48,883			42,969			37,387
Operating income		42,880			34,375			27,140
Other income (deductions)		(58	)		39			246
Net interest deductions		3,770			1,145			1,063
Income before income taxes		39,052			33,269			26,323
Income tax expense		14,776			12,565			10,303
Net income		24,276			20,704			16,020
Net income (loss) attributable to noncontrolling interests		22			(447	)		(692	)
Contribution to consolidated net income attributable to Centuri	$	24,254		$	21,151		$	16,712

2014 vs. 2013

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

Southwest Gas Corporation    |     15

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. Construction revenues include Centuri contracts with Southwest totaling $92.2 million in 2014 and $88.2 million in 2013. Centuri accounts for services provided to Southwest at contractual (market) prices at contract inception.

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 recently acquired companies, acquisition costs ($5 million), and changes that were implemented to match the increased size of the business and its complexity. In addition, construction services recorded approximately $4 million 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 the prior year 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 recent 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 2014 and 2013, revenues from replacement work were 67% and 70%, respectively, of total revenues. Governmental pipeline safety-related programs and U.S. tax bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. Centuri continues to successfully bid on pipe replacement projects throughout the United States and Canada.

2013 vs. 2012

Contribution to consolidated net income from construction services for 2013 increased $4.4 million compared to 2012. The increase was primarily due to a $15 million pretax loss recognized on a large fixed-price contract in 2012, partially offset by lower gains on the sale of equipment and higher general and administrative expenses (included in Construction expenses) in 2013.

Revenues increased $44.6 million, or 7%, when compared to 2012 due primarily to an increase in utility customer contracts for pipe replacement work, partially offset by the winding down of a portion of work related to the large fixed-price contract noted above. Construction revenues include NPL contracts with Southwest totaling $88.2 million in 2013 and $83.4 million in 2012. Construction services accounts for services provided to Southwest at contractual (market) prices at contract inception.

Construction expenses increased $31.8 million, or 6%, primarily due to additional pipe replacement work in 2013 as compared to 2012. Despite these increases, the construction expense variance between years was favorably impacted as 2012 included a $15 million pretax loss associated with the above-noted large fixed-price contract. General and administrative expense (included in construction expenses) increased approximately $6 million due to changes that were implemented to match the increased size of the business and its complexity. In addition, the construction services segment recorded approximately $4 million in 2013 associated with a legal settlement which

16    |    Southwest Gas Corporation

was resolved in February 2014. Depreciation and amortization expense increased $5.6 million between 2013 and 2012 due to additional equipment purchased to support growth in the volume of work being performed. Gains on sale of equipment (reflected as an offset to construction expenses) were $4.1 million and $8 million in 2013 and 2012, respectively.

During the past several years, the constructions services segment has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2013 and 2012, revenues from replacement work were 70% and 75%, respectively, of total revenues. Governmental pipeline safety-related programs and bonus depreciation incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.

Outlook for 2015

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

The recent acquisition has expanded the construction services operating base. Comparative results for 2015 will be favorably impacted by elimination of the acquisition costs ($5 million) recognized in 2014 as well as a full year of results associated with the acquisition (compared to one quarter in 2014). In 2015, Centuri revenues are expected to range between $950 million and $1 billion, and operating income is expected to approximate 6% of revenues (including the impacts of amortization, resulting from acquired intangibles, of approximately $5 million). Based on interest rates under Centuri’s secured revolving credit and term loan facility as of December 2014, we anticipate 2015 related net interest deductions to be between $6.5 million and $7.5 million. These collective expectations are before consideration of the portion of earnings attributable to the noncontrolling interest. Additionally, foreign exchange rates and the interest rate environment could influence their achievement.

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 2012 to 2014.

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

Southwest Gas Corporation    |     17

Rehearing Decision addressed issues raised by Southwest regarding capital structure. After taking into account modifications made as a result of the Rehearing Decision, the Company was authorized an annual revenue increase of $6.8 million, an overall rate of return of 6.56%, and a 10% return on 42.7% common equity in southern Nevada; and an annual revenue increase of $700,000, 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 proposed by Southwest. The PUCN decision also included a reduction in annualized depreciation expense of $5.2 million and $1.7 million in southern and northern Nevada, respectively. In addition, the PUCN decision reclassified approximately $2.5 million of modified business and mill taxes from pass-through items to operating expenses.

Infrastructure Replacement Mechanisms.    In January 2013, the PUCN authorized the opening of a new docket to review the merits of a mechanism to defer and recover certain costs associated with accelerated replacement of early vintage plastic (“EVPP”) and steel pipe, which was originally requested in the general rate case filed in April 2012. In January 2014, the PUCN concluded the rulemaking process by approving final rules, with only slight modifications to earlier proposed rules. 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 naturally.

Separately, in March 2013, Southwest submitted a petition to the PUCN requesting authority to defer certain costs associated with the proposed accelerated 2013 replacement of certain EVPP to coincide with bonus depreciation tax relief extended by The American Taxpayer Relief Act of 2012. In June 2013, a stipulation (the “Stipulation”), which provided regulatory asset treatment for specific infrastructure replacement projects occurring during 2013 in the amount of $2 million in northern Nevada and approximately $13.6 million in southern Nevada, was reached by all parties and was approved by the PUCN. While the above-noted infrastructure replacement regulation was being finalized, the Company submitted a filing to the PUCN in November 2013 requesting authority to replace $18.9 million of EVPP in 2014; the PUCN approved the request in January 2014. The new rules (noted in the paragraph above) enabled the Company to make a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying projects for replacement beginning in January 2015. The PUCN issued a final decision on this application in October 2014, approving EVPP replacement expenditures of $14.4 million in 2015. Also in October 2014, Southwest filed its first GIR rate application to request a surcharge to recover cumulative deferrals through August 2014, which were established through five separate regulatory dockets. This surcharge was made effective for both the southern and northern Nevada rate jurisdictions in January 2015.

Effectively, as a result of these mechanisms, the increase in depreciation expense, ordinarily arising from related capital expenditures, will be netted to zero for approved projects by the deferral process, between general rate cases. Incremental earnings associated with the equity portion of return related to these infrastructure replacements will materialize through billed rates, now that a surcharge has been established. The surcharge is expected to provide approximately $2 million in incremental operating margin in 2015 (part of which will be offset by higher amortization expense due to the favorable impacts previously recognized in deferring depreciation on the underlying plant). The actual amount achieved will be dependent upon actual volumes sold, as the surcharge is assessed through volumetric rates.

18    |    Southwest Gas Corporation

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 2014, Southwest made its annual PTY attrition filing, requesting annual revenue increases of $1.8 million in southern California, $486,000 in northern California and $243,000 for South Lake Tahoe. This filing was approved in December 2014 and rates were made effective in January 2015.

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 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 its 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. Of those allowances, Southwest must consign 25% into quarterly allowance auctions and the remaining allowances can be used to meet the triennial compliance obligation to cover the quantity of GHG emissions that occur during each triennial compliance period. The amount Southwest must consign increases by 5% annually. Given those levels of consignment, Southwest must also purchase allowances to meet its triennial compliance period obligations. Those purchases can be made through auctions or reserve sales that are hosted by the CARB, or through over the counter (“OTC”) purchases with other market participants. In addition to allowances, Southwest can purchase up to 8% of its annual GHG emissions with 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 those 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.

Southwest Gas Corporation    |     19

By September of each year, Southwest must inform the CARB of the percentage of Southwest’s annual allocation that are to be placed in Southwest’s Limited Use Holding Account (“LUHA”) for consignment to the quarterly auctions. In August 2014, Southwest filed the necessary paperwork with the CARB to place 25% of the allocated allowances in the LUHA. In December 2014, Southwest applied to participate in the quarterly auction to be held in February 2015 the results of which are still pending.

In January 2015, Southwest made a filing with the CPUC to establish two new balancing accounts required to comply with the GHG program. These accounts will be used to track and record costs incurred and revenue from consignment of the Company’s GHG allowances for auction and to separately track GHG administrative costs. An entry is expected during the first quarter of 2015 to record the amount required, in order to participate in the February 2015 auction, along with any associated costs. The recovery of these costs and the mechanism to return revenues received from consignment of the GHG allowances will be determined in Phase II of the CPUC Rulemaking, expected to occur during 2015.

Arizona Jurisdiction

General Rate Case Status.    The most recent general rate case decision (“ACC decision”) from the Arizona Corporation Commission (“ACC”) in Southwest’s Arizona rate jurisdiction was made effective in January 2012 and authorized an increase of $52.6 million, which included 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. The ACC decision also approved a full revenue decoupling mechanism with a monthly weather adjuster. In addition, Southwest agreed not to file a general rate case prior to April 30, 2016.

Proposed LNG (“Liquefied Natural Gas”) Facility.    In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, operated by Southwest and connected directly to its distribution system. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system) not to exceed $55 million. Two options were presented in the ACC filing to fill the storage tank; either transferring LNG from tanker trucks or to liquefy the natural gas onsite. The liquefaction option would have required the installation of equipment during the construction of the facility, at an additional cost of approximately $24 million and an estimated additional six months to construct. In December 2014, Southwest received an order from the ACC (“Order”) granting pre-approval of Southwest’s application to construct the LNG facility, excluding the liquefaction option, 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. These deferred costs and benefits will be evaluated in a future rate proceeding. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. Construction progress reports are required every six months until completion. Completion of the siting requirements for flammable vapor dispersion is also a condition of approval for the facility. Construction is expected to be complete within approximately 24 to 30 months from the date of approval.

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 are setoff from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously

20    |    Southwest Gas Corporation

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 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 November 2013, the Company filed a request to modify or clarify the COYL provision to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. This request was approved by the ACC in January 2014. A revised surcharge request, filed in February 2014, was approved effective June 2014. With the completion of Phase I customer contact, resources are now focused on contacting customers within replacement project areas to participate in the Phase II meter relocation.

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. The application requested an increase in operating revenues of approximately $9 million, and included a proposed change in rate design, which would compensate Paiute with a higher return if shippers desire to maintain shorter-lived contracts and, therefore, would incent shippers to sign longer term service agreements.

In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle its general rate case. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement, which was filed with the FERC in November 2014, would result in a revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. This increase is based on 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.

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 will be filed within 30 days of the final approval, in March 2015.

Elko County Expansion Project.    During the second and third quarters of 2013, Paiute notified present and potential shippers of its plans to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area. This additional capacity is required to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. Through the “open season” process, shippers responded with substantial interest. Dependent upon several variables, including the ultimate route of the project, the price of labor and materials, and factors such as environmental impacts, the cost to complete this project has been estimated at approximately $35 million and has a targeted in-service date of November 2015 (contingent upon FERC action). In October 2013, Paiute submitted a filing with the FERC requesting that its Staff initiate a pre-filing review of the proposed expansion project; a certificate application for the project was filed in June 2014. In October 2014, the FERC issued a notice of schedule for environmental review for this project. A preliminarily favorable environmental assessment of the proposed project was issued by the FERC in January 2015. Based on the FERC’s schedule, and the resulting associated deadlines, the FERC is expected to issue a decision on Paiute’s certificate application in the first half of 2015.

Southwest Gas Corporation    |     21

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, 2014, under-collections in all three states resulted in an asset of $87.6 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

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

	2014		2013
Arizona	$	48.4	$	3.2
Northern Nevada		10.2		4.4
Southern Nevada		20.4		4.1
California		8.6		6.5
	$	87.6	$	18.2

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.

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 June 2014, Southwest filed its ARA application with the PUCN to establish revised Base Tariff General Rates (“BTGR”), in addition to adjustments to the Variable Interest Expense rate, the Unrecovered Gas Cost Expense rates, and other rate-related items, all of which was approved effective January 2015. In November 2014, Southwest filed to adjust its quarterly Deferred Energy Account Adjustment (“DEAA”), which is based upon a twelve-month rolling average, in addition to requesting adjusted Base Tariff Energy (“BTER”) rates, both of which were also approved effective January 2015.

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 (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) of its annual normal weather supply needs. For the 2014/2015 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $5 per dekatherm. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities, and on the spot market. Prices for these contracts are not known until the month of purchase.

22    |    Southwest Gas Corporation

In late 2013, the Company suspended further fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Nevada VMP suspension is forward looking and did not impact Nevada VMP purchase transactions that occurred prior to the suspension. Agreements, under the Nevada VMP program, made prior to the suspension will terminate following the March 2015 delivery month. The Company evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.

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. 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. A tax extenders bill, the Tax Increase Prevention Act of 2014, was signed into law, in late December 2014, retroactive to the beginning of the 2014, and did not extend into 2015.

Cash Flows

Operating Cash Flows.    Cash flows provided by consolidated operating activities were comparable between 2014 and 2013. Both periods were impacted by period net income and the impacts of adding back non-cash depreciation and amortization, as well as the impacts of working capital components overall.

Investing Cash Flows.    Cash used in consolidated investing activities increased $207.6 million in 2014 as compared to 2013. The increase was primarily due to the acquisition of the construction services businesses (see Note 15 – Acquisition of Construction Services Businesses for net assets acquired), additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by Centuri due to the increased replacement construction work of its customers. In addition, the current year includes cash outlays for the July 2014 purchase of the corporate headquarters office complex, but also includes greater inflows associated with customer advances taken for utility construction.

Financing Cash Flows.    Net cash provided by consolidated financing activities increased $190.1 million in 2014 as compared to 2013. The current year includes the repayment of $65 million of IDRBs and the prior year included the repayment of $53 million of IDRBs and $101 million repayment of amounts outstanding on Southwest’s revolving credit and commercial paper facility. The prior year includes the issuance of $250 million of 4.875% senior notes, and the current year includes $145 million ($140 million long-term and $5 million short-term) of proceeds from Southwest’s revolving credit and commercial paper facility. The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under Centuri’s line of credit. The majority of Centuri’s borrowings are associated with the acquisition of construction services businesses noted previously. In addition, the prior period included Centuri borrowing under note agreements with two banking institutions entered into during the second quarter of 2013. Dividends paid increased in 2014 as compared to 2013 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding.

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

Southwest Gas Corporation    |     23

2014 Construction Expenditures

During the three-year period ended December 31, 2014, total gas plant increased from $4.8 billion to $5.6 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 59,000 meters during the three-year period.

During 2014, construction expenditures for the natural gas operations segment were $350 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 $288 million and provided approximately 70% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and, as needed, existing credit facilities.

2014 Financing Activity

In March 2014, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2017, but was extended to March 2019.

In October 2014, construction services subsidiaries of the Company entered into a $300 million secured revolving credit and term loan facility. The facility is scheduled to expire in October 2019 and replaces the previous $75 million credit facility, which was scheduled to expire in June 2015.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2017 will be approximately $1.3 billion. Of this amount, approximately $445 million is expected to be incurred in 2015. Southwest plans to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). Significant replacement activities are expected to continue during the next several years. See also Rates and Regulatory Proceedings for discussion of Nevada infrastructure, California IRRAM, Arizona COYL, a recently authorized LNG facility, and planned Paiute expansion. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 75% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

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.

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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 2014, the net under-collected PGA balance increased $69.4 million resulting in an under-collection of $87.6 million at December 31, 2014. See PGA Filings for more information.

In March 2014, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2017 and was extended to March 2019. 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 2014 was $165 million ($150 million outstanding on the long-term portion of the credit facility (including $50 million on the commercial paper program), and $15 million outstanding on the short-term portion), which occurred in the fourth quarter. At December 31, 2014, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $5 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 $10 million, no borrowings, and $50 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. 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, 2014, $50 million was outstanding on the commercial paper program, which is the maximum amount outstanding during the year.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. At December 31, 2014, $199 million was outstanding on the Centuri secured credit facility.

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).

In October 2014, Standard & Poor’s Ratings Services (“S&P”) downgraded the Company’s unsecured long-term debt ratings from A- to BBB+ (with a stable outlook). S&P cited the Company’s acquisition of Link-Line, W. S. Nicholls, and Brigadier, which increases the relative size of the higher-risk construction services business segment. 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.

In January 2014, Moody’s Investors Service, Inc. (“Moody’s”) upgraded the Company’s senior unsecured ratings from Baa1 with a stable outlook to A3 with a stable outlook. Moody’s cited the Company’s improved regulatory

Southwest Gas Corporation    |     25

environment in its service territories. 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.

In May 2013, Fitch Ratings (“Fitch”) upgraded the Company’s senior unsecured ratings including IDRBs from A- (with a positive outlook) to A (with a stable outlook). Fitch cited the Company’s stronger credit metrics and improved business risk profile. 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.

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, 2014, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $1.9 billion in additional debt and meet the leverage ratio requirement. The Company has at least $900 million 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, 2014, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $88 million in additional debt and meet the leverage ratio requirement. Centuri has at least $35 million of cushion in equity 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 rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.

Off-Balance Sheet Arrangements

All 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.

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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 Statement 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, 2014 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2015		2016-2017		2018-2019		Thereafter
Operating activities:
Operating leases (Note 2)	$	16	$	6	$	7	$	2	$	1
Gas purchase obligations		190		115		73		1		1
Pipeline capacity/storage		1,087		129		200		114		644
Derivatives (Note 12)		5		5		—		—		—
Other commitments		13		7		5		1		—
Financing activities:
Long-term debt, including current maturities (Note 6)		1,657		19		65		321		1,252
Interest on long-term debt		1,020		65		127		123		705
Capital leases (Note 2)		5		2		3		—		—
Other		9		—		1		1		7
Total	$	4,002	$	348	$	481	$	563	$	2,610

Obligations for Operating Activities:    The table above provides a summary of the Company’s obligations associated with operating activities. 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 159 million dekatherms. The fixed-price contracts range in price from approximately $4 to $5 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.

Obligations for Financing Activities:    Contractual obligations for financing activities primarily related to debt obligations consisting 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, 2014 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 2015 is $36 million and is not included in the table above.

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Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition and going concern. 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. 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 the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.

Accrued Utility Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, 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.

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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 $36 million and future pension expense by $3.8 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $11.1 million and expense by $2.2 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.9 million (but has no impact on the pension obligation).

At December 31, 2014, the Company lowered the discount rate to 4.25% from a rate of 5.00% at December 31, 2013. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation decreased to 2.75% at December 31, 2014 from 3.25% in the prior year. The asset return assumption of 7.75% to be used for 2015 expense did not change from the rate used in the previous year. A change to a new actuarial mortality table, which takes into account longer life spans for plan participants will significantly increase the expense level for 2015. Pension expense for 2015 is estimated to increase by $10 million compared to 2014 because of the new mortality assumption and lower 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,

Southwest Gas Corporation    |     29

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. Goodwill is evaluated for impairment no less frequently than annually. The fair value assigned to the intangible assets acquired and liabilities assumed, and the determination of goodwill associated with the current acquisition, are described in Note 15 – 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, 2014 are included as exhibits to the 2014 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,” “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 proposed Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, incremental operating margin in 2015, net earnings impacts from gas infrastructure replacement surcharges, operating expense increases in 2015, funding sources of cash requirements, sufficiency of working capital and current credit facility, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, future Centuri operating revenues, operating income, amortization and interest expense, Centuri’s projected financial performance and related market growth potential, Centuri proforma financial results, pension and post-retirement benefits, certain benefits of tax acts, the effect of any rate changes or regulatory proceedings, including the Paiute Pipeline Company general rate case filing, infrastructure replacement mechanisms and the COYL program, statements

30    |    Southwest Gas Corporation

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

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, results of 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, competition, our ability to raise capital in external financings, the true-up of amounts acquired in connection with the recent acquisition, including income taxes and ongoing evaluations in regard to goodwill. 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, 2014.

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 forward-looking statements even if experience or future changes show that the indicated results or events will not be realized. We caution you not to unduly rely on any forward-looking statement(s).

Common Stock Price and Dividend Information

	2014				2013				Dividends Declared
	High		Low		High		Low		2014		2013
First quarter	$	55.33	$	51.70	$	48.11	$	42.02	$	0.365	$	0.330
Second quarter		55.69		50.96		51.52		45.11		0.365		0.330
Third quarter		53.34		47.21		50.99		45.70		0.365		0.330
Fourth quarter		64.20		48.23		56.03		48.76		0.365		0.330
									$	1.460	$	1.320

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 17, 2015, there were 14,686 holders of record of common stock, and the market price of the common stock was $56.73.

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

Southwest Gas Corporation    |     31

for its respective businesses. The quarterly common stock dividend declared was 29.5 cents per share throughout 2012, 33 cents per share throughout 2013, and 36.5 cents per share throughout 2014. As a result of its ongoing review of dividend policy, in February 2015, the Board increased the quarterly dividend from 36.5 cents to 40.5 cents per share, effective with the June 2015 payment. This marks the ninth consecutive year in which the dividend was increased. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average, while maintaining the Company’s stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Board’s continued review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects.

32    |    Southwest Gas Corporation

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

December 31,	2014			2013
ASSETS
Utility plant:
Gas plant	$	5,556,599		$	5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413
Net utility plant (Note 2)		3,658,383			3,486,108
Other property and investments (Note 1)		326,743			260,871
Restricted cash (Note 1)		821			—
Current assets:
Cash and cash equivalents		39,566			41,077
Accounts receivable, net of allowances (Note 3)		281,824			219,469
Accrued utility revenue		73,900			72,700
Income taxes receivable, net		21,853			3,790
Deferred income taxes, net (Note 11)		2,109			31,130
Deferred purchased gas costs (Note 4)		87,556			18,217
Prepaids and other current assets (Notes 1, 4, and 12)		99,975			108,289
Total current assets		606,783			494,672
Noncurrent assets:
Goodwill (Notes 1 and 15)		143,160			17,810
Deferred charges and other assets (Notes 2, 4, and 12)		478,625			305,713
Total noncurrent assets		621,785			323,523
Total assets	$	5,214,515		$	4,565,174

34    |    Southwest Gas Corporation

CONSOLIDATED BALANCE SHEETS – Continued

December 31,	2014			2013
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized – 60,000,000 shares; issued and outstanding – 46,523,184 and 46,356,125 shares) (Note 10)	$	48,153		$	47,986
Additional paid-in capital		851,381			840,521
Accumulated other comprehensive income (loss), net (Note 5)		(50,175	)		(41,698	)
Retained earnings		639,164			567,714
Total Southwest Gas Corporation equity		1,488,523			1,414,523
Noncontrolling interest		(2,257	)		(2,128	)
Total equity		1,486,266			1,412,395
Redeemable noncontrolling interest (Note 16)		20,042			—
Long-term debt, less current maturities (Note 6)		1,637,592			1,381,327
Total capitalization		3,143,900			2,793,722
Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)		19,192			11,105
Short-term debt (Note 7)		5,000			—
Accounts payable		167,988			183,511
Customer deposits		71,546			73,367
Accrued general taxes		44,339			39,681
Accrued interest		16,468			17,920
Other current liabilities (Notes 2, 4, and 12)		145,584			108,580
Total current liabilities		470,117			434,164
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 11)		723,688			674,411
Taxes payable		—			284
Accumulated removal costs (Note 4)		304,000			279,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 9, and 12)		572,810			383,593
Total deferred income taxes and other credits		1,600,498			1,337,288
Total capitalization and liabilities	$	5,214,515		$	4,565,174

The accompanying notes are an integral part of these statements.

35    |    Southwest Gas Corporation

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

Year Ended December 31,	2014			2013			2012
Operating revenues:
Gas operating revenues	$	1,382,087		$	1,300,154		$	1,321,728
Construction revenues		739,620			650,628			606,050
Total operating revenues		2,121,707			1,950,782			1,927,778
Operating expenses:
Net cost of gas sold		505,356			436,001			479,602
Operations and maintenance		383,732			384,914			369,979
Depreciation and amortization		253,027			236,817			223,422
Taxes other than income taxes		47,252			45,551			41,728
Construction expenses		647,857			573,284			541,523
Total operating expenses		1,837,224			1,676,567			1,656,254
Operating income		284,483			274,215			271,524
Other income and (expenses):
Net interest deductions (Notes 6 and 7)		(72,069	)		(63,700	)		(68,020	)
Other income (deductions)		7,107			12,300			4,411
Total other income and (expenses)		(64,962	)		(51,400	)		(63,609	)
Income before income taxes		219,521			222,815			207,915
Income tax expense (Note 11)		78,373			77,942			75,276
Net income		141,148			144,873			132,639
Net income (loss) attributable to noncontrolling interests		22			(447	)		(692	)
Net income attributable to Southwest Gas Corporation	$	141,126		$	145,320		$	133,331
Basic earnings per share (Notes 1 and 14)	$	3.04		$	3.14		$	2.89
Diluted earnings per share (Notes 1 and 14)	$	3.01		$	3.11		$	2.86
Average number of common shares outstanding		46,494			46,318			46,115
Average shares outstanding (assuming dilution)		46,944			46,758			46,555

The accompanying notes are an integral part of these statements.

36    |    Southwest Gas Corporation

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

Year Ended December 31,	2014			2013			2012
Net Income	$	141,148		$	144,873		$	132,639
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 9):
Net actuarial gain (loss)		(107,661	)		62,214			(46,409	)
Amortization of prior service cost		220			220			—
Amortization of transition obligation		—			—			538
Amortization of net actuarial loss		14,667			21,190			15,870
Prior service cost		(4,130	)		—			(1,502	)
Regulatory adjustment		86,991			(76,651	)		26,518
Net defined benefit pension plans		(9,913	)		6,973			(4,985	)
Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 12)		—			—			1,834
Amounts reclassified into net income (Notes 5 and 12)		2,073			2,074			1,737
Net forward-starting interest rate swaps		2,073			2,074			3,571
Foreign currency translation adjustments		(659	)		—			—
Total other comprehensive income (loss), net of tax		(8,499	)		9,047			(1,414	)
Comprehensive income		132,649			153,920			131,225
Comprehensive income (loss) attributable to noncontrolling interests		—			(447	)		(692	)
Comprehensive income attributable to Southwest Gas Corporation	$	132,649		$	154,367		$	131,917

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,	2014			2013			2012
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	141,148		$	144,873		$	132,639
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		253,027			236,817			223,422
Deferred income taxes		64,309			68,639			66,280
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(3,683	)		(22,556	)		12,333
Accrued utility revenue		(1,200	)		(700	)		(1,700	)
Deferred purchased gas costs		(69,339	)		(111,143	)		22,823
Accounts payable		(41,499	)		27,668			(25,998	)
Accrued taxes		(13,573	)		925			113
Other current assets and liabilities		23,379			5,084			(18,948	)
Gains on sale		(6,171	)		(4,112	)		(8,040	)
Changes in undistributed stock compensation		7,973			6,958			5,137
AFUDC		(1,995	)		(2,274	)		(1,943	)
Changes in other assets and deferred charges		(21,732	)		(21,719	)		(15,367	)
Changes in other liabilities and deferred credits		15,779			17,749			(4,427	)
Net cash provided by operating activities	$	346,423		$	346,209		$	386,324

38    |    Southwest Gas Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued

Year Ended December 31,	2014			2013			2012
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(396,898	)		(364,276	)		(395,712	)
Acquisition of businesses, net of cash acquired		(190,497	)		—			—
Restricted cash		1,233			—			12,785
Changes in customer advances		20,363			7,773			(3,025	)
Miscellaneous inflows		11,611			8,465			13,963
Miscellaneous outflows		(1,400	)		—			(2,004	)
Net cash used in investing activities		(555,588	)		(348,038	)		(373,993	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		405			1,635			1,581
Dividends paid		(66,275	)		(59,535	)		(53,040	)
Interest rate swap settlement		—			—			(21,754	)
Issuance of long-term debt, net		269,228			311,290			489,518
Retirement of long-term debt		(139,155	)		(137,013	)		(427,043	)
Change in credit facility and commercial paper		140,000			(101,000	)		2,000
Change in short-term debt		5,000			1,999			—
Principal payments on capital lease obligations		(434	)		—			—
Other		(1,257	)		—			—
Net cash provided by (used in) financing activities		207,512			17,376			(8,738	)
Effects of currency translation on cash and cash equivalents		142			—			—
Change in cash and cash equivalents		(1,511	)		15,547			3,593
Cash and cash equivalents at beginning of period		41,077			25,530			21,937
Cash and cash equivalents at end of period	$	39,566		$	41,077		$	25,530
Supplemental information:
Interest paid, net of amounts capitalized	$	65,552		$	58,730		$	87,439
Income taxes paid (received)	$	24,247		$	6,850		$	2,843

The accompanying notes are an integral part of these statements.

39    |    Southwest Gas Corporation

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, 2011		45,956	$	47,586	$	821,640	$	(49,331	)	$	406,125		$	(989	)	$	1,225,031		$	—
Common stock issuances		192		192		7,137											7,329
Net income (loss)											133,331			(692	)		132,639
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)								(4,985	)								(4,985	)
FSIRS realized and unrealized gain, net of tax (Notes 5 and 12)								1,834									1,834
Amounts reclassified to net income, net of tax (Notes 5 and 12)								1,737									1,737
Dividends declared
Common: $1.18 per share											(55,087	)					(55,087	)
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 9)								6,973									6,973
Amounts reclassified to net income, net of tax (Notes 5 and 12)								2,074									2,074
Dividends declared
Common: $1.32 per share											(61,975	)					(61,975	)

40    |    Southwest Gas Corporation

	Southwest Gas Corporation Equity
	Common Stock					Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
	Shares			Amount
DECEMBER 31, 2013		46,356		$	47,986	$	840,521	$	(41,698	)	$	567,714		$	(2,128	)	$	1,412,395		$	—
Common stock issuances		167			167		10,860											11,027
Redeemable noncontrolling interest attributable to acquisition																					18,952
Net income (loss)												141,126			(129	)		140,997			151
Fair value accretion (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 9)									(9,913	)								(9,913	)
Amounts reclassified to net income, net of tax (Notes 5 and 12)									2,073									2,073
Dividends declared Common: $1.46 per share												(68,715	)					(68,715	)
DECEMBER 31, 2014		46,523	*	$	48,153	$	851,381	$	(50,175	)	$	639,164		$	(2,257	)	$	1,486,266		$	20,042

* At December 31, 2014, 2.7 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 36,000 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 wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co., Link-Line, W.S. Nicholls, and Brigadier.

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 the 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.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co., completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Additional consideration will be paid or accrued through the true-up period. The acquisition extends 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 6 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”) that provides construction and maintenance services for the Canadian utility industry, with operations primarily in Ontario, Canada; (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania as a specialty midstream pipeline contractor (“Brigadier”).

42    |    Southwest Gas Corporation

In October 2014, upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating a holding company, a direct subsidiary of Carson Water Company. In January 2015, the holding company was renamed Centuri. In addition, two direct subsidiaries exist under Centuri: Vistus Construction Group Inc. (“Vistus”, U.S. operations) and Lynxus Construction Group Inc. (“Lynxus”, Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line and W.S. Nicholls are subsidiaries of Lynxus.

Lynxus, including its subsidiaries of Link-Line, W.S. Nicholls, WSN Construction and WSN Industries will be consolidated under the voting interest method of accounting. Brigadier will be consolidated under the voting interest method.

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) as a majority-owned subsidiary. Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The Company’s investment in Western is not significant in relation to its total assets included in the Consolidated Balance Sheets. At December 31, 2014, Centuri’s investment in Western is $14.7 million and its maximum exposure to loss as a result of its involvement with the entity is estimated at $20.8 million, including obligations under a construction bonding arrangement under which Centuri has guaranteed the performance on certain projects of Western. 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, 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. The equity method investment in Western is included in Other Property and Investments in the 2014 Consolidated Balance Sheet.

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):

	2014			2013
Centuri property, equipment, and intangibles	$	405		$	320
Centuri accumulated provision for depreciation and amortization		(187	)		(163	)
Net cash surrender value of COLI policies		99			93
Other property		10			11
Total	$	327		$	261

Southwest Gas Corporation    |     43

Restricted Cash.    A construction bond that was required to be in place during the completion of one of Centuri’s construction projects is classified in the Consolidated Balance Sheets as restricted cash. The project is expected to be completed within one year. The restricted cash was acquired in conjunction with the acquisition of construction services businesses. See Note 15 – Acquisition of Construction Services Businesses for more information.

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 inventory and operating supplies of $23 million in 2014 and $21 million in 2013.

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, 2014, 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, 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.

During 2013 and 2014, approximately $9.3 million and $8.1 million, respectively, of customer advances, upon contract expiration, were applied as contributions toward utility construction activity and represent a non-cash investing activity. Additionally, in conjunction with the acquisition, the Company acquired several capital leases. During 2014 and after the acquisition date, an additional capital lease obligation was entered into and represents a non-cash financing inflow activity of $204,000. The associated capital lease asset represents a non-cash investing outflow activity of $204,000. In association with the acquisition, cash flows from investing activities includes an $18.9 million non-cash investing outflow due to equity to the noncontrolling interest in a subsidiary to acquire businesses. In addition, a non-cash investing outflow activity of $10.8 million related to an increase in an acquisition consideration payable is included.

Inventories.    Inventories are carried at weighted average cost and include natural gas stored underground, liquefied natural gas storage and materials and supplies.

44    |    Southwest Gas Corporation

Goodwill.    The construction services segment includes Goodwill of $133 million in 2014 ($125 million related to the recent acquisition, which is net of approximately $5 million due to foreign currency exchange translation adjustments between the acquisition date and the end of the year). The December 31, 2014 and 2013 Goodwill amounts shown in the Consolidated Balance Sheets include approximately $8 million of Goodwill recognized when Southwest first acquired NPL Construction Co. and is associated with the construction services segment. Goodwill of $10 million in both 2014 and 2013 is associated with the natural gas operations segment. Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill. No impairment was recorded in 2014.

Intangible Assets.    Intangible assets 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 have finite lives and are described in Notes 2 and 15.

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’s (“SEC”) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):

	December 31, 2014		December 31, 2013
Accumulated removal costs	$	304,000	$	279,000

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. In connection with significant changes in estimated costs to complete a

Southwest Gas Corporation    |     45

large fixed-price contract, construction services results for 2012 reflected a pretax loss of $15 million ($0.20 per share, after tax). The estimated cost changes that resulted in the loss recognized included reductions in projected productivity and higher costs of restoration work. During 2013, profitability on this contract was minimal and as of December 31, 2013, this fixed-price contract was substantially complete. 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.

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.

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.

	2014		2013		2012
(In thousands)
AFUDC:
Debt portion	$	1,228	$	1,260	$	1,129
Equity portion		1,995		2,274		1,943
AFUDC capitalized as part of utility plant	$	3,223	$	3,534	$	3,072

46    |    Southwest Gas Corporation

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):

	2014			2013			2012
Change in COLI policies	$	5,300		$	12,400		$	6,600
Interest income		2,602			461			924
Pipe replacement costs		—			(132	)		(2,680	)
Foreign currency transaction gain (loss)		(178	)		—			—
Miscellaneous income and (expense)		(617	)		(429	)		(433	)
Total other income (deductions)	$	7,107		$	12,300		$	4,411

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

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, the amounts of which are not material, are included in other income (expense) within net income. 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.    In connection with the ownership structure of Centuri and its subsidiary entities, a redeemable noncontrolling interest exists in Lynxus. The Company concluded that this noncontrolling interest meets the definition of a participating security in connection with Accounting Standards Codification (“ASC”) Topic 260, as a result of dividend participation rights of the noncontrolling interest that are different than the underlying proportional ownership interest. Related provisions of ASC 260 would require consideration of the participation right in computing earnings per share. However, as earnings are already attributed to the noncontrolling interest equivalent to the participation right, taking an additional adjustment in computing basic earnings per share would duplicate the economic impact associated with the participating security. Furthermore, as net income attributable to common shareholders of Southwest Gas Corporation has already been adjusted for the attribution of income to the noncontrolling interest, the Company concluded that a diluted earnings per share calculation, assuming exchange of the ownership shares of the noncontrolling interest in Lynxus, for ownership shares in Centuri, would not produce a different result than that which results from computing basic earnings per share. The noncontrolling interest is also redeemable for fair value at specified dates in the future. No adjustment will be made to the

Southwest Gas Corporation    |     47

Company’s income attributable to common shareholders, in computing earnings per share, to reflect changes in the redemption price, as redemption at fair value is not considered an economic distribution different from other common stockholders. See also Note 15 – Acquisition of Construction Services Businesses and Note 16 – Construction Services Noncontrolling Interests.

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.

	2014		2013		2012
(In thousands)
Average basic shares		46,494		46,318		46,115
Effect of dilutive securities:
Stock options		17		26		42
Performance shares		215		231		254
Restricted stock units		218		183		144
Average diluted shares		46,944		46,758		46,555

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. The core principle of the update is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. The Company plans to adopt this update, as required, on January 1, 2017 for interim and annual reporting periods. Early adoption is not permitted. The Company is evaluating what impact this standard might have on its consolidated financial statements and disclosures. Additionally, the power and utilities industry as a whole assembled a task force for purposes of considering unique circumstances that relate to our industry and for communicating those industry considerations to the American Institute of Certified Public Accountants. Those undertakings are ongoing.

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 asses 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 is not expected to have a material impact on the Company’s disclosures.

48    |    Southwest Gas Corporation

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.

Reclassifications.    Certain reclassifications were made to the prior year’s financial information included in the Consolidated Balance Sheets (goodwill is identified separately from Deferred charges and other assets) in order to present the prior-year information on a basis comparable with the current year’s presentation, with no impact to total assets overall.

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2014 and 2013 was as follows (thousands of dollars):

December 31,	2014			2013
Gas plant:
Storage	$	22,531		$	21,282
Transmission		312,300			313,306
Distribution		4,655,640			4,410,598
General		356,072			324,490
Software and software-related intangibles		196,035			168,815
Other		14,021			13,978
		5,556,599			5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413
Net utility plant	$	3,658,383		$	3,486,108

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

	2014		2013		2012
Depreciation and amortization expense	$	194,360	$	185,283	$	182,612

Included in the figures above is amortization of intangibles of $11.7 million in 2014, $10.3 million in 2013, and $9.3 million in 2012.

Operating Leases and Rentals.    In July 2014, the Company purchased for $16.5 million a portion of its corporate headquarters office complex in Las Vegas that it had previously leased. With the completion of the purchase, the lease terminated.

Southwest Gas Corporation    |     49

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):

	2014		2013		2012
Southwest Gas	$	5,330	$	8,308	$	7,762
Centuri		30,012		27,118		24,054
Consolidated rental payments/lease expense	$	35,342	$	35,426	$	31,816

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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	5,957
2016		4,236
2017		2,532
2018		1,582
2019		912
Thereafter		831
Total minimum lease payments	$	16,050

Capital Leases.    Centuri leases certain construction equipment. These leases are considered capital leases. The amount of capital leases of equipment as of December 31, 2014 and 2013 is as follows (thousands of dollars):

December 31,	2014			2013
Capital leases of equipment	$	5,763		$	—
Less: accumulated amortization		(287	)		—
Net capital leases	$	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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	1,690
2016		1,632
2017		813
2018		591
2019		—
Thereafter		—
		4,726
Less: amount representing interest		(497	)
Total minimum lease payments	$	4,229

50    |    Southwest Gas Corporation

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

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

	December 31, 2014
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, 2011	$	3,182
Additions charged to expense		2,471
Accounts written off, less recoveries		(3,149	)
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

At December 31, 2014, the construction services segment (Centuri) had $142 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs have been insignificant and are not reflected in the table above.

Southwest Gas Corporation    |     51

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,	2014			2013
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	390,293		$	249,985
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,425			160
Deferred purchased gas costs (3)		87,556			18,217
Accrued purchased gas costs (4)		2,600			31,500
Unamortized premium on reacquired debt (5)		20,478			19,614
Other (6)		72,132			48,945
		578,484			368,421
Regulatory liabilities:
Accumulated removal costs		(304,000	)		(279,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		—			(981	)
Deferred gain on southern Nevada division operations facility (7)		(115	)		(253	)
Unamortized gain on reacquired debt (8)		(10,862	)		(11,398	)
Other (9)		(34,233	)		(26,482	)
Net regulatory assets	$	229,274		$	50,307

(1) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovery period is greater than five years. (See Note 9).

(2) The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the 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 12).

Instrument	Balance Sheet Location	2014		2013
Swaps	Deferred charges and other assets	$	363	$	4
Swaps	Prepaids and other current assets		5,062		156
Swaps	Other current liabilities		—		(801	)
Swaps	Other deferred credits		—		(180	)

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

(4) Included in Prepaids and other current assets on the Consolidated Balance Sheets. Balance recovered or refunded on an ongoing basis.

52    |    Southwest Gas Corporation

(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) Balance was originally being amortized over a four-year period beginning in the fourth quarter of 2009. As a result of the most recent Nevada general rate case, the amortization period was extended through October 2015.

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

(9) Other regulatory liabilities includes 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 and Redeemable Noncontrolling Interest.

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

	2014									2013									2012
	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
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(135	)		220			355			(135	)		220			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			(329	)		538
Amortization of net actuarial (gain)/loss		23,656			(8,989	)		14,667			34,177			(12,987	)		21,190			25,597			(9,727	)		15,870
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)		42,771			(16,253	)		26,518
Pension plans other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973			(8,041	)		3,056			(4,985	)
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		—			—			—			—			—			—			2,959			(1,125	)		1,834
Amounts reclassified into net income		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			2,801			(1,064	)		1,737
FSIRS other comprehensive income (loss)		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			5,760			(2,189	)		3,571
Foreign currency translation adjustments:
Translation adjustments		(659	)		—			(659	)		—			—			—			—			—			—
Foreign currency other comprehensive income (loss)		(659	)		—			(659	)		—			—			—			—			—			—
Total other comprehensive income (loss)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047		$	(2,281	)	$	867		$	(1,414	)

(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.

54    |    Southwest Gas Corporation

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	$	33,000
SERP net actuarial loss		1,300
PBOP net actuarial loss		300
PBOP prior service cost		1,300

Approximately $2.1 million of previously realized losses (net of tax) related to the forward-starting interest rate swaps (“FSIRS”), included in AOCI at December 31, 2014, 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 9)									FSIRS (Note 12)									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, 2013	$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	—		$	—	$	—		$	(41,698	)
Net actuarial gain/(loss)		(173,646	)		65,985			(107,661	)		—			—			—			—			—		—			(107,661	)
Translation adjustments		—			—			—			—			—			—			(659	)		—		(659	)		(659	)
Other comprehensive income before reclassi fications		(173,646	)		65,985			(107,661	)		—			—			—			(659	)		—		(659	)		(108,320	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,345			(1,272	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		355			(135	)		220			—			—			—			—			—		—			220
Amortization of net actuarial loss (2)		23,656			(8,989	)		14,667			—			—			—			—			—		—			14,667
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			—			—		—			(4,130	)
Regulatory adjustment (3)		140,308			(53,317	)		86,991			—			—			—			—			—		—			86,991
Net current period other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(659	)		—		(659	)		(8,499	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(22	)		—		(22	)		(22	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(637	)		—		(637	)		(8,477	)
Ending Balance AOCI December 31, 2014	$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)

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(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 9 – Pension and Other Postretirement Benefits for additional details).

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

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, 2014 and 2013:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2014			2013
Net actuarial (loss) gain	$	(439,131	)	$	(289,141	)
Prior service cost		(8,373	)		(2,067	)
Less: amount recognized in regulatory assets		390,293			249,985
Recognized in AOCI	$	(57,211	)	$	(41,223	)

See Note 9 – Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 12 – Derivatives and Fair Value Measurements for more information on the FSIRS.

Note 6 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2014 and December 31, 2013 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 utilizes 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.

56    |    Southwest Gas Corporation

December 31,	2014					2013
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	133,403	$	125,000		$	130,953
Notes, 6.1%, due 2041		125,000			157,290		125,000			141,873
Notes, 3.875%, due 2022		250,000			262,030		250,000			252,485
Notes, 4.875%, due 2043		250,000			280,903		250,000			257,280
8% Series, due 2026		75,000			102,296		75,000			96,263
Medium-term notes, 7.59% series, due 2017		25,000			27,573		25,000			28,741
Medium-term notes, 7.78% series, due 2022		25,000			31,144		25,000			30,586
Medium-term notes, 7.92% series, due 2027		25,000			33,695		25,000			31,497
Medium-term notes, 6.76% series, due 2027		7,500			9,156		7,500			8,468
Unamortized discount		(5,223	)				(5,560	)
		902,277					901,940
Revolving credit facility and commercial paper		150,000			150,000		10,000			10,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
5.25% 2003 Series D, due 2038		20,000			20,277		20,000			20,150
5.25% 2004 Series A, due 2034		—			—		65,000			64,522
5.00% 2004 Series B, due 2033		31,200			31,223		31,200			30,284
4.85% 2005 Series A, due 2035		100,000			100,071		100,000			95,192
4.75% 2006 Series A, due 2036		24,855			25,399		24,855			22,974
Unamortized discount		(1,943	)				(2,776	)
		374,112					438,279
Centuri secured revolving credit and term loan facility		199,267			200,341		—			—
Centuri other debt obligations		31,128			31,127		42,213			42,119
		1,656,784					1,392,432
Less: current maturities		(19,192	)				(11,105	)
Long-term debt, less current maturities	$	1,637,592				$	1,381,327

In March 2014, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2017, but was extended to March 2019. Southwest will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. In addition to extending the credit facility, among other amendments, the applicable margins and unused commitment fees were reduced and the Pricing Level definitions were modified. Interest rates for the credit facility are calculated at either the

Southwest Gas Corporation    |     57

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, 2014, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2014, $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 1.21% at December 31, 2014. Borrowings under the credit facility ranged from none during the first and second quarters of 2014 to a high of $165 million during November and December 2014. With regard to the short-term portion of the credit facility, there was $5 million outstanding at December 31, 2014 and no borrowings outstanding at December 31, 2013. (See Note 7 – Short-Term Debt).

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

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, 2014, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.65% at December 31, 2014.

In October 2014, construction services subsidiaries of the Company entered into a $300 million secured revolving credit and term loan facility. The facility is scheduled to expire in October 2019 and replaces the previous $75 million credit facility, which was scheduled to expire in June 2015. The 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, 2014 totaled $477 million.

Interest rates for Centuri’s $300 million secured 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 credit facility ranged from a low of $199 million during December 2014 to a high of $232 million during October 2014. All amounts outstanding are considered long-term borrowings. The outstanding amount on the facility at December 31, 2014 includes term loans in the amount of $142 million. The effective interest rate on the facility was 3.31% at December 31, 2014.

In November 2014, Southwest’s $65 million 2004 5.25% Series A fixed-rate IDRBs (originally due in 2034) were redeemed at par plus accrued interest.

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

	December 31, 2014			December 31, 2013
2003 Series A		0.85	%		1.43	%
2008 Series A		0.90	%		1.41	%
2009 Series A		0.89	%		1.01	%
Tax-exempt Series A		0.84	%		1.07	%

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):

2015	$	19,192
2016		20,991
2017		43,899
2018		16,985
2019		304,328

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, 2014, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $1.9 billion in additional debt and meet the leverage ratio requirement. The Company has at least $900 million 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, 2014, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $88 million in additional debt and meet the leverage ratio requirement. Centuri has at least $35 million of cushion in equity relating to the minimum fixed charge ratio coverage requirement.

Note 7 – Short-Term Debt

As discussed in Note 6, Southwest has a $300 million credit facility that is scheduled to expire in March 2019, of which $150 million has been designated by management for working capital purposes. The Company had $5 million in short-term borrowings outstanding at December 31, 2014 and no short-term borrowings outstanding at December 31, 2013. The effective interest rate on the short-term portion of the credit facility was 1.13% at December 31, 2014.

Note 8 – 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.

Southwest Gas Corporation    |     59

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 2014 to July 2015, these liability insurance policies require Southwest to be responsible for the first $1 million dollars (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. 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.

Note 9 – 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):

	2014		2013		2012
Employee Investment Plan cost	$	4,816	$	4,850	$	4,707

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 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 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.

In accordance with regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities, 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.

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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, 2014, 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.

U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on December 31 of each year and expected to be available during the period to maturity of the pension benefits. 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 lower interest rate environment for high-quality fixed income investments, the Company reduced the discount rate at December 31, 2014 from 2013. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also lowered (consistent with management’s expectations overall). The asset return assumption (which impacts the following year’s expense) was not changed. The rates are presented in the table below:

	December 31, 2014			December 31, 2013
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%
Asset return assumption		7.75	%		7.75	%

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A landmark change to a new actuarial mortality table by the Society of Actuaries, which takes into account longer life spans for plan participants and forms a new basis for retirement plan obligations in the U.S., will significantly increase the expense level for 2015. It also negatively impacts the funded status of the plan at the end of 2014. Pension expense for 2015 is estimated to increase by $10 million compared to 2014 because of the extended mortality assumption and lower 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.

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

	2014									2013
	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)	$	886,714		$	36,143		$	58,020		$	902,812		$	37,373		$	59,704
Service cost		21,360			292			1,101			23,056			373			1,220
Interest cost		43,440			1,745			2,829			37,607			1,535			2,482
Plan amendments		—			—			6,661			—			—			—
Actuarial loss (gain)		144,606			5,459			4,567			(44,768	)		(661	)		(4,073	)
Benefits paid		(35,880	)		(2,463	)		(976	)		(31,993	)		(2,477	)		(1,313	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,060,240			41,176			72,202			886,714			36,143			58,020
Change in plan assets
Market value of plan assets at beginning of year		719,944			—			42,314			609,750			—			35,250
Actual return on plan assets		34,732			—			2,859			96,187			—			7,319
Employer contributions		36,000			2,463			—			46,000			2,477			169
Benefits paid		(35,880	)		(2,463	)		(281	)		(31,993	)		(2,477	)		(424	)
Market value of plan assets at end of year		754,796			—			44,892			719,944			—			42,314
Funded status at year end	$	(305,444	)	$	(41,176	)	$	(27,310	)	$	(166,770	)	$	(36,143	)	$	(15,706	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.25	%		4.25	%		4.25	%		5.00	%		5.00	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		2.75	%		N/A			3.25	%		3.25	%		N/A

Estimated funding for the plans above during calendar year 2015 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.

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

	December 31, 2014		December 31, 2013
Retirement plan	$	886,215	$	794,919
SERP		39,125		33,894

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

	2015	2016	2017	2018		2019		2020-2024
Pension	$ 39.1	$41.3	$43.1		$45.3		$47.5		$272.7
PBOP	3.3	3.6	3.8		4.0		4.1		20.4
SERP	2.6	2.6	2.6		2.6		2.6		13.0

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 6% declining to 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
	2014			2013			2012			2014			2013			2012			2014			2013			2012
(Thousands of dollars)
Service cost	$	21,360		$	23,056		$	20,319		$	292		$	373		$	274		$	1,101		$	1,220		$	977
Interest cost		43,440			37,607			38,266			1,745			1,535			1,629			2,829			2,482			2,547
Expected return on plan assets		(53,342	)		(49,840	)		(45,780	)		—			—			—			(3,264	)		(2,824	)		(2,404	)
Amortization of prior service cost		—			—			—			—			—			—			355			355			—
Amortization of transition obligation		—			—			—			—			—			—			—			—			867
Amortization of net actuarial loss		22,873			32,261			23,883			783			971			683			—			945			1,031
Net periodic benefit cost	$	34,331		$	43,084		$	36,688		$	2,820		$	2,879		$	2,586		$	1,021		$	2,178		$	3,018
Weighted-average assumptions (net benefit cost)
Discount rate		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%
Expected return on plan assets		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		2.75	%		3.00	%		3.25	%		2.75	%		3.00	%		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

	2014												2013												2012
	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)	$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)	$	74,853		$	70,016		$	4,111		$	726
Amortization of prior service cost (b)		(355	)		—			—			(355	)		(355	)		—			—			(355	)		—			—			—			—
Amortization of transition obligation (b)		—			—			—			—			—			—			—			—			(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)		(25,597	)		(23,883	)		(683	)		(1,031	)
Prior service cost		6,661			—			—			6,661			—			—			—			—			2,423			—			—			2,423
Regulatory adjustment		(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868			(42,771	)		(41,520	)		—			(1,251	)
Recognized in other comprehensive
(income) loss		15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—			8,041			4,613			3,428			—
Net periodic benefit costs recognized in net income		38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178			42,292			36,688			2,586			3,018
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178		$	50,333		$	41,301		$	6,014			$3,018

The table above discloses the net gain or loss, prior service cost, and transition amount 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.

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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, 2014 and December 31, 2013. The SERP has no assets. There were no transfers between Levels 1 and 2 during 2014.

	December 31, 2014						December 31, 2013
	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	$	6,661	$	198	$	6,859	$	8,224	$	244	$	8,468
Capital equipment		2,222		66		2,288		3,891		115		4,006
Chemicals/materials		5,233		155		5,388		8,228		244		8,472
Consumer goods		41,731		1,238		42,969		54,329		1,611		55,940
Energy and mining		18,502		549		19,051		36,126		1,071		37,197
Finance/insurance		20,685		613		21,298		37,643		1,116		38,759
Healthcare		37,846		1,122		38,968		40,426		1,199		41,625
Information technology		25,881		767		26,648		24,636		731		25,367
Services		28,846		855		29,701		31,212		926		32,138
Telecommunications/internet/media		18,498		549		19,047		24,270		720		24,990
Other		10,958		325		11,283		16,455		488		16,943
Real estate investment trusts		5,713		169		5,882		5,779		171		5,950
Mutual funds		86,159		24,567		110,726		76,764		22,495		99,259
Government fixed income securities		44,694		1,325		46,019		34,495		1,023		35,518
Preferred securities		568		17		585		—		—		—
Total Level 1 Assets (1)	$	354,197	$	32,515	$	386,712	$	402,478	$	32,154	$	434,632
Level 2 – Significant other observable inputs
Commercial paper	$	—	$	—	$	—	$	1,411	$	42	$	1,453
Government fixed income and mortgage backed securities		48,312		1,433		49,745		49,298		1,462		50,760
Corporate fixed income securities
Asset-backed and mortgage-backed		27,071		803		27,874		20,697		614		21,311
Banking		23,289		691		23,980		19,004		564		19,568
Insurance		6,182		183		6,365		6,481		192		6,673
Utilities		4,232		126		4,358		5,278		156		5,434
Other		23,120		686		23,806		19,649		582		20,231
Pooled funds and mutual funds		11,968		984		12,952		8,111		1,150		9,261
State and local obligations		1,499		44		1,543		1,370		41		1,411
Total Level 2 assets (2)	$	145,673	$	4,950	$	150,623	$	131,299	$	4,803	$	136,102
Level 3 – Significant unobservable inputs
Commingled equity funds	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Level 3 assets (3)	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Plan assets at fair value	$	759,105	$	45,152	$	804,257	$	723,229	$	42,575	$	765,804
Insurance company general account contracts (4)		4,003		—		4,003		4,296		—		4,296
Total Plan assets (5)	$	763,108	$	45,152	$	808,260	$	727,525	$	42,575	$	770,100

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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) Assets not considered Level 1 or Level 2 are valued using assumptions based on the best information available under the circumstances, such as investment manager pricing.

The commingled equity funds include private equity funds that invest in domestic and international securities (predominately Level 1 assets) regularly traded on securities exchanges. These funds are shown in the above table at net asset value. 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.

(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 $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) and $7,842,000 (qualified retirement plan – $7,581,000, PBOP – $261,000) for 2014 and 2013, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

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Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2012	$	127,467
Actual return on plan assets:
Relating to assets still held at the reporting date		21,903
Relating to assets sold during the period		—
Purchases		45,700
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2013		195,070
Actual return on plan assets:
Relating to assets still held at the reporting date		(6,932	)
Relating to assets sold during the period		2,069
Purchases		82,615
Sales		(5,900	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2014	$	266,922

Note 10 – Stock-Based Compensation

At December 31, 2014, 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):

	2014		2013		2012
Stock-based compensation plan expense, net of related tax benefits	$	8,130	$	8,012	$	7,396
Stock-based compensation plan related tax benefits		4,983		4,910		4,533

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 has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years.

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

	2014					2013					2012
	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		52		$	27.57		125		$	28.13		177		$	27.28
Exercised during the year		(16	)		24.31		(72	)		28.44		(52	)		25.25
Forfeited or expired during the year		—			—		(1	)		33.07		—			—
Outstanding and exercisable at year end		36		$	28.97		52		$	27.57		125		$	28.13

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):

	2014		2013		2012
Outstanding and exercisable	$	1,194	$	1,473	$	1,788
Exercised		451		1,402		928

	December 31, 2014		December 31, 2013		December 31, 2012
Market value of Southwest Gas stock	$	61.81	$	55.91	$	42.41

The weighted-average remaining contractual life for outstanding options was one year for 2014. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2014 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$25.00 to $26.10		17		0.5 Years	$	25.71
$29.08 to $33.07		19		1.5 Years	$	31.83

The Company received $379,000 in cash from the exercise of options during 2014 and a corresponding tax benefit of $167,000 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 subject to a final adjustment as determined by the Board of Directors) 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

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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, 2014 (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		323		$	39.16		245		$	38.00
Granted		77			53.73		83			53.73
Dividends		7					7
Forfeited or expired		—			—		—			—
Vested and issued*		(136	)		36.23		(78	)		40.87
Nonvested/unissued at December 31, 2014		271		$	43.71		257		$	41.22

* 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 2013 and 2012 was $44.83 and $41.34, respectively.

As of December 31, 2014, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $2.9 million.

Note 11 – 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,	2014			2013		2012
U.S.	$	221,471		$	222,815	$	207,915
Foreign		(1,950	)		—		—
Total income before income taxes	$	219,521		$	222,815	$	207,915

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

Year Ended December 31,	2014			2013		2012
Current:
Federal	$	1,739		$	3,549	$	2,296
State		5,073			5,107		5,744
Foreign		2,193			—		—
		9,005			8,656		8,040
Deferred:
Federal		71,439			67,414		65,551
State		614			1,872		1,685
Foreign		(2,685	)		—		—
		69,368			69,286		67,236
Total income tax expense	$	78,373		$	77,942	$	75,276

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

Year Ended December 31,	2014			2013			2012
Deferred federal and state:
Property-related items	$	52,814		$	62,737		$	64,249
Purchased gas cost adjustments		15,049			16,189			1,755
Employee benefits		109			(2,769	)		564
All other deferred		2,257			(6,010	)		1,529
Total deferred federal and state		70,229			70,147			68,097
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	69,368		$	69,286		$	67,236

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2012, 2013, and 2014 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2014			2013			2012
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.9			2.4			2.6
Property-related items		0.1			0.1			0.2
Tax credits		(0.5	)		(0.4	)		(0.4	)
Company owned life insurance		(1.0	)		(2.1	)		(1.3	)
All other differences		0.2			—			0.1
Consolidated effective income tax rate		35.7	%		35.0	%		36.2	%

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

December 31,	2014			2013
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	2,146		$	2,679
Employee benefits		31,557			25,591
Alternative minimum tax credit		20,172			19,739
Net operating losses and credits		9,719			15,113
Interest rate swap		8,622			9,893
Other		25,872			22,334
Valuation allowance		(253	)		(200	)
		97,835			95,149
Deferred tax liabilities:
Property-related items, including accelerated depreciation		736,810			694,024
Regulatory balancing accounts		33,736			18,688
Property-related items previously flowed through		28			836
Unamortized ITC		3,410			4,271
Debt-related costs		5,066			4,713
Intangibles		12,792			—
Other		27,572			15,898
		819,414			738,430
Net deferred tax liabilities		721,579			643,281
Current		(2,109	)		(31,130	)
Noncurrent		723,688			674,411
Net deferred tax liabilities	$	721,579		$	643,281

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, various states, and in Canada. The Company is currently under examination in Canada for years 2011 and 2012. With few exceptions, the Company is no longer subject to United States federal, state and local, or Canadian income tax examinations for years before 2010.

At December 31, 2014, the Company has a U.S. federal net operating loss carryforward of $28 million which expires in 2031. The Company also has federal general business credits of $711,000, which begin to expire in 2031. The Company also has U.S. federal net capital loss carryforwards of $494,000, which begin to expire in 2016. At December 31, 2014, the Company has an income tax net operating loss carryforward related to Canadian operations of $1.1 million which expires in 2034.

As of December 31, 2014, 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.

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

	2014		2013
Unrecognized tax benefits at beginning of year	$	—	$	—
Gross increases-tax positions in prior period		305		—
Gross decreases-tax positions in prior period		—		—
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	$	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 limitations, 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, 2014. 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. Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):

	2014		2013		2012
Tax-related interest income	$	—	$	—	$	24

Final and Proposed Income Tax Regulations. In September 2013, the United States Department of the Treasury and the Internal Revenue Service (“IRS”) issued final and proposed regulations for the tax treatment of tangible property. The final regulations include standards for determining whether and when a taxpayer must capitalize costs incurred in acquiring, maintaining, or improving tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, and were eligible for adoption in earlier years under certain

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circumstances. Proposed 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 final and proposed 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.

Note 12 – 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.

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

The fixed-price contracts and Swaps are utilized by Southwest under its ongoing volatility mitigation programs to effectively fix the price on a portion (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2015 through March 2016. 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, 2014		December 31, 2013
Contract notional amounts		5,105		13,571

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, 2014, 2013, and 2012 and their location in the Consolidated Statements of Income (thousands of dollars):

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	2014			2013			2012
Swaps	Net cost of gas sold	$	(2,363	)	$	976		$	(4,854	)
Swaps	Net cost of gas sold		2,363	*		(976	)*		4,854	*
Total		$	—		$	—		$	—

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

In January 2010, 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 fixed-rate debt to replace maturing debt. The first FSIRS terminated in December 2010. The second FSIRS terminated in March 2012. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss (ineffective portion) was recognized in income for either FSIRS during any period, including the period presented in the following table.

Gains (losses) recognized in other comprehensive income for derivatives designated as cash flow hedging instruments:

	Year Ended December 31, 2014		Year Ended December 31, 2013		Year Ended December 31, 2012
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	—	$	—	$	2,959

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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, 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	)
December 31, 2013 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	257	$	(77	)	$	180
Swaps	Prepaids and other current assets		1,054		(253	)		801
Swaps	Other current liabilities		126		(282	)		(156	)
Swaps	Other deferred credits		7		(11	)		(4	)
Total		$	1,444	$	(623	)	$	821

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

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under 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, 2014		Year ended December 31, 2013		Year ended December 31, 2012
(Thousands of dollars)
Paid to counterparties	$	829	$	3,148	$	14,843
Received from counterparties	$	4,713	$	915	$	634

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

December 31, 2014 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	5,062
Swaps	Deferred charges and other assets		363
December 31, 2013 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(180	)
Swaps	Other current liabilities		(801	)
Swaps	Prepaids and other current assets		156
Swaps	Deferred charges and other assets		4

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

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (see Note 9 – Pension and Other Post Retirement Benefits for definitions of the levels of the fair value hierarchy):

Level 2 - Significant other observable inputs

	December 31, 2014			December 31, 2013
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets - Swaps	$	—		$	801
Deferred charges and other assets - Swaps		—			180
Liabilities at fair value:
Other current liabilities - Swaps		(5,062	)		(156	)
Other deferred credits - Swaps		(363	)		(4	)
Net Assets (Liabilities)	$	(5,425	)	$	821

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 13 – 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.

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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, 2014		December 31, 2013
Accounts receivable for Centuri services	$	9,169	$	10,787

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

	December 31, 2014		December 31, 2013
Revenues (a)
United States	$	2,069,513	$	1,950,782
Canada		52,194		—
Total	$	2,121,707	$	1,950,782
Long-lived assets
United States	$	6,021,476		5,674,449
Canada		14,475		—
Total	$	6,035,951	$	5,674,449

(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, 2014 is as follows (thousands of dollars):

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	$	4,657,709	$	567,405	$	(10,599	)	$	5,214,515
Capital expenditures	$	350,025	$	46,873				$	396,898

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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
2012	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,321,728	$	522,676				$	1,844,404
Intersegment sales		—		83,374					83,374
Total	$	1,321,728	$	606,050				$	1,927,778
Interest revenue	$	915	$	9				$	924
Interest expense	$	66,957	$	1,063				$	68,020
Depreciation and amortization	$	186,035	$	37,387				$	223,422
Income tax expense	$	64,973	$	10,303				$	75,276
Segment net income	$	116,619	$	16,712				$	133,331
Segment assets	$	4,204,948	$	283,109				$	4,488,057
Capital expenditures	$	308,951	$	86,761				$	395,712

(a) Construction services segment assets include 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 include 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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Note 14 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
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
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,835		(3,888	)		(4,414	)		62,106
Net income (loss) attributable to Southwest Gas Corporation		78,919		(3,676	)		(4,305	)		62,393
Basic earnings (loss) per common share*		1.71		(0.08	)		(0.09	)		1.35
Diluted earnings (loss) per common share*		1.70		(0.08	)		(0.09	)		1.34

* 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 15 – Acquisition of Construction Services Businesses below regarding an acquisition in the last quarter of 2014 and see Note-16 – Construction Services Noncontrolling Interests regarding allocation of earnings.

Note 15 – Acquisition of Construction Services Businesses

As indicated in Note 1 – Summary of Significant Accounting Policies, under Consolidation, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses for $221 million. Previous owners of the acquired companies retained an approximate 10% interest in the Canadian subsidiaries of Centuri.

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Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed as incurred. The Company’s allocation of the purchase price was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. The final purchase accounting has not yet been completed. Further refinement is expected to occur, including changes to income taxes and intangibles. However, no material changes are expected. The preliminary estimated fair values of assets acquired and liabilities assumed as of October 1, 2014, are as follows (in millions of dollars):

Cash, cash equivalents, and restricted cash	$	3
Contracts receivable and other receivables		62
Property, plant and equipment		17
Other assets		17
Intangible assets		52
Goodwill		130
Total assets acquired		281
Current liabilities		39
Deferred income tax—long-term		17
Other long-term liabilities		4
Net assets acquired	$	221

Acquired contracts receivable and other receivables are expected to be collected.

The preliminary allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill, which is generally not deductible for tax purposes, consists of the value associated with the assembled workforce and consolidation of operations. The business of Brigadier was acquired via asset purchase. Therefore, the $4.9 million of tax-basis goodwill assigned to Brigadier is expected to be deductible for tax purposes. All other goodwill associated with the acquisition is not deductible for tax purposes. At December 31, 2014, the balance of goodwill associated with the acquisition was $125 million after consideration of changes in foreign currency adjustments. At December 31, 2014, other intangible assets totaled $48.2 million (after foreign currency adjustments of $1.9 million and approximately $1.5 million accumulated amortization). Intangible assets (as of December 2014) consist of $500,000 in non-competition agreements (net of approximately $40,000 of accumulated amortization, with a 5-year weighted-average useful life), $36.5 million in customer relationships (net of approximately $550,000 accumulated amortization, with useful lives ranging from 12 to 21 years), $10 million in trade names (net of approximately $250,000 accumulated amortization, with useful lives ranging from 4 to 20 years), and $1.2 million in work backlog (net of approximately $700,000 accumulated

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amortization, with an 8-month useful life). The intangible assets other than goodwill are included in Other property and investments in the Consolidated Balance Sheets. The estimated future amortization of the intangible assets acquired in the acquisition for the next five years is as follows (in thousands):

2015	$	4,615
2016		3,371
2017		3,371
2018		3,123
2019		2,370

In connection with the acquisition, previous owners retained certain ownership rights, specifically, an approximate 10% stock ownership interest in the associated Canadian businesses. However, while the actual ownership interest was approximately 10% of Lynxus (Canadian operations), the terms of the underlying equity agreements include dividend participation rights equal to 3.4% of dividends declared at the level of Centuri. Additionally, these same agreements include, among other terms, the ability of the prior owners to exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021. Furthermore, the equity agreements include an exchange feature such that the noncontrolling ownership interest retained by the parties, in the Canadian subsidiaries, may be convertible into shares equivalent to a 3.4% interest in Centuri (redeemable noncontrolling interest). In consideration of these circumstances and the underlying agreements, it was deemed appropriate to allocate earnings to the redeemable noncontrolling interest at an amount equivalent to approximately 3.4% of total Centuri earnings (rather than based on the actual current proportional ownership). Through this earnings allocation process, approximately 96.6% of Centuri earnings are attributable to the Company. This earnings allocation takes place before the redeemable noncontrolling interest balance, included on the balance sheet, is adjusted based on its redemption value. Adjustments to redemption value through December 31, 2014 impacted retained earnings but not current net income. See also Earnings Per Share included within Note 1, and discussion below regarding adjustment to fair value, as well as Note 16 – Construction Services Noncontrolling Interests for more information.

The unaudited pro forma consolidated financial information for fiscal 2014 and fiscal 2013 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning fiscal 2013) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31,
	2014		2013
Total operating revenues	$	2,295,318	$	2,203,272
Net income attributable to Southwest Gas Corporation	$	149,588	$	143,424
Basic earnings per share	$	3.22	$	3.10
Diluted earnings per share	$	3.19	$	3.07

Acquisition costs of $5 million that were incurred during 2014, and included in construction expenses in the Consolidated Statements of Income, were excluded from the 2014 unaudited pro forma consolidated financial information shown above and included in the 2013 amounts. No material nonrecurring pro forma adjustments directly attributable to the business combination were included in the unaudited pro forma consolidated financial information.

Southwest Gas Corporation    |     81

The pro forma financial information includes assumptions and adjustments made to incorporate various items including, but not limited to, additional interest expense and depreciation and amortization expense, and intercompany eliminations and tax effects, as appropriate. The pro forma financial information has been prepared for comparative purposes only, and is not intended to be indicative of what the Company’s results would have been had the acquisition occurred at the beginning of the periods presented or of the results which may occur in the future, for a number of reasons. These reasons include, but are not limited to, differences between the assumptions used to prepare the pro forma information, potential cost savings from operating efficiencies, and the impact of incremental costs incurred in integrating the businesses.

Actual results from Link-Line, W.S. Nicholls, and Brigadier operations included in the Consolidated Statements of Income since the date of acquisition are as follows (in thousands of dollars):

	Year ended December 31, 2014
Construction revenues	$	54,264
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier	$	1,859

Note 16 – Construction Services Noncontrolling Interests

As discussed in Note 15 – Acquisition of Construction Services Businesses, at the close of the acquisition, previous owners of the acquired companies retained an approximate 10% equity interest in the Canadian businesses that were acquired. The agreement, associated with the approximate 10% indirect equity interest of the sellers, provides special dividend rights which entitle the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri and subject to certain conditions, such interests may become exchangeable for a 3.4% equity interest in Centuri. Additionally, the previous owners may exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021.

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The Company has determined that this noncontrolling interest is a redeemable noncontrolling interest and, in accordance with SEC guidance, is classified as mezzanine equity (temporary equity) in the Consolidated Balance Sheets. The redeemable noncontrolling interest is reported at $20 million, the estimated redemption value as of December 31, 2014. Based on the fair value model employed, the estimated redemption value of the redeemable noncontrolling interest increased by approximately $961,000 during the fourth quarter of 2014. Changes in the value of the redeemable noncontrolling interest will be recognized as they occur and the carrying value will be adjusted accordingly at each quarterly reporting date. Any adjustment to the redemption value impacts retained earnings, but does not impact net income.

	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2013	$	—
Redeemable noncontrolling interest related to acquisition		18,952
Net Income (loss) attributable to redeemable noncontrolling interest		151
Foreign currency exchange translation adjustment		(22	)
Adjustment to redemption value		961
Balance, December 31, 2014	$	20,042

The redemption value of the redeemable noncontrolling interest was determined using a Monte Carlo simulation method. First, a market approach was utilized to determine a construction services enterprise value as of the acquisition date. Potential guideline publicly-traded companies were identified by using a selection criteria, including actively traded equities, their financial solvency, and other factors. Once the guideline companies were determined, enterprise value was calculated using a weighted approach of projected earnings before interest expense and taxes (“EBIT”) and earnings before interest expense, taxes, and depreciation and amortization expense (“EBITDA”). After an estimated fair value was determined, a Monte Carlo simulation was used to assign a value to the noncontrolling interest of the sellers. Other assumptions used in this analysis included dividends, probability of events, and a discount due to lack of control (the sellers do not influence operations).

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.

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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. See Item 9A Controls and Procedures of the 2014 SEC Form 10-K for a discussion regarding the scope of management’s assessment due to the recent acquisition of Link-Line, W.S. Nicholls, and Brigadier, entities which are excluded from management’s report on internal control over financial reporting. The acquired businesses represent 5% of consolidated total assets and 3% of consolidated revenues for the year ended December 31, 2014 and are not significant to the Company’s consolidated financial statements. 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” issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. 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, 2014. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 26, 2015

84    |    Southwest Gas Corporation

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, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

As described in Management’s Report on Internal Control Over Financial Reporting appearing in Item 9A of the Southwest Gas Corporation’s 2014 Annual Report on Form 10-K, management has excluded Link-Line Contractors

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Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. from its assessment of internal control over financial reporting as of December 31, 2014 because it was acquired in a purchase business combination by NPL Construction Co. on October 1, 2014. We have also excluded Link-Line Contractors Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. from our audit of internal control over financial reporting. Link-Line Contractors Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. are wholly-owned subsidiaries whose total assets and total revenues represent 5% and 3%, respectively, of the related consolidated financial statements amounts as of and for the year ended December 31, 2014.

PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 26, 2015

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EX-21.01

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2014

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
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. 333-180045) and Form S-8 (Nos. 333-200835, 333-185354, 333-155581, 333-147952, 333-106762) of Southwest Gas Corporation of our report dated February 26, 2015 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.

/s/ PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 26, 2015

EX-31.01

Exhibit 31.01

Certification

I, Jeffrey W. Shaw, 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 26, 2015

/S/ JEFFREY W. SHAW

Jeffrey W. Shaw

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 26, 2015

/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, 2014 as filed with the Securities and Exchange Commission (the “Report”), I, Jeffrey W. Shaw, the 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 26, 2015

/s/ Jeffrey W. Shaw

Jeffrey W. Shaw

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, 2014 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 26, 2015

/s/ Roy R. Centrella

Roy R. Centrella

Senior Vice President/Chief Financial Officer

XML

Construction Services Noncontrolling Interests (Tables)

12 Months Ended

Dec. 31, 2014

Noncontrolling Interest [Abstract]

Summary of Redeemable Noncontrolling Interest

	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2013	$	—
Redeemable noncontrolling interest related to acquisition		18,952
Net Income (loss) attributable to redeemable noncontrolling interest		151
Foreign currency exchange translation adjustment		(22	)
Adjustment to redemption value		961
Balance, December 31, 2014	$	20,042

XML

Acquisition of Construction Services Businesses - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	Oct. 31, 2014 Business	Dec. 31, 2014 Business	Dec. 31, 2013	Oct. 01, 2014
Business Acquisition [Line Items]
Business acquisition, consideration		$ 221,000,000
Number of business acquisitions	3	3
Goodwill		143,160,000	17,810,000
Construction Services [Member]
Business Acquisition [Line Items]
Goodwill		133,000,000
Brigadier [Member]
Business Acquisition [Line Items]
Goodwill assigned for deductible tax purpose		4,900,000
Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Acquisition [Line Items]
Goodwill		125,000,000		130,000,000
Intangible assets		48,200,000
Foreign currency adjustments		1,900,000
Accumulated amortization		1,500,000
Incurred acquisition costs		5,000,000
Link-Line, W.S. Nicholls, and Brigadier [Member] | Maximum [Member]
Business Acquisition [Line Items]
Indirect equity interest percentage		100.00%
Link-Line, W.S. Nicholls, and Brigadier [Member] | Non-Competition Agreements [Member]
Business Acquisition [Line Items]
Intangible assets		500,000
Accumulated amortization		40,000
Intangible assets useful life		5 years
Link-Line, W.S. Nicholls, and Brigadier [Member] | Customer Relationships [Member]
Business Acquisition [Line Items]
Intangible assets		36,500,000
Accumulated amortization		550,000
Link-Line, W.S. Nicholls, and Brigadier [Member] | Customer Relationships [Member] | Minimum [Member]
Business Acquisition [Line Items]
Intangible assets useful life		12 years
Link-Line, W.S. Nicholls, and Brigadier [Member] | Customer Relationships [Member] | Maximum [Member]
Business Acquisition [Line Items]
Intangible assets useful life		21 years
Link-Line, W.S. Nicholls, and Brigadier [Member] | Trade Names [Member]
Business Acquisition [Line Items]
Intangible assets		10,000,000
Accumulated amortization		250,000
Link-Line, W.S. Nicholls, and Brigadier [Member] | Trade Names [Member] | Minimum [Member]
Business Acquisition [Line Items]
Intangible assets useful life		4 years
Link-Line, W.S. Nicholls, and Brigadier [Member] | Trade Names [Member] | Maximum [Member]
Business Acquisition [Line Items]
Intangible assets useful life		20 years
Link-Line, W.S. Nicholls, and Brigadier [Member] | Work Backlog [Member]
Business Acquisition [Line Items]
Intangible assets		1,200,000
Accumulated amortization		$ 700,000
Intangible assets useful life		8 months
Centuri Construction Group [Member]
Business Acquisition [Line Items]
Indirect equity interest convertible for percentage of holding company equity interest		96.60%
Principal Previous Owners [Member] | Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Acquisition [Line Items]
Indirect equity interest percentage		10.00%
Indirect equity interest dividend rights, percentage of cash dividend paid by Centuri to the Company		3.40%
Description of indirect equity interest		However, while the actual ownership interest was approximately 10% of Lynxus (Canadian operations), the terms of the underlying equity agreements include dividend participation rights equal to 3.4% of dividends declared at the level of Centuri. Additionally, these same agreements include, among other terms, the ability of the prior owners to exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021. Furthermore, the equity agreements include an exchange feature such that the noncontrolling ownership interest retained by the parties, in the Canadian subsidiaries, may be convertible into shares equivalent to a 3.4% interest in Centuri (redeemable noncontrolling interest). In consideration of these circumstances and the underlying agreements, it was deemed appropriate to allocate earnings to the redeemable noncontrolling interest at an amount equivalent to approximately 3.4% of total Centuri earnings (rather than based on the actual current proportional ownership). Through this earnings allocation process, approximately 96.6% of Centuri earnings are attributable to the Company.
Principal Previous Owners [Member] | Link-Line, W.S. Nicholls, and Brigadier [Member] | Construction Services [Member]
Business Acquisition [Line Items]
Indirect equity interest convertible for percentage of holding company equity interest		3.40%
Principal Previous Owners [Member] | Centuri Construction Group [Member]
Business Acquisition [Line Items]
Indirect equity interest percentage		10.00%

XML

Receivables and Related Allowances - Schedule of Percent of Customers by State (Detail)	12 Months Ended
	Dec. 31, 2014
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%

XML

Utility Plant and Leases - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Jul. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Regulated Operations [Abstract]
Amortization of intangibles		$ 11.7	$ 10.3	$ 9.3
Purchase of portion of corporate headquarters office complex	$ 16.5

XML

Short-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Working capital purposes	$ 150,000,000
Short-term borrowings outstanding on the credit facility	5,000,000	0
Effective interest rate on short-term borrowings	1.13%
March 2019 [Member]
Short-term Debt [Line Items]
Current borrowing capacity	$ 300,000,000
Short-term debt expiration date	Mar. 01, 2019

XML

Receivables and Related Allowances - Schedule of Allowance for Uncollectibles (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Receivables [Abstract]
Beginning Balance	$ 1,725	$ 2,504	$ 3,182
Additions charged to expense	4,146	3,583	2,471
Accounts written off, less recoveries	(3,616)	(4,362)	(3,149)
Ending Balance	$ 2,255	$ 1,725	$ 2,504

XML

Pension and Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	$ 39.1
2016	41.3
2017	43.1
2018	45.3
2019	47.5
2020-2024	272.7
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	3.3
2016	3.6
2017	3.8
2018	4.0
2019	4.1
2020-2024	20.4
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
2015	2.6
2016	2.6
2017	2.6
2018	2.6
2019	2.6
2020-2024	$ 13.0

XML

Derivatives and Fair Value Measurements - Paid to and Received from Counterparties for Settlements of Matured Swaps (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Paid to counterparties	$ 829	$ 3,148	$ 14,843
Received from counterparties	$ 4,713	$ 915	$ 634

XML

Utility Plant and Leases - Schedule of Net Utility Plant (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 5,556,599	$ 5,252,469
Less: accumulated depreciation	(1,973,098)	(1,868,504)
Acquisition adjustments, net	550	730
Construction work in progress	74,332	101,413
Net utility plant	3,658,383	3,486,108
Storage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	22,531	21,282
Transmission [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	312,300	313,306
Distribution [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	4,655,640	4,410,598
General [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	356,072	324,490
Software and software-related intangibles [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	196,035	168,815
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 14,021	$ 13,978

XML

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

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):

	2014		2013		2012
Stock-based compensation plan expense, net of related tax benefits	$	8,130	$	8,012	$	7,396
Stock-based compensation plan related tax benefits		4,983		4,910		4,533

Schedule of Stock Options Activity

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

	2014					2013					2012
	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		52		$	27.57		125		$	28.13		177		$	27.28
Exercised during the year		(16	)		24.31		(72	)		28.44		(52	)		25.25
Forfeited or expired during the year		—			—		(1	)		33.07		—			—
Outstanding and exercisable at year end		36		$	28.97		52		$	27.57		125		$	28.13

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):

	2014		2013		2012
Outstanding and exercisable	$	1,194	$	1,473	$	1,788
Exercised		451		1,402		928

Summary of Market Prices of Common Stock

	December 31, 2014		December 31, 2013		December 31, 2012
Market value of Southwest Gas stock	$	61.81	$	55.91	$	42.41

Schedule of Stock Options Outstanding and Exercisable

The following table summarizes information about stock options outstanding at December 31, 2014 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$25.00 to $26.10		17		0.5 Years	$	25.71
$29.08 to $33.07		19		1.5 Years	$	31.83

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, 2014 (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		323		$	39.16		245		$	38.00
Granted		77			53.73		83			53.73
Dividends		7					7
Forfeited or expired		—			—		—			—
Vested and issued*		(136	)		36.23		(78	)		40.87
Nonvested/unissued at December 31, 2014		271		$	43.71		257		$	41.22

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

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Pension and Other Postretirement Benefits - Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net periodic benefit cost	$ 38,172	$ 48,141	$ 42,292
Discount rate	4.25%	5.00%
Expected return on plan assets	7.75%	7.75%
Weighted-average rate of compensation increase	2.75%	3.25%
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service cost	21,360	23,056	20,319
Interest cost	43,440	37,607	38,266
Expected return on plan assets	(53,342)	(49,840)	(45,780)
Amortization of net actuarial loss	22,873	32,261	23,883
Net periodic benefit cost	34,331	43,084	36,688
Qualified Retirement Plan [Member] | Net benefit cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	5.00%	4.25%	5.00%
Expected return on plan assets	7.75%	8.00%	8.00%
Weighted-average rate of compensation increase	3.25%	2.75%	3.00%
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service cost	292	373	274
Interest cost	1,745	1,535	1,629
Amortization of net actuarial loss	783	971	683
Net periodic benefit cost	2,820	2,879	2,586
SERP [Member] | Net benefit cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	5.00%	4.25%	5.00%
Expected return on plan assets	7.75%	8.00%	8.00%
Weighted-average rate of compensation increase	3.25%	2.75%	3.00%
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Service cost	1,101	1,220	977
Interest cost	2,829	2,482	2,547
Expected return on plan assets	(3,264)	(2,824)	(2,404)
Amortization of prior service cost	355	355
Amortization of transition obligation			867
Amortization of net actuarial loss		945	1,031
Net periodic benefit cost	$ 1,021	$ 2,178	$ 3,018
PBOP [Member] | Net benefit cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	5.00%	4.25%	5.00%
Expected return on plan assets	7.75%	8.00%	8.00%

XML

Construction Services Noncontrolling Interests - Summary of Redeemable Noncontrolling Interest (Detail) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014
Redeemable Noncontrolling Interest [Line Items]
Foreign currency exchange translation adjustment		$ (637,000)
Adjustment to redemption value	961,000
Balance, December 31, 2014	20,042,000	20,042,000
Redeemable Noncontrolling Interest (Temporary Equity) [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable noncontrolling interest related to acquisition		18,952,000
Net Income (loss) attributable to redeemable noncontrolling interest		151,000
Foreign currency exchange translation adjustment		(22,000)
Adjustment to redemption value		961,000
Balance, December 31, 2014	$ 20,042,000	$ 20,042,000

XML

Pension and Other Postretirement Benefits - Cost of Retirement Plan (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Employee Investment Plan cost	$ 4,816	$ 4,850	$ 4,707

XML

Stock-Based Compensation - Schedule of Stock Options Outstanding and Exercisable (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
$25.0 to $26.10 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Price, Lower limit	$ 25.00
Range of Exercise Price, Upper limit	$ 26.10
Number outstanding	17
Weighted-remaining average contractual life, years	6 months
Weighted-average exercise price	$ 25.71
$29.08 to $33.07 [Member]
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	19
Weighted-remaining average contractual life, years	1 year 6 months
Weighted-average exercise price	$ 31.83

XML

Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	$ 578,484	$ 368,421
Net regulatory assets	229,274	50,307
Accrued pension and other postretirement benefit costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	390,293	249,985
Unrealized net loss on non-trading derivatives (Swaps) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	5,425	160
Deferred purchased gas costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	87,556	18,217
Accrued purchased gas costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	2,600	31,500
Unamortized premium on reacquired debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	20,478	19,614
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	72,132	48,945
Accumulated removal costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(304,000)	(279,000)
Unrealized net gain on non-trading derivatives (Swaps) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total		(981)
Deferred gain on southern Nevada division operations facility [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(115)	(253)
Unamortized gain on reacquired debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(10,862)	(11,398)
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	$ (34,233)	$ (26,482)

XML

Segment Information - Schedule of Segment Reporting Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total operating revenues	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 488,566	$ 371,799	$ 409,768	$ 657,645	$ 2,121,707	$ 1,950,782	$ 1,927,778
Interest revenue													2,602	461	924
Interest expense													72,069	63,700	68,020
Depreciation and amortization													253,027	236,817	223,422
Income tax expense													78,373	77,942	75,276
Segment net income	58,746	1,970	9,627	70,783	57,303	(2,864)	10,108	80,773	62,393	(4,305)	(3,676)	78,919	141,126	145,320	133,331
Segment assets	5,214,515				4,565,174				4,488,057				5,214,515	4,565,174	4,488,057
Capital expenditures													396,898	364,276	395,712
Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													2,029,519	1,862,629	1,844,404
Intersegment sales [Member]
Segment Reporting Information [Line Items]
Revenues													92,188	88,153	83,374
Gas Operations [Member]
Segment Reporting Information [Line Items]
Total operating revenues													1,382,087	1,300,154	1,321,728
Interest revenue													2,596	456	915
Interest expense													68,299	62,555	66,957
Depreciation and amortization													204,144	193,848	186,035
Income tax expense													63,597	65,377	64,973
Segment net income													116,872	124,169	116,619
Segment assets	4,657,709				4,272,029				4,204,948				4,657,709	4,272,029	4,204,948
Capital expenditures													350,025	314,578	308,951
Gas Operations [Member] | Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													1,382,087	1,300,154	1,321,728
Construction Services [Member]
Segment Reporting Information [Line Items]
Total operating revenues													739,620	650,628	606,050
Interest revenue													6	5	9
Interest expense													3,770	1,145	1,063
Depreciation and amortization													48,883	42,969	37,387
Income tax expense													14,776	12,565	10,303
Segment net income													24,254	21,151	16,712
Segment assets	567,405				293,811				283,109				567,405	293,811	283,109
Capital expenditures													46,873	49,698	86,761
Construction Services [Member] | Revenues from unaffiliated customers [Member]
Segment Reporting Information [Line Items]
Revenues													647,432	562,475	522,676
Construction Services [Member] | Intersegment sales [Member]
Segment Reporting Information [Line Items]
Revenues													92,188	88,153	83,374
Adjustments [Member]
Segment Reporting Information [Line Items]
Segment assets	$ (10,599)				$ (666)								$ (10,599)	$ (666)

XML

Pension and Other Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet and Income Statement (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	$ 173,646	$ (100,345)	$ 74,853
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	886,714	902,812
Service cost	21,360	23,056	20,319
Interest cost	43,440	37,607	38,266
Benefit obligation at end of year (PBO/PBO/APBO)	1,060,240	886,714	902,812
Market value of plan assets, beginning balance	719,944	609,750
Actual return on plan assets	34,732	96,187
Employer contributions	36,000	46,000
Market value of plan assets, ending balance	754,796	719,944	609,750
Funded status at year end	(305,444)	(166,770)
Qualified Retirement Plan [Member] | Change in benefit obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	144,606	(44,768)
Benefits paid	(35,880)	(31,993)
Qualified Retirement Plan [Member] | Change in plan assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Benefits paid	(35,880)	(31,993)
Qualified Retirement Plan [Member] | Benefit obligation [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.25%
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	36,143	37,373
Service cost	292	373	274
Interest cost	1,745	1,535	1,629
Benefit obligation at end of year (PBO/PBO/APBO)	41,176	36,143	37,373
Employer contributions	2,463	2,477
Funded status at year end	(41,176)	(36,143)
SERP [Member] | Change in benefit obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	5,459	(661)
Benefits paid	(2,463)	(2,477)
SERP [Member] | Change in plan assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Benefits paid	(2,463)	(2,477)
SERP [Member] | Benefit obligation [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.25%
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	58,020	59,704
Service cost	1,101	1,220	977
Interest cost	2,829	2,482	2,547
Plan amendments	6,661
Benefit obligation at end of year (PBO/PBO/APBO)	72,202	58,020	59,704
Market value of plan assets, beginning balance	42,314	35,250
Actual return on plan assets	2,859	7,319
Employer contributions		169
Market value of plan assets, ending balance	44,892	42,314	35,250
Funded status at year end	(27,310)	(15,706)
PBOP [Member] | Change in benefit obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	4,567	(4,073)
Benefits paid	(976)	(1,313)
PBOP [Member] | Change in plan assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Benefits paid	$ (281)	$ (424)
PBOP [Member] | Benefit obligation [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Discount rate	4.25%	5.00%

XML

Stock-Based Compensation - Schedule of Stock Options Activity (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of options, Outstanding at the beginning of the year	52	125	177
Number of options, Exercised during the year	(16)	(72)	(52)
Number of options, Forfeited or expired during the year		(1)
Number of options, Outstanding and exercisable at year end	36	52	125
Weighted-average exercise price, Outstanding at the beginning of the year	$ 27.57	$ 28.13	$ 27.28
Weighted-average exercise price, Exercised during the year	$ 24.31	$ 28.44	$ 25.25
Weighted-average exercise price, Forfeited or expired during the year		$ 33.07
Weighted-average exercise price, Outstanding and exercisable at year end	$ 28.97	$ 27.57	$ 28.13

XML

Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets, including insurance contracts	$ 808,260	$ 770,100
Assets at fair value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	804,257	765,804
Insurance company general account contracts (Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Contract value of insurance contracts	4,003	4,296
Level 1 - Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	386,712	434,632
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Agriculture [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	6,859	8,468
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	2,288	4,006
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	5,388	8,472
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	42,969	55,940
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	19,051	37,197
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	21,298	38,759
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	38,968	41,625
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	26,648	25,367
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	29,701	32,138
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Telecommunications/internet/media [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	19,047	24,990
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	11,283	16,943
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	5,882	5,950
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	110,726	99,259
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	46,019	35,518
Level 1 - Quoted prices in active markets for identical financial assets [Member] | Preferred securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	585
Level 2 - Significant other observable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	150,623	136,102
Level 2 - Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	23,806	20,231
Level 2 - Significant other observable inputs [Member] | Commercial paper [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets		1,453
Level 2 - Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	49,745	50,760
Level 2 - Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	27,874	21,311
Level 2 - Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	23,980	19,568
Level 2 - Significant other observable inputs [Member] | Insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	6,365	6,673
Level 2 - Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	4,358	5,434
Level 2 - Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	12,952	9,261
Level 2 - Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,543	1,411
Level 3 - Significant unobservable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	266,922	195,070
Level 3 - Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	266,922	195,070
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets, including insurance contracts	763,108	727,525
Qualified Retirement Plan [Member] | Assets at fair value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	759,105	723,229
Qualified Retirement Plan [Member] | Insurance company general account contracts (Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Contract value of insurance contracts	4,003	4,296
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	354,197	402,478
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Agriculture [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	6,661	8,224
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	2,222	3,891
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	5,233	8,228
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	41,731	54,329
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	18,502	36,126
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	20,685	37,643
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	37,846	40,426
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	25,881	24,636
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	28,846	31,212
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Telecommunications/internet/media [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	18,498	24,270
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	10,958	16,455
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	5,713	5,779
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	86,159	76,764
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	44,694	34,495
Qualified Retirement Plan [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Preferred securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	568
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	145,673	131,299
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	23,120	19,649
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Commercial paper [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets		1,411
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	48,312	49,298
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	27,071	20,697
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	23,289	19,004
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	6,182	6,481
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	4,232	5,278
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	11,968	8,111
Qualified Retirement Plan [Member] | Level 2 - Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,499	1,370
Qualified Retirement Plan [Member] | Level 3 - Significant unobservable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	259,235	189,452
Qualified Retirement Plan [Member] | Level 3 - Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	259,235	189,452
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets, including insurance contracts	45,152	42,575
PBOP [Member] | Assets at fair value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	45,152	42,575
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	32,515	32,154
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Agriculture [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	198	244
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	66	115
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	155	244
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,238	1,611
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	549	1,071
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	613	1,116
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,122	1,199
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	767	731
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	855	926
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Telecommunications/internet/media [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	549	720
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	325	488
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	169	171
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	24,567	22,495
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,325	1,023
PBOP [Member] | Level 1 - Quoted prices in active markets for identical financial assets [Member] | Preferred securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	17
PBOP [Member] | Level 2 - Significant other observable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	4,950	4,803
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	686	582
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Commercial paper [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets		42
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	1,433	1,462
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	803	614
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	691	564
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Insurance [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	183	192
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	126	156
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	984	1,150
PBOP [Member] | Level 2 - Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	44	41
PBOP [Member] | Level 3 - Significant unobservable inputs [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	7,687	5,618
PBOP [Member] | Level 3 - Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Fair value of plan assets	$ 7,687	$ 5,618

XML

Stock-Based Compensation - Schedule of Aggregate Intrinsic Value of Outstanding and Exercisable Options (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Outstanding and exercisable	$ 1,194	$ 1,473	$ 1,788
Exercised	$ 451	$ 1,402	$ 928

XML

Pension and Other Postretirement Benefits - Schedule of Accumulated Benefit Obligation (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation	$ 886,215	$ 794,919
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Accumulated benefit obligation	$ 39,125	$ 33,894

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

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 wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co., Link-Line, W.S. Nicholls, and Brigadier.

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 the 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.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co., completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Additional consideration will be paid or accrued through the true-up period. The acquisition extends 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 6 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”) that provides construction and maintenance services for the Canadian utility industry, with operations primarily in Ontario, Canada; (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania as a specialty midstream pipeline contractor (“Brigadier”).

In October 2014, upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating a holding company, a direct subsidiary of Carson Water Company. In January 2015, the holding company was renamed Centuri. In addition, two direct subsidiaries exist under Centuri: Vistus Construction Group Inc. (“Vistus”, U.S. operations) and Lynxus Construction Group Inc. (“Lynxus”, Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line and W.S. Nicholls are subsidiaries of Lynxus.

Lynxus, including its subsidiaries of Link-Line, W.S. Nicholls, WSN Construction and WSN Industries will be consolidated under the voting interest method of accounting. Brigadier will be consolidated under the voting interest method.

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) as a majority-owned subsidiary. Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The Company’s investment in Western is not significant in relation to its total assets included in the Consolidated Balance Sheets. At December 31, 2014, Centuri’s investment in Western is $14.7 million and its maximum exposure to loss as a result of its involvement with the entity is estimated at $20.8 million, including obligations under a construction bonding arrangement under which Centuri has guaranteed the performance on certain projects of Western. 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, 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. The equity method investment in Western is included in Other Property and Investments in the 2014 Consolidated Balance Sheet.

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):

	2014			2013
Centuri property, equipment, and intangibles	$	405		$	320
Centuri accumulated provision for depreciation and amortization		(187	)		(163	)
Net cash surrender value of COLI policies		99			93
Other property		10			11
Total	$	327		$	261

Restricted Cash

Restricted Cash.    A construction bond that was required to be in place during the completion of one of Centuri’s construction projects is classified in the Consolidated Balance Sheets as restricted cash. The project is expected to be completed within one year. The restricted cash was acquired in conjunction with the acquisition of construction services businesses. See Note 15 – Acquisition of Construction Services Businesses for more information.

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 inventory and operating supplies of $23 million in 2014 and $21 million in 2013.

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, 2014, 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, 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.

During 2013 and 2014, approximately $9.3 million and $8.1 million, respectively, of customer advances, upon contract expiration, were applied as contributions toward utility construction activity and represent a non-cash investing activity. Additionally, in conjunction with the acquisition, the Company acquired several capital leases. During 2014 and after the acquisition date, an additional capital lease obligation was entered into and represents a non-cash financing inflow activity of $204,000. The associated capital lease asset represents a non-cash investing outflow activity of $204,000. In association with the acquisition, cash flows from investing activities includes an $18.9 million non-cash investing outflow due to equity to the noncontrolling interest in a subsidiary to acquire businesses. In addition, a non-cash investing outflow activity of $10.8 million related to an increase in an acquisition consideration payable is included.

Inventories

Inventories.    Inventories are carried at weighted average cost and include natural gas stored underground, liquefied natural gas storage and materials and supplies.

Goodwill

Goodwill.    The construction services segment includes Goodwill of $133 million in 2014 ($125 million related to the recent acquisition, which is net of approximately $5 million due to foreign currency exchange translation adjustments between the acquisition date and the end of the year). The December 31, 2014 and 2013 Goodwill amounts shown in the Consolidated Balance Sheets include approximately $8 million of Goodwill recognized when Southwest first acquired NPL Construction Co. and is associated with the construction services segment. Goodwill of $10 million in both 2014 and 2013 is associated with the natural gas operations segment. Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill. No impairment was recorded in 2014.

Intangible Assets

Intangible Assets.    Intangible assets 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 have finite lives and are described in Notes 2 and 15.

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’s (“SEC”) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):

	December 31, 2014		December 31, 2013
Accumulated removal costs	$	304,000	$	279,000

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. In connection with significant changes in estimated costs to complete a large fixed-price contract, construction services results for 2012 reflected a pretax loss of $15 million ($0.20 per share, after tax). The estimated cost changes that resulted in the loss recognized included reductions in projected productivity and higher costs of restoration work. During 2013, profitability on this contract was minimal and as of December 31, 2013, this fixed-price contract was substantially complete. 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.

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.

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.

	2014		2013		2012
(In thousands)
AFUDC:
Debt portion	$	1,228	$	1,260	$	1,129
Equity portion		1,995		2,274		1,943
AFUDC capitalized as part of utility plant	$	3,223	$	3,534	$	3,072

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):

	2014			2013			2012
Change in COLI policies	$	5,300		$	12,400		$	6,600
Interest income		2,602			461			924
Pipe replacement costs		—			(132	)		(2,680	)
Foreign currency transaction gain (loss)		(178	)		—			—
Miscellaneous income and (expense)		(617	)		(429	)		(433	)
Total other income (deductions)	$	7,107		$	12,300		$	4,411

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

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, the amounts of which are not material, are included in other income (expense) within net income. 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.    In connection with the ownership structure of Centuri and its subsidiary entities, a redeemable noncontrolling interest exists in Lynxus. The Company concluded that this noncontrolling interest meets the definition of a participating security in connection with Accounting Standards Codification (“ASC”) Topic 260, as a result of dividend participation rights of the noncontrolling interest that are different than the underlying proportional ownership interest. Related provisions of ASC 260 would require consideration of the participation right in computing earnings per share. However, as earnings are already attributed to the noncontrolling interest equivalent to the participation right, taking an additional adjustment in computing basic earnings per share would duplicate the economic impact associated with the participating security. Furthermore, as net income attributable to common shareholders of Southwest Gas Corporation has already been adjusted for the attribution of income to the noncontrolling interest, the Company concluded that a diluted earnings per share calculation, assuming exchange of the ownership shares of the noncontrolling interest in Lynxus, for ownership shares in Centuri, would not produce a different result than that which results from computing basic earnings per share. The noncontrolling interest is also redeemable for fair value at specified dates in the future. No adjustment will be made to the Company’s income attributable to common shareholders, in computing earnings per share, to reflect changes in the redemption price, as redemption at fair value is not considered an economic distribution different from other common stockholders. See also Note 15 – Acquisition of Construction Services Businesses and Note 16 – Construction Services Noncontrolling Interests.

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.

	2014		2013		2012
(In thousands)
Average basic shares		46,494		46,318		46,115
Effect of dilutive securities:
Stock options		17		26		42
Performance shares		215		231		254
Restricted stock units		218		183		144
Average diluted shares		46,944		46,758		46,555

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. The core principle of the update is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. The Company plans to adopt this update, as required, on January 1, 2017 for interim and annual reporting periods. Early adoption is not permitted. The Company is evaluating what impact this standard might have on its consolidated financial statements and disclosures. Additionally, the power and utilities industry as a whole assembled a task force for purposes of considering unique circumstances that relate to our industry and for communicating those industry considerations to the American Institute of Certified Public Accountants. Those undertakings are ongoing.

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 asses 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 is not expected to have a material impact on the Company’s 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.

Reclassifications

Reclassifications.    Certain reclassifications were made to the prior year’s financial information included in the Consolidated Balance Sheets (goodwill is identified separately from Deferred charges and other assets) in order to present the prior-year information on a basis comparable with the current year’s presentation, with no impact to total assets overall.

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Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Operating Leases (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Leases [Abstract]
2015	$ 5,957
2016	4,236
2017	2,532
2018	1,582
2019	912
Thereafter	831
Total minimum lease payments	$ 16,050

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Summary of Significant Accounting Policies - Schedule of Accumulated Removal Costs (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accumulated Removal Costs [Abstract]
Accumulated removal costs	$ 304,000	$ 279,000

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Pension and Other Postretirement Benefits - Schedule of Assumptions Used (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.25%
Asset return assumption	7.75%	7.75%

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Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Unrecognized tax benefits at beginning of year	$ 0
Gross increases-tax positions in prior period	305
Gross decreases-tax positions in prior period	0	0
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	$ 305	$ 0

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
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
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,835		(3,888	)		(4,414	)		62,106
Net income (loss) attributable to Southwest Gas Corporation		78,919		(3,676	)		(4,305	)		62,393
Basic earnings (loss) per common share*		1.71		(0.08	)		(0.09	)		1.35
Diluted earnings (loss) per common share*		1.70		(0.08	)		(0.09	)		1.34

* 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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Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Capital Leases (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Leases [Abstract]
2015	$ 1,690
2016	1,632
2017	813
2018	591
2019	0
Thereafter	0
Future minimum lease payments due	4,726
Less: amount representing interest	(497)
Total minimum lease payments	$ 4,229

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Long-Term Debt - Additional Information (Detail) (USD $)	1 Months Ended		3 Months Ended		12 Months Ended			1 Months Ended
	Dec. 31, 2014	Nov. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	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	0
Maximum current borrowing usage	165,000,000	165,000,000
Redemption of long term debt					139,155,000	137,013,000	427,043,000
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, 2014, the Company is in compliance with all of its covenants.
Issuance of additional debt					1,900,000,000
Minimum net worth					900,000,000
Previous Revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity								75,000,000
Credit facility expiration date								Jun. 30, 2015
Secured Revolving Credit and Term Loan Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity								300,000,000
Credit facility expiration date								Oct. 31, 2019
Effective interest rate					3.31%
Minimum current borrowing usage	199,000,000
Maximum current borrowing usage								232,000,000
Term loans	142,000,000				142,000,000
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] | Minimum [Member]
Debt Instrument [Line Items]
Commitment fee								0.15%
Short-term credit facility [Member]
Debt Instrument [Line Items]
Credit facility outstanding	5,000,000				5,000,000	0
Centuri Construction Group [Member]
Debt Instrument [Line Items]
Debt secured by assets								477,000,000
Debt instrument covenant description					Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2014, Centuri is in compliance with all of its covenants.
Issuance of additional debt					88,000,000
Equity cushion relating to minimum fixed charge ratio coverage requirement					35,000,000
LIBOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin								2.25%
LIBOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin								1.00%
CDOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin								2.25%
CDOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin								1.00%
Alternate Base Rate or Canadian Base Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin								1.25%
Alternate Base Rate or Canadian Base Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin								0.00%
5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate		5.25%
Redemption of long term debt		65,000,000
Debt instrument original due date					Jul. 01, 2034
Southwest Gas Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit designated as long term debt				150,000,000
Line of credit designated for working capital purposes				150,000,000
Credit facility maximum borrowing capacity				300,000,000
Credit facility expiration date					Mar. 01, 2019
Long-term portion of the credit facility	150,000,000				150,000,000
Effective interest rate					1.21%
Southwest Gas Credit Facility [Member] | Before Amendment [Member]
Debt Instrument [Line Items]
Credit facility expiration date					Mar. 01, 2017
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%
Commercial paper program [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	50,000,000				50,000,000
Credit facility outstanding	50,000,000				50,000,000
Commercial paper program [Member] | Short-term credit facility [Member]
Debt Instrument [Line Items]
Effective interest rate					0.65%
Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate				6.10%
Notes payable				$ 125,000,000
Notes, 6.1%, due 2041 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Percentage limit on liens securing indebtedness				10.00%

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Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 488,566	$ 371,799	$ 409,768	$ 657,645	$ 2,121,707	$ 1,950,782	$ 1,927,778
Operating income	112,373	18,290	26,755	127,065	100,772	6,141	28,908	138,394	115,211	6,310	15,380	134,623	284,483	274,215	271,524
Net income (loss)	58,897	1,927	9,627	70,697	57,189	(3,057)	10,067	80,674	62,106	(4,414)	(3,888)	78,835	141,148	144,873	132,639
Net income (loss) attributable to Southwest Gas Corporation	$ 58,746	$ 1,970	$ 9,627	$ 70,783	$ 57,303	$ (2,864)	$ 10,108	$ 80,773	$ 62,393	$ (4,305)	$ (3,676)	$ 78,919	$ 141,126	$ 145,320	$ 133,331
Basic earnings (loss) per common share	$ 1.26	$ 0.04	$ 0.21	$ 1.52	$ 1.24	$ (0.06)	$ 0.22	$ 1.75	$ 1.35	$ (0.09)	$ (0.08)	$ 1.71	$ 3.04	$ 3.14	$ 2.89
Diluted earnings (loss) per common share	$ 1.25	$ 0.04	$ 0.21	$ 1.51	$ 1.22	$ (0.06)	$ 0.22	$ 1.73	$ 1.34	$ (0.09)	$ (0.08)	$ 1.70	$ 3.01	$ 3.11	$ 2.86

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Equity [Abstract]
Amount of FSIRS existing AOCI losses expected to reclassified income in next twelve months	$ 2.1

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Utility Plant and Leases - Schedule of Depreciation and Amortization Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 253,027	$ 236,817	$ 223,422
Gas plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 194,360	$ 185,283	$ 182,612

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

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 wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co., Link-Line, W.S. Nicholls, and Brigadier.

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 the 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.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co., completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Additional consideration will be paid or accrued through the true-up period. The acquisition extends 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 6 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”) that provides construction and maintenance services for the Canadian utility industry, with operations primarily in Ontario, Canada; (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania as a specialty midstream pipeline contractor (“Brigadier”).

In October 2014, upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating a holding company, a direct subsidiary of Carson Water Company. In January 2015, the holding company was renamed Centuri. In addition, two direct subsidiaries exist under Centuri: Vistus Construction Group Inc. (“Vistus”, U.S. operations) and Lynxus Construction Group Inc. (“Lynxus”, Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line and W.S. Nicholls are subsidiaries of Lynxus.

Lynxus, including its subsidiaries of Link-Line, W.S. Nicholls, WSN Construction and WSN Industries will be consolidated under the voting interest method of accounting. Brigadier will be consolidated under the voting interest method.

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) as a majority-owned subsidiary. Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The Company’s investment in Western is not significant in relation to its total assets included in the Consolidated Balance Sheets. At December 31, 2014, Centuri’s investment in Western is $14.7 million and its maximum exposure to loss as a result of its involvement with the entity is estimated at $20.8 million, including obligations under a construction bonding arrangement under which Centuri has guaranteed the performance on certain projects of Western. 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, 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. The equity method investment in Western is included in Other Property and Investments in the 2014 Consolidated Balance Sheet.

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):

	2014			2013
Centuri property, equipment, and intangibles	$	405		$	320
Centuri accumulated provision for depreciation and amortization		(187	)		(163	)
Net cash surrender value of COLI policies		99			93
Other property		10			11
Total	$	327		$	261

Restricted Cash.    A construction bond that was required to be in place during the completion of one of Centuri’s construction projects is classified in the Consolidated Balance Sheets as restricted cash. The project is expected to be completed within one year. The restricted cash was acquired in conjunction with the acquisition of construction services businesses. See Note 15 – Acquisition of Construction Services Businesses for more information.

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 inventory and operating supplies of $23 million in 2014 and $21 million in 2013.

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, 2014, 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, 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.

During 2013 and 2014, approximately $9.3 million and $8.1 million, respectively, of customer advances, upon contract expiration, were applied as contributions toward utility construction activity and represent a non-cash investing activity. Additionally, in conjunction with the acquisition, the Company acquired several capital leases. During 2014 and after the acquisition date, an additional capital lease obligation was entered into and represents a non-cash financing inflow activity of $204,000. The associated capital lease asset represents a non-cash investing outflow activity of $204,000. In association with the acquisition, cash flows from investing activities includes an $18.9 million non-cash investing outflow due to equity to the noncontrolling interest in a subsidiary to acquire businesses. In addition, a non-cash investing outflow activity of $10.8 million related to an increase in an acquisition consideration payable is included.

Inventories.    Inventories are carried at weighted average cost and include natural gas stored underground, liquefied natural gas storage and materials and supplies.

Goodwill.    The construction services segment includes Goodwill of $133 million in 2014 ($125 million related to the recent acquisition, which is net of approximately $5 million due to foreign currency exchange translation adjustments between the acquisition date and the end of the year). The December 31, 2014 and 2013 Goodwill amounts shown in the Consolidated Balance Sheets include approximately $8 million of Goodwill recognized when Southwest first acquired NPL Construction Co. and is associated with the construction services segment. Goodwill of $10 million in both 2014 and 2013 is associated with the natural gas operations segment. Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill. No impairment was recorded in 2014.

Intangible Assets.    Intangible assets 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 have finite lives and are described in Notes 2 and 15.

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’s (“SEC”) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):

	December 31, 2014		December 31, 2013
Accumulated removal costs	$	304,000	$	279,000

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. In connection with significant changes in estimated costs to complete a large fixed-price contract, construction services results for 2012 reflected a pretax loss of $15 million ($0.20 per share, after tax). The estimated cost changes that resulted in the loss recognized included reductions in projected productivity and higher costs of restoration work. During 2013, profitability on this contract was minimal and as of December 31, 2013, this fixed-price contract was substantially complete. 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.

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.

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.

	2014		2013		2012
(In thousands)
AFUDC:
Debt portion	$	1,228	$	1,260	$	1,129
Equity portion		1,995		2,274		1,943
AFUDC capitalized as part of utility plant	$	3,223	$	3,534	$	3,072

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):

	2014			2013			2012
Change in COLI policies	$	5,300		$	12,400		$	6,600
Interest income		2,602			461			924
Pipe replacement costs		—			(132	)		(2,680	)
Foreign currency transaction gain (loss)		(178	)		—			—
Miscellaneous income and (expense)		(617	)		(429	)		(433	)
Total other income (deductions)	$	7,107		$	12,300		$	4,411

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

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, the amounts of which are not material, are included in other income (expense) within net income. 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.    In connection with the ownership structure of Centuri and its subsidiary entities, a redeemable noncontrolling interest exists in Lynxus. The Company concluded that this noncontrolling interest meets the definition of a participating security in connection with Accounting Standards Codification (“ASC”) Topic 260, as a result of dividend participation rights of the noncontrolling interest that are different than the underlying proportional ownership interest. Related provisions of ASC 260 would require consideration of the participation right in computing earnings per share. However, as earnings are already attributed to the noncontrolling interest equivalent to the participation right, taking an additional adjustment in computing basic earnings per share would duplicate the economic impact associated with the participating security. Furthermore, as net income attributable to common shareholders of Southwest Gas Corporation has already been adjusted for the attribution of income to the noncontrolling interest, the Company concluded that a diluted earnings per share calculation, assuming exchange of the ownership shares of the noncontrolling interest in Lynxus, for ownership shares in Centuri, would not produce a different result than that which results from computing basic earnings per share. The noncontrolling interest is also redeemable for fair value at specified dates in the future. No adjustment will be made to the Company’s income attributable to common shareholders, in computing earnings per share, to reflect changes in the redemption price, as redemption at fair value is not considered an economic distribution different from other common stockholders. See also Note 15 – Acquisition of Construction Services Businesses and Note 16 – Construction Services Noncontrolling Interests.

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.

	2014		2013		2012
(In thousands)
Average basic shares		46,494		46,318		46,115
Effect of dilutive securities:
Stock options		17		26		42
Performance shares		215		231		254
Restricted stock units		218		183		144
Average diluted shares		46,944		46,758		46,555

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. The core principle of the update is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. The Company plans to adopt this update, as required, on January 1, 2017 for interim and annual reporting periods. Early adoption is not permitted. The Company is evaluating what impact this standard might have on its consolidated financial statements and disclosures. Additionally, the power and utilities industry as a whole assembled a task force for purposes of considering unique circumstances that relate to our industry and for communicating those industry considerations to the American Institute of Certified Public Accountants. Those undertakings are ongoing.

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 asses 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 is not expected to have a material impact on the Company’s 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.

Reclassifications.    Certain reclassifications were made to the prior year’s financial information included in the Consolidated Balance Sheets (goodwill is identified separately from Deferred charges and other assets) in order to present the prior-year information on a basis comparable with the current year’s presentation, with no impact to total assets overall.

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Acquisition of Construction Services Businesses - Schedule of Actual Results Included In Consolidated Statements of Income (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Combination, Separately Recognized Transactions [Line Items]
Construction revenues													$ 739,620	$ 650,628	$ 606,050
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier	58,746	1,970	9,627	70,783	57,303	(2,864)	10,108	80,773	62,393	(4,305)	(3,676)	78,919	141,126	145,320	133,331
Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Construction revenues													54,264
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier													$ 1,859

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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) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	$ 33,000
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	1,300
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	300
PBOP prior service cost	$ 1,300

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Summary of Significant Accounting Policies - Schedule of Capitalized and Debt Portion of AFUDC (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract]
Debt portion	$ 1,228	$ 1,260	$ 1,129
Equity portion	1,995	2,274	1,943
AFUDC capitalized as part of utility plant	$ 3,223	$ 3,534	$ 3,072

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

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

December 31,	2014			2013
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	390,293		$	249,985
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,425			160
Deferred purchased gas costs (3)		87,556			18,217
Accrued purchased gas costs (4)		2,600			31,500
Unamortized premium on reacquired debt (5)		20,478			19,614
Other (6)		72,132			48,945
		578,484			368,421
Regulatory liabilities:
Accumulated removal costs		(304,000	)		(279,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		—			(981	)
Deferred gain on southern Nevada division operations facility (7)		(115	)		(253	)
Unamortized gain on reacquired debt (8)		(10,862	)		(11,398	)
Other (9)		(34,233	)		(26,482	)
Net regulatory assets	$	229,274		$	50,307

(1) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovery period is greater than five years. (See Note 9).

(2) The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the 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 12).

Instrument	Balance Sheet Location	2014		2013
Swaps	Deferred charges and other assets	$	363	$	4
Swaps	Prepaids and other current assets		5,062		156
Swaps	Other current liabilities		—		(801	)
Swaps	Other deferred credits		—		(180	)

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

(4) Included in Prepaids and other current assets 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) Balance was originally being amortized over a four-year period beginning in the fourth quarter of 2009. As a result of the most recent Nevada general rate case, the amortization period was extended through October 2015.

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

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

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Receivables and Related Allowances (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014, 

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

Schedule of Percent of Customers by State

The table below contains information about the percentage of customers in each of the three states at December 31, 2014.
	December 31, 2014
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, 2011	$	3,182
Additions charged to expense		2,471
Accounts written off, less recoveries		(3,149	)
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

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Derivatives and Fair Value Measurements - Notional Amounts under Swaps Contracts (Detail)	Dec. 31, 2014 MMBTU	Dec. 31, 2013 MMBTU
Offsetting [Abstract]
Contract notional amounts	5,105,000	13,571,000

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Receivables and Related Allowances - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Receivables And Related Allowances [Line Items]
Customer accounts receivable	$ 281,824	$ 219,469
Centuri Construction Group [Member]
Receivables And Related Allowances [Line Items]
Customer accounts receivable	$ 142,000

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Summary of Significant Accounting Policies - Other Income (Deductions) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Change in COLI policies	$ 5,300	$ 12,400	$ 6,600
Interest income	2,602	461	924
Pipe replacement costs		(132)	(2,680)
Foreign currency transaction gain (loss)	(178)
Miscellaneous income and (expense)	(617)	(429)	(433)
Total other income (deductions)	$ 7,107	$ 12,300	$ 4,411

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

12 Months Ended

Dec. 31, 2014

Text Block [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)

	2014									2013									2012
	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
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(135	)		220			355			(135	)		220			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			(329	)		538
Amortization of net actuarial (gain)/loss		23,656			(8,989	)		14,667			34,177			(12,987	)		21,190			25,597			(9,727	)		15,870
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)		42,771			(16,253	)		26,518
Pension plans other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973			(8,041	)		3,056			(4,985	)
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		—			—			—			—			—			—			2,959			(1,125	)		1,834
Amounts reclassified into net income		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			2,801			(1,064	)		1,737
FSIRS other comprehensive income (loss)		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			5,760			(2,189	)		3,571
Foreign currency translation adjustments:
Translation adjustments		(659	)		—			(659	)		—			—			—			—			—			—
Foreign currency other comprehensive income (loss)		(659	)		—			(659	)		—			—			—			—			—			—
Total other comprehensive income (loss)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047		$	(2,281	)	$	867		$	(1,414	)

(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	$	33,000
SERP net actuarial loss		1,300
PBOP net actuarial loss		300
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 9)									FSIRS (Note 12)									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, 2013	$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	—		$	—	$	—		$	(41,698	)
Net actuarial gain/(loss)		(173,646	)		65,985			(107,661	)		—			—			—			—			—		—			(107,661	)
Translation adjustments		—			—			—			—			—			—			(659	)		—		(659	)		(659	)
Other comprehensive income before reclassi fications		(173,646	)		65,985			(107,661	)		—			—			—			(659	)		—		(659	)		(108,320	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,345			(1,272	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		355			(135	)		220			—			—			—			—			—		—			220
Amortization of net actuarial loss (2)		23,656			(8,989	)		14,667			—			—			—			—			—		—			14,667
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			—			—		—			(4,130	)
Regulatory adjustment (3)		140,308			(53,317	)		86,991			—			—			—			—			—		—			86,991
Net current period other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(659	)		—		(659	)		(8,499	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(22	)		—		(22	)		(22	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(637	)		—		(637	)		(8,477	)
Ending Balance AOCI December 31, 2014	$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)

(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 9 – Pension and Other Postretirement Benefits for additional details).

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

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, 2014 and 2013:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2014			2013
Net actuarial (loss) gain	$	(439,131	)	$	(289,141	)
Prior service cost		(8,373	)		(2,067	)
Less: amount recognized in regulatory assets		390,293			249,985
Recognized in AOCI	$	(57,211	)	$	(41,223	)

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt

The Centuri secured revolving credit and term loan facility and Centuri other debt obligations (not actively traded) are categorized as Level 3, based on significant unobservable inputs to their fair values. Since Centuri’s debt is not publicly traded, fair values for the secured revolving credit and term loan facility and other debt obligations were based on a conventional discounted cash flow methodology and utilizes 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,	2014					2013
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	133,403	$	125,000		$	130,953
Notes, 6.1%, due 2041		125,000			157,290		125,000			141,873
Notes, 3.875%, due 2022		250,000			262,030		250,000			252,485
Notes, 4.875%, due 2043		250,000			280,903		250,000			257,280
8% Series, due 2026		75,000			102,296		75,000			96,263
Medium-term notes, 7.59% series, due 2017		25,000			27,573		25,000			28,741
Medium-term notes, 7.78% series, due 2022		25,000			31,144		25,000			30,586
Medium-term notes, 7.92% series, due 2027		25,000			33,695		25,000			31,497
Medium-term notes, 6.76% series, due 2027		7,500			9,156		7,500			8,468
Unamortized discount		(5,223	)				(5,560	)
		902,277					901,940
Revolving credit facility and commercial paper		150,000			150,000		10,000			10,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
5.25% 2003 Series D, due 2038		20,000			20,277		20,000			20,150
5.25% 2004 Series A, due 2034		—			—		65,000			64,522
5.00% 2004 Series B, due 2033		31,200			31,223		31,200			30,284
4.85% 2005 Series A, due 2035		100,000			100,071		100,000			95,192
4.75% 2006 Series A, due 2036		24,855			25,399		24,855			22,974
Unamortized discount		(1,943	)				(2,776	)
		374,112					438,279
Centuri secured revolving credit and term loan facility		199,267			200,341		—			—
Centuri other debt obligations		31,128			31,127		42,213			42,119
		1,656,784					1,392,432
Less: current maturities		(19,192	)				(11,105	)
Long-term debt, less current maturities	$	1,637,592				$	1,381,327

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, 2014			December 31, 2013
2003 Series A		0.85	%		1.43	%
2008 Series A		0.90	%		1.41	%
2009 Series A		0.89	%		1.01	%
Tax-exempt Series A		0.84	%		1.07	%

Estimated Maturities of Long-Term Debt

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

2015	$	19,192
2016		20,991
2017		43,899
2018		16,985
2019		304,328

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Consolidated Statements of Equity and Redeemable Noncontrolling Interest (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends declared Common, per share	$ 1.46	$ 1.32	$ 1.18
Shares registered and available for issuance	2,700,000
Common shares registered for issuance upon exercise of options	36,000	52,000	125,000

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Pension and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Cost of Retirement Plan

The cost of the Southwest plan is listed below (in thousands):

	2014		2013		2012
Employee Investment Plan cost	$	4,816	$	4,850	$	4,707

Schedule of Allocation of Plan Assets

At December 31, 2014, 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, 2014			December 31, 2013
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%
Asset return assumption		7.75	%		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 Statements of Income.

	2014									2013
	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)	$	886,714		$	36,143		$	58,020		$	902,812		$	37,373		$	59,704
Service cost		21,360			292			1,101			23,056			373			1,220
Interest cost		43,440			1,745			2,829			37,607			1,535			2,482
Plan amendments		—			—			6,661			—			—			—
Actuarial loss (gain)		144,606			5,459			4,567			(44,768	)		(661	)		(4,073	)
Benefits paid		(35,880	)		(2,463	)		(976	)		(31,993	)		(2,477	)		(1,313	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,060,240			41,176			72,202			886,714			36,143			58,020
Change in plan assets
Market value of plan assets at beginning of year		719,944			—			42,314			609,750			—			35,250
Actual return on plan assets		34,732			—			2,859			96,187			—			7,319
Employer contributions		36,000			2,463			—			46,000			2,477			169
Benefits paid		(35,880	)		(2,463	)		(281	)		(31,993	)		(2,477	)		(424	)
Market value of plan assets at end of year		754,796			—			44,892			719,944			—			42,314
Funded status at year end	$	(305,444	)	$	(41,176	)	$	(27,310	)	$	(166,770	)	$	(36,143	)	$	(15,706	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.25	%		4.25	%		4.25	%		5.00	%		5.00	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		2.75	%		N/A			3.25	%		3.25	%		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, 2014		December 31, 2013
Retirement plan	$	886,215	$	794,919
SERP		39,125		33,894

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):

	2015	2016	2017	2018		2019		2020-2024
Pension	$ 39.1	$41.3	$43.1		$45.3		$47.5		$272.7
PBOP	3.3	3.6	3.8		4.0		4.1		20.4
SERP	2.6	2.6	2.6		2.6		2.6		13.0

Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2014			2013			2012			2014			2013			2012			2014			2013			2012
(Thousands of dollars)
Service cost	$	21,360		$	23,056		$	20,319		$	292		$	373		$	274		$	1,101		$	1,220		$	977
Interest cost		43,440			37,607			38,266			1,745			1,535			1,629			2,829			2,482			2,547
Expected return on plan assets		(53,342	)		(49,840	)		(45,780	)		—			—			—			(3,264	)		(2,824	)		(2,404	)
Amortization of prior service cost		—			—			—			—			—			—			355			355			—
Amortization of transition obligation		—			—			—			—			—			—			—			—			867
Amortization of net actuarial loss		22,873			32,261			23,883			783			971			683			—			945			1,031
Net periodic benefit cost	$	34,331		$	43,084		$	36,688		$	2,820		$	2,879		$	2,586		$	1,021		$	2,178		$	3,018
Weighted-average assumptions (net benefit cost)
Discount rate		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%
Expected return on plan assets		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		2.75	%		3.00	%		3.25	%		2.75	%		3.00	%		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

	2014												2013												2012
	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)	$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)	$	74,853		$	70,016		$	4,111		$	726
Amortization of prior service cost (b)		(355	)		—			—			(355	)		(355	)		—			—			(355	)		—			—			—			—
Amortization of transition obligation (b)		—			—			—			—			—			—			—			—			(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)		(25,597	)		(23,883	)		(683	)		(1,031	)
Prior service cost		6,661			—			—			6,661			—			—			—			—			2,423			—			—			2,423
Regulatory adjustment		(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868			(42,771	)		(41,520	)		—			(1,251	)
Recognized in other comprehensive
(income) loss		15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—			8,041			4,613			3,428			—
Net periodic benefit costs recognized in net income		38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178			42,292			36,688			2,586			3,018
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178		$	50,333		$	41,301		$	6,014			$3,018

The table above discloses the net gain or loss, prior service cost, and transition amount 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, 2014 and December 31, 2013. The SERP has no assets. There were no transfers between Levels 1 and 2 during 2014.

	December 31, 2014						December 31, 2013
	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	$	6,661	$	198	$	6,859	$	8,224	$	244	$	8,468
Capital equipment		2,222		66		2,288		3,891		115		4,006
Chemicals/materials		5,233		155		5,388		8,228		244		8,472
Consumer goods		41,731		1,238		42,969		54,329		1,611		55,940
Energy and mining		18,502		549		19,051		36,126		1,071		37,197
Finance/insurance		20,685		613		21,298		37,643		1,116		38,759
Healthcare		37,846		1,122		38,968		40,426		1,199		41,625
Information technology		25,881		767		26,648		24,636		731		25,367
Services		28,846		855		29,701		31,212		926		32,138
Telecommunications/internet/media		18,498		549		19,047		24,270		720		24,990
Other		10,958		325		11,283		16,455		488		16,943
Real estate investment trusts		5,713		169		5,882		5,779		171		5,950
Mutual funds		86,159		24,567		110,726		76,764		22,495		99,259
Government fixed income securities		44,694		1,325		46,019		34,495		1,023		35,518
Preferred securities		568		17		585		—		—		—
Total Level 1 Assets (1)	$	354,197	$	32,515	$	386,712	$	402,478	$	32,154	$	434,632
Level 2 – Significant other observable inputs
Commercial paper	$	—	$	—	$	—	$	1,411	$	42	$	1,453
Government fixed income and mortgage backed securities		48,312		1,433		49,745		49,298		1,462		50,760
Corporate fixed income securities
Asset-backed and mortgage-backed		27,071		803		27,874		20,697		614		21,311
Banking		23,289		691		23,980		19,004		564		19,568
Insurance		6,182		183		6,365		6,481		192		6,673
Utilities		4,232		126		4,358		5,278		156		5,434
Other		23,120		686		23,806		19,649		582		20,231
Pooled funds and mutual funds		11,968		984		12,952		8,111		1,150		9,261
State and local obligations		1,499		44		1,543		1,370		41		1,411
Total Level 2 assets (2)	$	145,673	$	4,950	$	150,623	$	131,299	$	4,803	$	136,102
Level 3 – Significant unobservable inputs
Commingled equity funds	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Level 3 assets (3)	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Plan assets at fair value	$	759,105	$	45,152	$	804,257	$	723,229	$	42,575	$	765,804
Insurance company general account contracts (4)		4,003		—		4,003		4,296		—		4,296
Total Plan assets (5)	$	763,108	$	45,152	$	808,260	$	727,525	$	42,575	$	770,100

(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) Assets not considered Level 1 or Level 2 are valued using assumptions based on the best information available under the circumstances, such as investment manager pricing.

The commingled equity funds include private equity funds that invest in domestic and international securities (predominately Level 1 assets) regularly traded on securities exchanges. These funds are shown in the above table at net asset value. 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.

(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 $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) and $7,842,000 (qualified retirement plan – $7,581,000, PBOP – $261,000) for 2014 and 2013, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

Schedule of Effect of Significant Unobservable Inputs

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2012	$	127,467
Actual return on plan assets:
Relating to assets still held at the reporting date		21,903
Relating to assets sold during the period		—
Purchases		45,700
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2013		195,070
Actual return on plan assets:
Relating to assets still held at the reporting date		(6,932	)
Relating to assets sold during the period		2,069
Purchases		82,615
Sales		(5,900	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2014	$	266,922

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Pension and Other Postretirement Benefits - Schedule of Effect of Significant Unobservable Inputs (Detail) (Commingled equity funds [Member], Level 3 - Significant unobservable inputs [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Beginning balance	$ 195,070	$ 127,467
Actual return on plan assets, Relating to assets still held/Sold during the period	(6,932)	21,903
Purchases	82,615	45,700
Sales	(5,900)
Settlements	0	0
Transfers in and/or out of Level 3	0	0
Ending balance	266,922	195,070
Realized [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual return on plan assets, Relating to assets still held/Sold during the period	$ 2,069

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Acquisition of Construction Services Businesses - Schedule of Estimated Future Amortization of Intangible Assets Acquired (Detail) (Link-Line, W.S. Nicholls, and Brigadier [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Link-Line, W.S. Nicholls, and Brigadier [Member]
Finite-Lived Intangible Assets [Line Items]
2015	$ 4,615
2016	3,371
2017	3,371
2018	3,123
2019	$ 2,370

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	Oct. 31, 2014 Business	Dec. 31, 2014 Segment Business	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Number of segments		2
Number of business acquisitions	3	3
Purchase agreements including debt assumed	$ 221,000,000	$ 190,497,000
Non-cash construction advances - non-cash investing item		8,100,000	9,300,000
Non-cash investing outflow activity		10,800,000
Goodwill		143,160,000	17,810,000
Goodwill impairment charges		0
Recognized pretax losses, after tax earnings per share impacts				$ 0.20
Secured Revolving Credit and Term Loan Facility [Member]
Significant Accounting Policies [Line Items]
Secured revolving credit and term loan facility	300,000,000
Construction Services [Member]
Significant Accounting Policies [Line Items]
Goodwill		133,000,000
Recognized pretax profit/losses				15,000,000
Gas Operations [Member]
Significant Accounting Policies [Line Items]
Goodwill		10,000,000	10,000,000
Recent Acquisitions [Member] | Construction Services [Member]
Significant Accounting Policies [Line Items]
Goodwill recognized by acquisition		125,000,000
Reduction of goodwill due to foreign currency exchange translation adjustments		5,000,000
NPL Construction Co. [Member] | Construction Services [Member]
Significant Accounting Policies [Line Items]
Goodwill		8,000,000	8,000,000
Non-controlling Interest [Member]
Significant Accounting Policies [Line Items]
Non-cash investing outflow activity		18,900,000
Pooled funds and mutual funds [Member] | Level 2 - Significant other observable inputs [Member]
Significant Accounting Policies [Line Items]
Money market fund investments		250,000
Capital Lease Obligation [Member]
Significant Accounting Policies [Line Items]
Non-cash financing inflow activity		204,000
Capital Lease Asset [Member]
Significant Accounting Policies [Line Items]
Non-cash investing outflow activity		204,000
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]
Subsidiaries holding interest percentage		50.00%
Investment amount		14,700,000
Exposure to loss as a result of its investment		20,800,000
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%
Gas Pipe Inventory and Operating Supplies [Member]
Significant Accounting Policies [Line Items]
Gas pipe inventory and operating supplies		$ 23,000,000	$ 21,000,000

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Receivables and Related Allowances - Schedule of Accounts Receivable (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Gas utility customer accounts receivable balance	$ 136,148

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Pension and Other Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 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	25
Estimated increase in pension expense	$ 10
Future estimated funding amount	39
Future estimated funding amount of retirement plan	$ 36
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	6.00%
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	5.00%

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Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
Utility plant:
Gas plant	$ 5,556,599,000	$ 5,252,469,000
Less: accumulated depreciation	(1,973,098,000)	(1,868,504,000)
Acquisition adjustments, net	550,000	730,000
Construction work in progress	74,332,000	101,413,000
Net utility plant (Note 2)	3,658,383,000	3,486,108,000
Other property and investments (Note 1)	326,743,000	260,871,000
Restricted cash (Note 1)	821,000
Current assets:
Cash and cash equivalents	39,566,000	41,077,000
Accounts receivable, net of allowances (Note 3)	281,824,000	219,469,000
Accrued utility revenue	73,900,000	72,700,000
Income taxes receivable, net	21,853,000	3,790,000
Deferred income taxes, net (Note 11)	2,109,000	31,130,000
Deferred purchased gas costs (Note 4)	87,556,000	18,217,000
Prepaids and other current assets (Notes 1, 4, and 12)	99,975,000	108,289,000
Total current assets	606,783,000	494,672,000
Noncurrent assets:
Goodwill (Notes 1 and 15)	143,160,000	17,810,000
Deferred charges and other assets (Notes 2, 4, and 12)	478,625,000	305,713,000
Total noncurrent assets	621,785,000	323,523,000
Total assets	5,214,515,000	4,565,174,000
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 46,523,184 and 46,356,125 shares) (Note 10)	48,153,000	47,986,000
Additional paid-in capital	851,381,000	840,521,000
Accumulated other comprehensive income (loss), net (Note 5)	(50,175,000)	(41,698,000)
Retained earnings	639,164,000	567,714,000
Total Southwest Gas Corporation equity	1,488,523,000	1,414,523,000
Noncontrolling interest	(2,257,000)	(2,128,000)
Total equity	1,486,266,000	1,412,395,000
Redeemable noncontrolling interest (Note 16)	20,042,000
Long-term debt, less current maturities (Note 6)	1,637,592,000	1,381,327,000
Total capitalization	3,143,900,000	2,793,722,000
Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)	19,192,000	11,105,000
Short-term debt (Note 7)	5,000,000	0
Accounts payable	167,988,000	183,511,000
Customer deposits	71,546,000	73,367,000
Accrued general taxes	44,339,000	39,681,000
Accrued interest	16,468,000	17,920,000
Other current liabilities (Notes 2, 4, and 12)	145,584,000	108,580,000
Total current liabilities	470,117,000	434,164,000
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 11)	723,688,000	674,411,000
Taxes payable		284,000
Accumulated removal costs (Note 4)	304,000,000	279,000,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 9, and 12)	572,810,000	383,593,000
Total deferred income taxes and other credits	1,600,498,000	1,337,288,000
Total capitalization and liabilities	$ 5,214,515,000	$ 4,565,174,000

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Summary of Significant Accounting Policies - Schedule of Earnings Per Share, Basic and Diluted (Detail) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Weighted Average Number of Shares Outstanding, Diluted [Abstract]
Average basic shares	46,494	46,318	46,115
Stock options	17	26	42
Performance shares	215	231	254
Restricted stock units	218	183	144
Average diluted shares	46,944	46,758	46,555

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Line Items]
Federal general business credit carryforward	$ 711,000
Federal net operating loss carryforward, expiration year	2031
Federal general business credits, expiration year	2031
Net operating loss carryforward expiration year	2034
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
Minimum [Member]
Income Tax Disclosure [Line Items]
Amount of benefit being recognized in financial statements upon ultimate settlement, Percentage	50.00%
Canada [Member]
Income Tax Disclosure [Line Items]
Federal net operating loss carryforward	1,100,000
Canada [Member] | Tax Year 2011 [Member]
Income Tax Disclosure [Line Items]
Tax examination, year	2011
Canada [Member] | Tax Year 2012 [Member]
Income Tax Disclosure [Line Items]
Tax examination, year	2012
United States [Member]
Income Tax Disclosure [Line Items]
Federal net operating loss carryforward	28,000,000
Federal net capital loss carryforward	$ 494,000

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Acquisition of Construction Services Businesses - Preliminary Estimated Fair Values of Assets Acquired and Liabilities Assumed (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Oct. 01, 2014
Business Acquisition [Line Items]
Goodwill	$ 143,160,000	$ 17,810,000
Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Acquisition [Line Items]
Cash, cash equivalents, and restricted cash			3,000,000
Contracts receivable and other receivables			62,000,000
Property, plant and equipment			17,000,000
Other assets			17,000,000
Intangible assets			52,000,000
Goodwill	125,000,000		130,000,000
Total assets acquired			281,000,000
Current liabilities			39,000,000
Deferred income tax-long-term			17,000,000
Other long-term liabilities			4,000,000
Net assets acquired			$ 221,000,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$ 141,148	$ 144,873	$ 132,639
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	253,027	236,817	223,422
Deferred income taxes	64,309	68,639	66,280
Changes in current assets and liabilities:
Accounts receivable, net of allowances	(3,683)	(22,556)	12,333
Accrued utility revenue	(1,200)	(700)	(1,700)
Deferred purchased gas costs	(69,339)	(111,143)	22,823
Accounts payable	(41,499)	27,668	(25,998)
Accrued taxes	(13,573)	925	113
Other current assets and liabilities	23,379	5,084	(18,948)
Gains on sale	(6,171)	(4,112)	(8,040)
Changes in undistributed stock compensation	7,973	6,958	5,137
AFUDC	(1,995)	(2,274)	(1,943)
Changes in other assets and deferred charges	(21,732)	(21,719)	(15,367)
Changes in other liabilities and deferred credits	15,779	17,749	(4,427)
Net cash provided by operating activities	346,423	346,209	386,324
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions	(396,898)	(364,276)	(395,712)
Acquisition of businesses, net of cash acquired	(190,497)
Restricted cash	1,233		12,785
Changes in customer advances	20,363	7,773	(3,025)
Miscellaneous inflows	11,611	8,465	13,963
Miscellaneous outflows	(1,400)		(2,004)
Net cash used in investing activities	(555,588)	(348,038)	(373,993)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net	405	1,635	1,581
Dividends paid	(66,275)	(59,535)	(53,040)
Interest rate swap settlement			(21,754)
Issuance of long-term debt, net	269,228	311,290	489,518
Retirement of long-term debt	(139,155)	(137,013)	(427,043)
Change in credit facility and commercial paper	140,000	(101,000)	2,000
Change in short-term debt	5,000	1,999
Principal payments on capital lease obligations	(434)
Other	(1,257)
Net cash provided by (used in) financing activities	207,512	17,376	(8,738)
Effects of currency translation on cash and cash equivalents	142
Change in cash and cash equivalents	(1,511)	15,547	3,593
Cash and cash equivalents at beginning of period	41,077	25,530	21,937
Cash and cash equivalents at end of period	39,566	41,077	25,530
Supplemental information:
Interest paid, net of amounts capitalized	65,552	58,730	87,439
Income taxes paid (received)	$ 24,247	$ 6,850	$ 2,843

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Income Taxes - Reconciliation of U.S Federal Statutory Rate to Consolidated Effective Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
U.S. federal statutory income tax rate	35.00%	35.00%	35.00%
Net state taxes	1.90%	2.40%	2.60%
Property-related items	0.10%	0.10%	0.20%
Tax credits	(0.50%)	(0.40%)	(0.40%)
Company owned life insurance	(1.00%)	(2.10%)	(1.30%)
All other differences	0.20%		0.10%
Consolidated effective income tax rate	35.70%	35.00%	36.20%

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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, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]
Net actuarial gain/(loss), Before-Tax Amount	$ (173,646)	$ 100,345	$ (74,853)
Amortization of prior service cost, Before-Tax Amount	355	355
Amortization of transition obligation, Before-Tax Amount			867
Amortization of net actuarial (gain)/loss, Before-Tax Amount	23,656	34,177	25,597
Prior service cost, Before-Tax Amount	(6,661)		(2,423)
Regulatory adjustment, Before-Tax Amount	140,308	(123,630)	42,771
Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax	(15,988)	11,247	(8,041)
Unrealized/realized gain (loss), Before-Tax Amount			2,959
Amounts reclassified into net income, Before-Tax Amount	3,345	3,345	2,801
FSIRS other comprehensive income (loss), Before-Tax Amount	3,345	3,345	5,760
Translation adjustments, Before-Tax Amount	(659)
Foreign currency other comprehensive income (loss), Before-Tax Amount	(659)
Total other comprehensive income (loss), Before-Tax Amount	(13,302)	14,592	(2,281)
Net actuarial gain/(loss), Tax (Expense) or Benefit	65,985	(38,131)	28,444
Amortization of prior service cost, Tax (Expense) or Benefit	(135)	(135)
Amortization of transition obligation, Tax (Expense) or Benefit			(329)
Amortization of net actuarial (gain)/loss, Tax (Expense) or Benefit	(8,989)	(12,987)	(9,727)
Prior service cost, Tax (Expense) or Benefit	2,531		921
Regulatory adjustment, Tax (Expense) or Benefit	(53,317)	46,979	(16,253)
Net current period other comprehensive income (loss), Defined Benefit Plans Tax (Expense) Benefit	6,075	(4,274)	3,056
Unrealized/realized gain (loss), Tax (Expense) or Benefit			(1,125)
Amounts reclassified into net income, Tax (Expense) or Benefit	(1,272)	(1,271)	(1,064)
FSIRS other comprehensive income (loss), Tax (Expense) or Benefit	(1,272)	(1,271)	(2,189)
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	4,803	(5,545)	867
Net actuarial gain/(loss), Net-of-Tax Amount	(107,661)	62,214	(46,409)
Amortization of prior service cost, Net-of-Tax Amount	220	220
Amortization of transition obligation, Net-of-Tax Amount			538
Amortization of net actuarial (gain)/loss, Net-of-Tax Amount	14,667	21,190	15,870
Prior service cost, Net-of-Tax Amount	(4,130)		(1,502)
Regulatory adjustment, Net-of-Tax Amount	86,991	(76,651)	26,518
Net defined benefit pension plans	(9,913)	6,973	(4,985)
Unrealized/realized loss, Net-of-Tax Amount			1,834
Amounts reclassified into net income (Notes 5 and 12)	2,073	2,074	1,737
FSIRS other comprehensive income (loss), Net-of-Tax Amount	2,073	2,074	3,571
Translation adjustments, Net-of-Tax Amount	(659)
Foreign currency other comprehensive income (loss), Net-of-Tax Amount	(659)
Total other comprehensive income (loss), net of tax	$ (8,499)	$ 9,047	$ (1,414)

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Derivatives and Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Natural gas portfolios, maximum % rate	25.00%
Gain or loss (ineffective portion) recognized in income	$ 0
Senior Notes, 3.875%, Due 2022 [Member]
Derivative [Line Items]
Agreement settlement paid	$ 21,800,000
Minimum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	Jan. 01, 2015
Maximum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	Mar. 31, 2016

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Derivatives and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [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, 2014		December 31, 2013
Contract notional amounts		5,105		13,571

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, 2014, 2013, and 2012 and their location in the Consolidated Statements of Income (thousands of dollars):

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	2014			2013			2012
Swaps	Net cost of gas sold	$	(2,363	)	$	976		$	(4,854	)
Swaps	Net cost of gas sold		2,363	*		(976	)*		4,854	*
Total		$	—		$	—		$	—

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

Gains (Losses) Recognized in Other Comprehensive Income for Derivatives as Cash Flow Hedging Instruments

Gains (losses) recognized in other comprehensive income for derivatives designated as cash flow hedging instruments:

	Year Ended December 31, 2014		Year Ended December 31, 2013		Year Ended December 31, 2012
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	—	$	—	$	2,959

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, 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	)
December 31, 2013 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	257	$	(77	)	$	180
Swaps	Prepaids and other current assets		1,054		(253	)		801
Swaps	Other current liabilities		126		(282	)		(156	)
Swaps	Other deferred credits		7		(11	)		(4	)
Total		$	1,444	$	(623	)	$	821

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, 2014		Year ended December 31, 2013		Year ended December 31, 2012
(Thousands of dollars)
Paid to counterparties	$	829	$	3,148	$	14,843
Received from counterparties	$	4,713	$	915	$	634

Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in 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, 2014 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	5,062
Swaps	Deferred charges and other assets		363
December 31, 2013 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(180	)
Swaps	Other current liabilities		(801	)
Swaps	Prepaids and other current assets		156
Swaps	Deferred charges and other assets		4

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 9 – Pension and Other Post Retirement Benefits for definitions of the levels of the fair value hierarchy):

Level 2 - Significant other observable inputs

	December 31, 2014			December 31, 2013
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets - Swaps	$	—		$	801
Deferred charges and other assets - Swaps		—			180
Liabilities at fair value:
Other current liabilities - Swaps		(5,062	)		(156	)
Other deferred credits - Swaps		(363	)		(4	)
Net Assets (Liabilities)	$	(5,425	)	$	821

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Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2014
Debt Instrument [Line Items]
Less: current maturities	$ (19,192,000)	$ (11,105,000)
Long-term debt, less current maturities	1,637,592,000	1,381,327,000
Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Notes payable			125,000,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Total long-term debt	1,656,784,000	1,392,432,000
Less: current maturities	(19,192,000)	(11,105,000)
Long-term debt, less current maturities	1,637,592,000	1,381,327,000
Total long-term debt	1,656,784,000	1,392,432,000
Carrying Amount [Member] | Centuri secured revolving credit and term loan facility [Member]
Debt Instrument [Line Items]
Centuri secured revolving credit and term loan facility	199,267,000
Carrying Amount [Member] | Centuri other debt obligations [Member]
Debt Instrument [Line Items]
Centuri other debt obligations	31,128,000	42,213,000
Carrying Amount [Member] | Bonds [Member]
Debt Instrument [Line Items]
Unsecured debt	374,112,000	438,279,000
Carrying Amount [Member] | Debentures [Member]
Debt Instrument [Line Items]
Unamortized discount	(5,223,000)	(5,560,000)
Notes payable	902,277,000	901,940,000
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	10,000,000
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	(1,943,000)	(2,776,000)
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	20,000,000	20,000,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Unsecured debt		65,000,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Unsecured debt	31,200,000	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] | Centuri secured revolving credit and term loan facility [Member]
Debt Instrument [Line Items]
Centuri secured revolving credit and term loan facility	200,341,000
Market Value [Member] | Centuri other debt obligations [Member]
Debt Instrument [Line Items]
Centuri other debt obligations	31,127,000	42,119,000
Market Value [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	133,403,000	130,953,000
Market Value [Member] | Debentures [Member] | Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	157,290,000	141,873,000
Market Value [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	262,030,000	252,485,000
Market Value [Member] | Debentures [Member] | Notes, 4.875%, due 2043 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	280,903,000	257,280,000
Market Value [Member] | Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	102,296,000	96,263,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	27,573,000	28,741,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	31,144,000	30,586,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	33,695,000	31,497,000
Market Value [Member] | Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	9,156,000	8,468,000
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	10,000,000
Market Value [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Line of credit facility, 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]
Line of credit facility, 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]
Line of credit facility, fair value	50,000,000	50,000,000
Market Value [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Line of credit facility, 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]
Line of credit facility, fair value	20,277,000	20,150,000
Market Value [Member] | Fixed-rate bonds [Member] | 5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value		64,522,000
Market Value [Member] | Fixed-rate bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	31,223,000	30,284,000
Market Value [Member] | Fixed-rate bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	100,071,000	95,192,000
Market Value [Member] | Fixed-rate bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	$ 25,399,000	$ 22,974,000

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data

Note 14 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
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
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,835		(3,888	)		(4,414	)		62,106
Net income (loss) attributable to Southwest Gas Corporation		78,919		(3,676	)		(4,305	)		62,393
Basic earnings (loss) per common share*		1.71		(0.08	)		(0.09	)		1.35
Diluted earnings (loss) per common share*		1.70		(0.08	)		(0.09	)		1.34

* 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 15 – Acquisition of Construction Services Businesses below regarding an acquisition in the last quarter of 2014 and see Note-16 – Construction Services Noncontrolling Interests regarding allocation of earnings.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014		December 31, 2013
Accounts receivable for Centuri services	$	9,169	$	10,787

Schedule of Revenues and Long-Lived Assets by Geographic Area

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

	December 31, 2014		December 31, 2013
Revenues (a)
United States	$	2,069,513	$	1,950,782
Canada		52,194		—
Total	$	2,121,707	$	1,950,782
Long-lived assets
United States	$	6,021,476		5,674,449
Canada		14,475		—
Total	$	6,035,951	$	5,674,449

(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, 2014 is as follows (thousands of dollars):

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	$	4,657,709	$	567,405	$	(10,599	)	$	5,214,515
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
2012	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,321,728	$	522,676				$	1,844,404
Intersegment sales		—		83,374					83,374
Total	$	1,321,728	$	606,050				$	1,927,778
Interest revenue	$	915	$	9				$	924
Interest expense	$	66,957	$	1,063				$	68,020
Depreciation and amortization	$	186,035	$	37,387				$	223,422
Income tax expense	$	64,973	$	10,303				$	75,276
Segment net income	$	116,619	$	16,712				$	133,331
Segment assets	$	4,204,948	$	283,109				$	4,488,057
Capital expenditures	$	308,951	$	86,761				$	395,712

(a) Construction services segment assets include 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 include 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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Income Taxes - Summary of Tax-Related Interest Income (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Tax-related interest income			$ 24

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Construction Services Noncontrolling Interests

12 Months Ended

Dec. 31, 2014

Noncontrolling Interest [Abstract]

Construction Services Noncontrolling Interests

Note 16 – Construction Services Noncontrolling Interests

As discussed in Note 15 – Acquisition of Construction Services Businesses, at the close of the acquisition, previous owners of the acquired companies retained an approximate 10% equity interest in the Canadian businesses that were acquired. The agreement, associated with the approximate 10% indirect equity interest of the sellers, provides special dividend rights which entitle the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri and subject to certain conditions, such interests may become exchangeable for a 3.4% equity interest in Centuri. Additionally, the previous owners may exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021.

The Company has determined that this noncontrolling interest is a redeemable noncontrolling interest and, in accordance with SEC guidance, is classified as mezzanine equity (temporary equity) in the Consolidated Balance Sheets. The redeemable noncontrolling interest is reported at $20 million, the estimated redemption value as of December 31, 2014. Based on the fair value model employed, the estimated redemption value of the redeemable noncontrolling interest increased by approximately $961,000 during the fourth quarter of 2014. Changes in the value of the redeemable noncontrolling interest will be recognized as they occur and the carrying value will be adjusted accordingly at each quarterly reporting date. Any adjustment to the redemption value impacts retained earnings, but does not impact net income.

	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2013	$	—
Redeemable noncontrolling interest related to acquisition		18,952
Net Income (loss) attributable to redeemable noncontrolling interest		151
Foreign currency exchange translation adjustment		(22	)
Adjustment to redemption value		961
Balance, December 31, 2014	$	20,042

The redemption value of the redeemable noncontrolling interest was determined using a Monte Carlo simulation method. First, a market approach was utilized to determine a construction services enterprise value as of the acquisition date. Potential guideline publicly-traded companies were identified by using a selection criteria, including actively traded equities, their financial solvency, and other factors. Once the guideline companies were determined, enterprise value was calculated using a weighted approach of projected earnings before interest expense and taxes (“EBIT”) and earnings before interest expense, taxes, and depreciation and amortization expense (“EBITDA”). After an estimated fair value was determined, a Monte Carlo simulation was used to assign a value to the noncontrolling interest of the sellers. Other assumptions used in this analysis included dividends, probability of events, and a discount due to lack of control (the sellers do not influence operations).

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.

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Long-Term Debt - Summary of Effective Interest Rates on Variable-Rate IDRBs (Detail)	Dec. 31, 2014	Dec. 31, 2013
2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.85%	1.43%
2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.90%	1.41%
2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.89%	1.01%
Tax-exempt Series A, due 2028 [Member]
Debt Instrument [Line Items]
Effective interest rates	0.84%	1.07%

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Segment Information - Schedule of Revenues and Long-Lived Assets by Geographic Area (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total Revenues	$ 627,683	$ 432,475	$ 453,153	$ 608,396	$ 538,357	$ 387,346	$ 411,574	$ 613,505	$ 488,566	$ 371,799	$ 409,768	$ 657,645	$ 2,121,707	$ 1,950,782	$ 1,927,778
Total Long-lived assets	6,035,951				5,674,449								6,035,951	5,674,449
United States [Member]
Segment Reporting Information [Line Items]
Total Revenues													2,069,513	1,950,782
Total Long-lived assets	6,021,476				5,674,449								6,021,476	5,674,449
Canada [Member]
Segment Reporting Information [Line Items]
Total Revenues													52,194
Total Long-lived assets	$ 14,475												$ 14,475

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Consolidated Statements of Equity and Redeemable Noncontrolling Interest (USD $) In Thousands, except Share data	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, 2011	$ 1,225,031	$ 47,586		$ 821,640	$ (49,331)	$ 406,125	$ (989)
Balance, Shares at Dec. 31, 2011		45,956,000
Common stock issuances, Value	7,329	192		7,137
Common stock issuance, Shares		192,000
Net income (loss)	132,639					133,331	(692)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)	(4,985)				(4,985)
FSIRS realized and unrealized gain, net of tax (Notes 5 and 12)	1,834				1,834
Amounts reclassified into net income (Notes 5 and 12)	1,737				1,737
Dividends declared Common	(55,087)					(55,087)
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 issuance, 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 9)	6,973				6,973
Amounts reclassified into net income (Notes 5 and 12)	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	46,356,125	46,356,000
Common stock issuances, Value	11,027	167		10,860
Common stock issuance, Shares		167,000
Net income (loss)	141,148
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)	(9,913)				(9,913)
Amounts reclassified into net income (Notes 5 and 12)	2,073				2,073
Dividends declared Common	(68,715)					(68,715)
Redeemable noncontrolling interest attributable to acquisition								18,952
Net income (loss)	140,997					141,126	(129)	151
Fair value accretion (Note 16)	(961)					(961)		961
Foreign currency exchange translation adj.	(637)				(637)			(22)
Balance at Dec. 31, 2014	$ 1,486,266	$ 48,153		$ 851,381	$ (50,175)	$ 639,164	$ (2,257)	$ 20,042
Balance, Shares at Dec. 31, 2014	46,523,184	46,523,000	[1]

[1] At December 31, 2014, 2.7 million common shares were registered and available for issuance under provisions of the Company's various stock issuance plans. In addition, approximately 36,000 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 Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common stock, par	$ 1	$ 1
Common stock, authorized	60,000,000	60,000,000
Common stock, issued	46,523,184	46,356,125
Common stock, outstanding	46,523,184	46,356,125

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits

Note 9 – 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):

	2014		2013		2012
Employee Investment Plan cost	$	4,816	$	4,850	$	4,707

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 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 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.

In accordance with regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities, 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, 2014, 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.

U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on December 31 of each year and expected to be available during the period to maturity of the pension benefits. 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 lower interest rate environment for high-quality fixed income investments, the Company reduced the discount rate at December 31, 2014 from 2013. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also lowered (consistent with management’s expectations overall). The asset return assumption (which impacts the following year’s expense) was not changed. The rates are presented in the table below:

	December 31, 2014			December 31, 2013
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%
Asset return assumption		7.75	%		7.75	%

A landmark change to a new actuarial mortality table by the Society of Actuaries, which takes into account longer life spans for plan participants and forms a new basis for retirement plan obligations in the U.S., will significantly increase the expense level for 2015. It also negatively impacts the funded status of the plan at the end of 2014. Pension expense for 2015 is estimated to increase by $10 million compared to 2014 because of the extended mortality assumption and lower 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.

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

	2014									2013
	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)	$	886,714		$	36,143		$	58,020		$	902,812		$	37,373		$	59,704
Service cost		21,360			292			1,101			23,056			373			1,220
Interest cost		43,440			1,745			2,829			37,607			1,535			2,482
Plan amendments		—			—			6,661			—			—			—
Actuarial loss (gain)		144,606			5,459			4,567			(44,768	)		(661	)		(4,073	)
Benefits paid		(35,880	)		(2,463	)		(976	)		(31,993	)		(2,477	)		(1,313	)
Benefit obligation at end of year (PBO/PBO/APBO)		1,060,240			41,176			72,202			886,714			36,143			58,020
Change in plan assets
Market value of plan assets at beginning of year		719,944			—			42,314			609,750			—			35,250
Actual return on plan assets		34,732			—			2,859			96,187			—			7,319
Employer contributions		36,000			2,463			—			46,000			2,477			169
Benefits paid		(35,880	)		(2,463	)		(281	)		(31,993	)		(2,477	)		(424	)
Market value of plan assets at end of year		754,796			—			44,892			719,944			—			42,314
Funded status at year end	$	(305,444	)	$	(41,176	)	$	(27,310	)	$	(166,770	)	$	(36,143	)	$	(15,706	)
Weighted-average assumptions (benefit obligation)
Discount rate		4.25	%		4.25	%		4.25	%		5.00	%		5.00	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		2.75	%		N/A			3.25	%		3.25	%		N/A

Estimated funding for the plans above during calendar year 2015 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, 2014		December 31, 2013
Retirement plan	$	886,215	$	794,919
SERP		39,125		33,894

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

	2015	2016	2017	2018		2019		2020-2024
Pension	$ 39.1	$41.3	$43.1		$45.3		$47.5		$272.7
PBOP	3.3	3.6	3.8		4.0		4.1		20.4
SERP	2.6	2.6	2.6		2.6		2.6		13.0

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 6% declining to 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
	2014			2013			2012			2014			2013			2012			2014			2013			2012
(Thousands of dollars)
Service cost	$	21,360		$	23,056		$	20,319		$	292		$	373		$	274		$	1,101		$	1,220		$	977
Interest cost		43,440			37,607			38,266			1,745			1,535			1,629			2,829			2,482			2,547
Expected return on plan assets		(53,342	)		(49,840	)		(45,780	)		—			—			—			(3,264	)		(2,824	)		(2,404	)
Amortization of prior service cost		—			—			—			—			—			—			355			355			—
Amortization of transition obligation		—			—			—			—			—			—			—			—			867
Amortization of net actuarial loss		22,873			32,261			23,883			783			971			683			—			945			1,031
Net periodic benefit cost	$	34,331		$	43,084		$	36,688		$	2,820		$	2,879		$	2,586		$	1,021		$	2,178		$	3,018
Weighted-average assumptions (net benefit cost)
Discount rate		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%
Expected return on plan assets		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		2.75	%		3.00	%		3.25	%		2.75	%		3.00	%		N/A			N/A			N/A

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

	2014												2013												2012
	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)	$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)	$	74,853		$	70,016		$	4,111		$	726
Amortization of prior service cost (b)		(355	)		—			—			(355	)		(355	)		—			—			(355	)		—			—			—			—
Amortization of transition obligation (b)		—			—			—			—			—			—			—			—			(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)		(25,597	)		(23,883	)		(683	)		(1,031	)
Prior service cost		6,661			—			—			6,661			—			—			—			—			2,423			—			—			2,423
Regulatory adjustment		(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868			(42,771	)		(41,520	)		—			(1,251	)
Recognized in other comprehensive
(income) loss		15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—			8,041			4,613			3,428			—
Net periodic benefit costs recognized in net income		38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178			42,292			36,688			2,586			3,018
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178		$	50,333		$	41,301		$	6,014			$3,018

The table above discloses the net gain or loss, prior service cost, and transition amount 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, 2014 and December 31, 2013. The SERP has no assets. There were no transfers between Levels 1 and 2 during 2014.

	December 31, 2014						December 31, 2013
	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	$	6,661	$	198	$	6,859	$	8,224	$	244	$	8,468
Capital equipment		2,222		66		2,288		3,891		115		4,006
Chemicals/materials		5,233		155		5,388		8,228		244		8,472
Consumer goods		41,731		1,238		42,969		54,329		1,611		55,940
Energy and mining		18,502		549		19,051		36,126		1,071		37,197
Finance/insurance		20,685		613		21,298		37,643		1,116		38,759
Healthcare		37,846		1,122		38,968		40,426		1,199		41,625
Information technology		25,881		767		26,648		24,636		731		25,367
Services		28,846		855		29,701		31,212		926		32,138
Telecommunications/internet/media		18,498		549		19,047		24,270		720		24,990
Other		10,958		325		11,283		16,455		488		16,943
Real estate investment trusts		5,713		169		5,882		5,779		171		5,950
Mutual funds		86,159		24,567		110,726		76,764		22,495		99,259
Government fixed income securities		44,694		1,325		46,019		34,495		1,023		35,518
Preferred securities		568		17		585		—		—		—
Total Level 1 Assets (1)	$	354,197	$	32,515	$	386,712	$	402,478	$	32,154	$	434,632
Level 2 – Significant other observable inputs
Commercial paper	$	—	$	—	$	—	$	1,411	$	42	$	1,453
Government fixed income and mortgage backed securities		48,312		1,433		49,745		49,298		1,462		50,760
Corporate fixed income securities
Asset-backed and mortgage-backed		27,071		803		27,874		20,697		614		21,311
Banking		23,289		691		23,980		19,004		564		19,568
Insurance		6,182		183		6,365		6,481		192		6,673
Utilities		4,232		126		4,358		5,278		156		5,434
Other		23,120		686		23,806		19,649		582		20,231
Pooled funds and mutual funds		11,968		984		12,952		8,111		1,150		9,261
State and local obligations		1,499		44		1,543		1,370		41		1,411
Total Level 2 assets (2)	$	145,673	$	4,950	$	150,623	$	131,299	$	4,803	$	136,102
Level 3 – Significant unobservable inputs
Commingled equity funds	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Level 3 assets (3)	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070
Total Plan assets at fair value	$	759,105	$	45,152	$	804,257	$	723,229	$	42,575	$	765,804
Insurance company general account contracts (4)		4,003		—		4,003		4,296		—		4,296
Total Plan assets (5)	$	763,108	$	45,152	$	808,260	$	727,525	$	42,575	$	770,100

(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) Assets not considered Level 1 or Level 2 are valued using assumptions based on the best information available under the circumstances, such as investment manager pricing.

The commingled equity funds include private equity funds that invest in domestic and international securities (predominately Level 1 assets) regularly traded on securities exchanges. These funds are shown in the above table at net asset value. 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.

(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 $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) and $7,842,000 (qualified retirement plan – $7,581,000, PBOP – $261,000) for 2014 and 2013, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2012	$	127,467
Actual return on plan assets:
Relating to assets still held at the reporting date		21,903
Relating to assets sold during the period		—
Purchases		45,700
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2013		195,070
Actual return on plan assets:
Relating to assets still held at the reporting date		(6,932	)
Relating to assets sold during the period		2,069
Purchases		82,615
Sales		(5,900	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2014	$	266,922

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Derivatives and Fair Value Measurements - Fair Values of Swaps in Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		$ 1,444
Liability derivatives not designated as hedging instruments	(5,425)	(623)
Net total not designated as hedging instruments	(5,425)	821
Swaps [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		126
Liability derivatives not designated as hedging instruments	(5,062)	(282)
Net total not designated as hedging instruments	(5,062)	(156)
Swaps [Member] | Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		7
Liability derivatives not designated as hedging instruments	(363)	(11)
Net total not designated as hedging instruments	(363)	(4)
Swaps [Member] | Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		257
Liability derivatives not designated as hedging instruments		(77)
Net total not designated as hedging instruments		180
Swaps [Member] | Prepaids and other current assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments		1,054
Liability derivatives not designated as hedging instruments		(253)
Net total not designated as hedging instruments		$ 801

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Income Taxes - Significant Components of Deferred Income Tax Expense (Benefit) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred federal and state:
Total deferred federal and state	$ 70,229	$ 70,147	$ 68,097
Deferred ITC, net	(861)	(861)	(861)
Total deferred income tax expense	69,368	69,286	67,236
Property-related items [Member]
Deferred federal and state:
Total deferred federal and state	52,814	62,737	64,249
Purchased gas cost adjustments [Member]
Deferred federal and state:
Total deferred federal and state	15,049	16,189	1,755
Employee benefits [Member]
Deferred federal and state:
Total deferred federal and state	109	(2,769)	564
All other deferred [Member]
Deferred federal and state:
Total deferred federal and state	$ 2,257	$ (6,010)	$ 1,529

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Income Taxes - Summary of Income Before Taxes and Noncontrolling Interest for Domestic and Foreign Operations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax [Line Items]
Total income before income taxes	$ 219,521	$ 222,815	$ 207,915
Foreign [Member]
Income Tax [Line Items]
Total income before income taxes	(1,950)
United States [Member]
Income Tax [Line Items]
Total income before income taxes	$ 221,471	$ 222,815	$ 207,915

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 17, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
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		46,637,647
Entity Public Float			$ 2,454,899,230

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2014

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

Stock-Based Compensation

Note 10 – Stock-Based Compensation

At December 31, 2014, 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):

	2014		2013		2012
Stock-based compensation plan expense, net of related tax benefits	$	8,130	$	8,012	$	7,396
Stock-based compensation plan related tax benefits		4,983		4,910		4,533

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 has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years.

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

	2014					2013					2012
	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		52		$	27.57		125		$	28.13		177		$	27.28
Exercised during the year		(16	)		24.31		(72	)		28.44		(52	)		25.25
Forfeited or expired during the year		—			—		(1	)		33.07		—			—
Outstanding and exercisable at year end		36		$	28.97		52		$	27.57		125		$	28.13

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):

	2014		2013		2012
Outstanding and exercisable	$	1,194	$	1,473	$	1,788
Exercised		451		1,402		928

	December 31, 2014		December 31, 2013		December 31, 2012
Market value of Southwest Gas stock	$	61.81	$	55.91	$	42.41

The weighted-average remaining contractual life for outstanding options was one year for 2014. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2014 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$25.00 to $26.10		17		0.5 Years	$	25.71
$29.08 to $33.07		19		1.5 Years	$	31.83

The Company received $379,000 in cash from the exercise of options during 2014 and a corresponding tax benefit of $167,000 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 subject to a final adjustment as determined by the Board of Directors) 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, 2014 (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		323		$	39.16		245		$	38.00
Granted		77			53.73		83			53.73
Dividends		7					7
Forfeited or expired		—			—		—			—
Vested and issued*		(136	)		36.23		(78	)		40.87
Nonvested/unissued at December 31, 2014		271		$	43.71		257		$	41.22

* 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 2013 and 2012 was $44.83 and $41.34, respectively.

As of December 31, 2014, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $2.9 million.

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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, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	$ 173,646	$ (100,345)	$ 74,853
Amortization of prior service cost	(355)	(355)
Amortization of transition obligation			(867)
Amortization of net actuarial loss	(23,656)	(34,177)	(25,597)
Prior service cost	6,661		2,423
Regulatory adjustment	(140,308)	123,630	(42,771)
Recognized in other comprehensive (income) loss	15,988	(11,247)	8,041
Net periodic benefit costs recognized in net income	38,172	48,141	42,292
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	54,160	36,894	50,333
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	163,215	(91,115)	70,016
Amortization of net actuarial loss	(22,872)	(32,261)	(23,883)
Regulatory adjustment	(129,031)	113,762	(41,520)
Recognized in other comprehensive (income) loss	11,312	(9,614)	4,613
Net periodic benefit costs recognized in net income	34,331	43,084	36,688
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	45,643	33,470	41,301
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	5,460	(662)	4,111
Amortization of net actuarial loss	(784)	(971)	(683)
Recognized in other comprehensive (income) loss	4,676	(1,633)	3,428
Net periodic benefit costs recognized in net income	2,820	2,879	2,586
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	7,496	1,246	6,014
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net actuarial loss (gain)	4,971	(8,568)	726
Amortization of prior service cost	(355)	(355)
Amortization of transition obligation			(867)
Amortization of net actuarial loss		(945)	(1,031)
Prior service cost	6,661		2,423
Regulatory adjustment	(11,277)	9,868	(1,251)
Net periodic benefit costs recognized in net income	1,021	2,178	3,018
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$ 1,021	$ 2,178	$ 3,018

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Stock-Based Compensation - Schedule of Nonvested Performance and Restricted Stock Unit Plans (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant date fair value, Granted	$ 44.83	$ 41.34
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested/unissued, Number of Units, at beginning of year			323
Nonvested, Number of Units, Granted			77
Nonvested, Number of Units, Dividends			7
Nonvested, Number of Units, Forfeited or expired			0
Nonvested, Number of Units, Vested and issued			(136)
Nonvested/unissued, Number of Units, Ending balance			271
Weighted-average grant date fair value, Beginning balance			$ 39.16
Weighted-average grant date fair value, Granted			$ 53.73
Weighted-average grant date fair value, Dividends
Weighted-average grant date fair value, Forfeited or expired			$ 0
Weighted-average grant date fair value, Vested and issued			$ 36.23
Weighted-average grant date fair value, Ending balance			$ 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			245
Nonvested, Number of Units, Granted			83
Nonvested, Number of Units, Dividends			7
Nonvested, Number of Units, Forfeited or expired			0
Nonvested, Number of Units, Vested and issued			(78)
Nonvested/unissued, Number of Units, Ending balance			257
Weighted-average grant date fair value, Beginning balance			$ 38.00
Weighted-average grant date fair value, Granted			$ 53.73
Weighted-average grant date fair value, Dividends
Weighted-average grant date fair value, Forfeited or expired			$ 0
Weighted-average grant date fair value, Vested and issued			$ 40.87
Weighted-average grant date fair value, Ending balance			$ 41.22

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues:
Gas operating revenues	$ 1,382,087	$ 1,300,154	$ 1,321,728
Construction revenues	739,620	650,628	606,050
Total operating revenues	2,121,707	1,950,782	1,927,778
Operating expenses:
Net cost of gas sold	505,356	436,001	479,602
Operations and maintenance	383,732	384,914	369,979
Depreciation and amortization	253,027	236,817	223,422
Taxes other than income taxes	47,252	45,551	41,728
Construction expenses	647,857	573,284	541,523
Total operating expenses	1,837,224	1,676,567	1,656,254
Operating income	284,483	274,215	271,524
Other income and (expenses):
Net interest deductions (Notes 6 and 7)	(72,069)	(63,700)	(68,020)
Other income (deductions)	7,107	12,300	4,411
Total other income and (expenses)	(64,962)	(51,400)	(63,609)
Income before income taxes	219,521	222,815	207,915
Income tax expense (Note 11)	78,373	77,942	75,276
Net income	141,148	144,873	132,639
Net income (loss) attributable to noncontrolling interests	22	(447)	(692)
Net income attributable to Southwest Gas Corporation	$ 141,126	$ 145,320	$ 133,331
Basic earnings per share (Notes 1 and 14)	$ 3.04	$ 3.14	$ 2.89
Diluted earnings per share (Notes 1 and 14)	$ 3.01	$ 3.11	$ 2.86
Average number of common shares outstanding	46,494	46,318	46,115
Average shares outstanding (assuming dilution)	46,944	46,758	46,555

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2014

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,	2014			2013
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	390,293		$	249,985
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,425			160
Deferred purchased gas costs (3)		87,556			18,217
Accrued purchased gas costs (4)		2,600			31,500
Unamortized premium on reacquired debt (5)		20,478			19,614
Other (6)		72,132			48,945
		578,484			368,421
Regulatory liabilities:
Accumulated removal costs		(304,000	)		(279,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		—			(981	)
Deferred gain on southern Nevada division operations facility (7)		(115	)		(253	)
Unamortized gain on reacquired debt (8)		(10,862	)		(11,398	)
Other (9)		(34,233	)		(26,482	)
Net regulatory assets	$	229,274		$	50,307

(1) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovery period is greater than five years. (See Note 9).

(2) The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the 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 12).

Instrument	Balance Sheet Location	2014		2013
Swaps	Deferred charges and other assets	$	363	$	4
Swaps	Prepaids and other current assets		5,062		156
Swaps	Other current liabilities		—		(801	)
Swaps	Other deferred credits		—		(180	)

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

(4) Included in Prepaids and other current assets 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) Balance was originally being amortized over a four-year period beginning in the fourth quarter of 2009. As a result of the most recent Nevada general rate case, the amortization period was extended through October 2015.

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

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

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Receivables and Related Allowances

12 Months Ended

Dec. 31, 2014

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

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

	December 31, 2014
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, 2011	$	3,182
Additions charged to expense		2,471
Accounts written off, less recoveries		(3,149	)
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

At December 31, 2014, the construction services segment (Centuri) had $142 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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Acquisition of Construction Services Businesses

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisition of Construction Services Businesses

Note 15 – Acquisition of Construction Services Businesses

As indicated in Note 1 – Summary of Significant Accounting Policies, under Consolidation, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses for $221 million. Previous owners of the acquired companies retained an approximate 10% interest in the Canadian subsidiaries of Centuri.

Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed as incurred. The Company’s allocation of the purchase price was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. The final purchase accounting has not yet been completed. Further refinement is expected to occur, including changes to income taxes and intangibles. However, no material changes are expected. The preliminary estimated fair values of assets acquired and liabilities assumed as of October 1, 2014, are as follows (in millions of dollars):

Cash, cash equivalents, and restricted cash	$	3
Contracts receivable and other receivables		62
Property, plant and equipment		17
Other assets		17
Intangible assets		52
Goodwill		130
Total assets acquired		281
Current liabilities		39
Deferred income tax—long-term		17
Other long-term liabilities		4
Net assets acquired	$	221

Acquired contracts receivable and other receivables are expected to be collected.

The preliminary allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill, which is generally not deductible for tax purposes, consists of the value associated with the assembled workforce and consolidation of operations. The business of Brigadier was acquired via asset purchase. Therefore, the $4.9 million of tax-basis goodwill assigned to Brigadier is expected to be deductible for tax purposes. All other goodwill associated with the acquisition is not deductible for tax purposes. At December 31, 2014, the balance of goodwill associated with the acquisition was $125 million after consideration of changes in foreign currency adjustments. At December 31, 2014, other intangible assets totaled $48.2 million (after foreign currency adjustments of $1.9 million and approximately $1.5 million accumulated amortization). Intangible assets (as of December 2014) consist of $500,000 in non-competition agreements (net of approximately $40,000 of accumulated amortization, with a 5-year weighted-average useful life), $36.5 million in customer relationships (net of approximately $550,000 accumulated amortization, with useful lives ranging from 12 to 21 years), $10 million in trade names (net of approximately $250,000 accumulated amortization, with useful lives ranging from 4 to 20 years), and $1.2 million in work backlog (net of approximately $700,000 accumulated amortization, with an 8-month useful life). The intangible assets other than goodwill are included in Other property and investments in the Consolidated Balance Sheets. The estimated future amortization of the intangible assets acquired in the acquisition for the next five years is as follows (in thousands):

2015	$	4,615
2016		3,371
2017		3,371
2018		3,123
2019		2,370

In connection with the acquisition, previous owners retained certain ownership rights, specifically, an approximate 10% stock ownership interest in the associated Canadian businesses. However, while the actual ownership interest was approximately 10% of Lynxus (Canadian operations), the terms of the underlying equity agreements include dividend participation rights equal to 3.4% of dividends declared at the level of Centuri. Additionally, these same agreements include, among other terms, the ability of the prior owners to exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021. Furthermore, the equity agreements include an exchange feature such that the noncontrolling ownership interest retained by the parties, in the Canadian subsidiaries, may be convertible into shares equivalent to a 3.4% interest in Centuri (redeemable noncontrolling interest). In consideration of these circumstances and the underlying agreements, it was deemed appropriate to allocate earnings to the redeemable noncontrolling interest at an amount equivalent to approximately 3.4% of total Centuri earnings (rather than based on the actual current proportional ownership). Through this earnings allocation process, approximately 96.6% of Centuri earnings are attributable to the Company. This earnings allocation takes place before the redeemable noncontrolling interest balance, included on the balance sheet, is adjusted based on its redemption value. Adjustments to redemption value through December 31, 2014 impacted retained earnings but not current net income. See also Earnings Per Share included within Note 1, and discussion below regarding adjustment to fair value, as well as Note 16 – Construction Services Noncontrolling Interests for more information.

The unaudited pro forma consolidated financial information for fiscal 2014 and fiscal 2013 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning fiscal 2013) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31,
	2014		2013
Total operating revenues	$	2,295,318	$	2,203,272
Net income attributable to Southwest Gas Corporation	$	149,588	$	143,424
Basic earnings per share	$	3.22	$	3.10
Diluted earnings per share	$	3.19	$	3.07

Acquisition costs of $5 million that were incurred during 2014, and included in construction expenses in the Consolidated Statements of Income, were excluded from the 2014 unaudited pro forma consolidated financial information shown above and included in the 2013 amounts. No material nonrecurring pro forma adjustments directly attributable to the business combination were included in the unaudited pro forma consolidated financial information.

The pro forma financial information includes assumptions and adjustments made to incorporate various items including, but not limited to, additional interest expense and depreciation and amortization expense, and intercompany eliminations and tax effects, as appropriate. The pro forma financial information has been prepared for comparative purposes only, and is not intended to be indicative of what the Company’s results would have been had the acquisition occurred at the beginning of the periods presented or of the results which may occur in the future, for a number of reasons. These reasons include, but are not limited to, differences between the assumptions used to prepare the pro forma information, potential cost savings from operating efficiencies, and the impact of incremental costs incurred in integrating the businesses.

Actual results from Link-Line, W.S. Nicholls, and Brigadier operations included in the Consolidated Statements of Income since the date of acquisition are as follows (in thousands of dollars):

	Year ended December 31, 2014
Construction revenues	$	54,264
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier	$	1,859

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Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Note 11 – 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,	2014			2013		2012
U.S.	$	221,471		$	222,815	$	207,915
Foreign		(1,950	)		—		—
Total income before income taxes	$	219,521		$	222,815	$	207,915

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

Year Ended December 31,	2014			2013		2012
Current:
Federal	$	1,739		$	3,549	$	2,296
State		5,073			5,107		5,744
Foreign		2,193			—		—
		9,005			8,656		8,040
Deferred:
Federal		71,439			67,414		65,551
State		614			1,872		1,685
Foreign		(2,685	)		—		—
		69,368			69,286		67,236
Total income tax expense	$	78,373		$	77,942	$	75,276

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

Year Ended December 31,	2014			2013			2012
Deferred federal and state:
Property-related items	$	52,814		$	62,737		$	64,249
Purchased gas cost adjustments		15,049			16,189			1,755
Employee benefits		109			(2,769	)		564
All other deferred		2,257			(6,010	)		1,529
Total deferred federal and state		70,229			70,147			68,097
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	69,368		$	69,286		$	67,236

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2012, 2013, and 2014 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2014			2013			2012
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.9			2.4			2.6
Property-related items		0.1			0.1			0.2
Tax credits		(0.5	)		(0.4	)		(0.4	)
Company owned life insurance		(1.0	)		(2.1	)		(1.3	)
All other differences		0.2			—			0.1
Consolidated effective income tax rate		35.7	%		35.0	%		36.2	%

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

December 31,	2014			2013
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	2,146		$	2,679
Employee benefits		31,557			25,591
Alternative minimum tax credit		20,172			19,739
Net operating losses and credits		9,719			15,113
Interest rate swap		8,622			9,893
Other		25,872			22,334
Valuation allowance		(253	)		(200	)
		97,835			95,149
Deferred tax liabilities:
Property-related items, including accelerated depreciation		736,810			694,024
Regulatory balancing accounts		33,736			18,688
Property-related items previously flowed through		28			836
Unamortized ITC		3,410			4,271
Debt-related costs		5,066			4,713
Intangibles		12,792			—
Other		27,572			15,898
		819,414			738,430
Net deferred tax liabilities		721,579			643,281
Current		(2,109	)		(31,130	)
Noncurrent		723,688			674,411
Net deferred tax liabilities	$	721,579		$	643,281

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, various states, and in Canada. The Company is currently under examination in Canada for years 2011 and 2012. With few exceptions, the Company is no longer subject to United States federal, state and local, or Canadian income tax examinations for years before 2010.

At December 31, 2014, the Company has a U.S. federal net operating loss carryforward of $28 million which expires in 2031. The Company also has federal general business credits of $711,000, which begin to expire in 2031. The Company also has U.S. federal net capital loss carryforwards of $494,000, which begin to expire in 2016. At December 31, 2014, the Company has an income tax net operating loss carryforward related to Canadian operations of $1.1 million which expires in 2034.

As of December 31, 2014, 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):

	2014		2013
Unrecognized tax benefits at beginning of year	$	—	$	—
Gross increases-tax positions in prior period		305		—
Gross decreases-tax positions in prior period		—		—
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	$	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 limitations, 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, 2014. 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. Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):

	2014		2013		2012
Tax-related interest income	$	—	$	—	$	24

Final and Proposed Income Tax Regulations. In September 2013, the United States Department of the Treasury and the Internal Revenue Service (“IRS”) issued final and proposed regulations for the tax treatment of tangible property. The final regulations include standards for determining whether and when a taxpayer must capitalize costs incurred in acquiring, maintaining, or improving tangible property. The final 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. Proposed 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 final and proposed 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.

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Stock-Based Compensation - Schedule of Stock-Based Plan Compensation Expense, Including Cash Award (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation plan expense, net of related tax benefits	$ 8,130	$ 8,012	$ 7,396
Stock-based compensation plan related tax benefits	$ 4,983	$ 4,910	$ 4,533

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Short-Term Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Short-Term Debt

Note 7 – Short-Term Debt

As discussed in Note 6, Southwest has a $300 million credit facility that is scheduled to expire in March 2019, of which $150 million has been designated by management for working capital purposes. The Company had $5 million in short-term borrowings outstanding at December 31, 2014 and no short-term borrowings outstanding at December 31, 2013. The effective interest rate on the short-term portion of the credit facility was 1.13% at December 31, 2014.

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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) (USD $)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Other comprehensive income loss, effective income tax rate	38.00%
Tax expense or benefit for currency translation adjustment	$ 0

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Segment Information - Schedule of Segment Reporting Information (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Income tax payable netted		$ 666,000
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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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI")

12 Months Ended

Dec. 31, 2014

Text Block [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 and Redeemable Noncontrolling Interest.

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

	2014									2013									2012
	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
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(135	)		220			355			(135	)		220			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			(329	)		538
Amortization of net actuarial (gain)/loss		23,656			(8,989	)		14,667			34,177			(12,987	)		21,190			25,597			(9,727	)		15,870
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)		42,771			(16,253	)		26,518
Pension plans other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973			(8,041	)		3,056			(4,985	)
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		—			—			—			—			—			—			2,959			(1,125	)		1,834
Amounts reclassified into net income		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			2,801			(1,064	)		1,737
FSIRS other comprehensive income (loss)		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			5,760			(2,189	)		3,571
Foreign currency translation adjustments:
Translation adjustments		(659	)		—			(659	)		—			—			—			—			—			—
Foreign currency other comprehensive income (loss)		(659	)		—			(659	)		—			—			—			—			—			—
Total other comprehensive income (loss)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047		$	(2,281	)	$	867		$	(1,414	)

(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	$	33,000
SERP net actuarial loss		1,300
PBOP net actuarial loss		300
PBOP prior service cost		1,300

Approximately $2.1 million of previously realized losses (net of tax) related to the forward-starting interest rate swaps (“FSIRS”), included in AOCI at December 31, 2014, 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 9)									FSIRS (Note 12)									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, 2013	$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	—		$	—	$	—		$	(41,698	)
Net actuarial gain/(loss)		(173,646	)		65,985			(107,661	)		—			—			—			—			—		—			(107,661	)
Translation adjustments		—			—			—			—			—			—			(659	)		—		(659	)		(659	)
Other comprehensive income before reclassi fications		(173,646	)		65,985			(107,661	)		—			—			—			(659	)		—		(659	)		(108,320	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,345			(1,272	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		355			(135	)		220			—			—			—			—			—		—			220
Amortization of net actuarial loss (2)		23,656			(8,989	)		14,667			—			—			—			—			—		—			14,667
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			—			—		—			(4,130	)
Regulatory adjustment (3)		140,308			(53,317	)		86,991			—			—			—			—			—		—			86,991
Net current period other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(659	)		—		(659	)		(8,499	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(22	)		—		(22	)		(22	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(637	)		—		(637	)		(8,477	)
Ending Balance AOCI December 31, 2014	$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)

(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 9 – Pension and Other Postretirement Benefits for additional details).

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

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, 2014 and 2013:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2014			2013
Net actuarial (loss) gain	$	(439,131	)	$	(289,141	)
Prior service cost		(8,373	)		(2,067	)
Less: amount recognized in regulatory assets		390,293			249,985
Recognized in AOCI	$	(57,211	)	$	(41,223	)

See Note 9 – Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 12 – Derivatives and Fair Value Measurements for more information on the FSIRS.

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Long-Term Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Long-Term Debt

Note 6 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2014 and December 31, 2013 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 utilizes 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,	2014					2013
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	133,403	$	125,000		$	130,953
Notes, 6.1%, due 2041		125,000			157,290		125,000			141,873
Notes, 3.875%, due 2022		250,000			262,030		250,000			252,485
Notes, 4.875%, due 2043		250,000			280,903		250,000			257,280
8% Series, due 2026		75,000			102,296		75,000			96,263
Medium-term notes, 7.59% series, due 2017		25,000			27,573		25,000			28,741
Medium-term notes, 7.78% series, due 2022		25,000			31,144		25,000			30,586
Medium-term notes, 7.92% series, due 2027		25,000			33,695		25,000			31,497
Medium-term notes, 6.76% series, due 2027		7,500			9,156		7,500			8,468
Unamortized discount		(5,223	)				(5,560	)
		902,277					901,940
Revolving credit facility and commercial paper		150,000			150,000		10,000			10,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
5.25% 2003 Series D, due 2038		20,000			20,277		20,000			20,150
5.25% 2004 Series A, due 2034		—			—		65,000			64,522
5.00% 2004 Series B, due 2033		31,200			31,223		31,200			30,284
4.85% 2005 Series A, due 2035		100,000			100,071		100,000			95,192
4.75% 2006 Series A, due 2036		24,855			25,399		24,855			22,974
Unamortized discount		(1,943	)				(2,776	)
		374,112					438,279
Centuri secured revolving credit and term loan facility		199,267			200,341		—			—
Centuri other debt obligations		31,128			31,127		42,213			42,119
		1,656,784					1,392,432
Less: current maturities		(19,192	)				(11,105	)
Long-term debt, less current maturities	$	1,637,592				$	1,381,327

In March 2014, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2017, but was extended to March 2019. Southwest will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. In addition to extending the credit facility, among other amendments, the applicable margins and unused commitment fees were reduced and the Pricing Level definitions were modified. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At December 31, 2014, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2014, $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 1.21% at December 31, 2014. Borrowings under the credit facility ranged from none during the first and second quarters of 2014 to a high of $165 million during November and December 2014. With regard to the short-term portion of the credit facility, there was $5 million outstanding at December 31, 2014 and no borrowings outstanding at December 31, 2013. (See Note 7 – Short-Term Debt).

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

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, 2014, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.65% at December 31, 2014.

In October 2014, construction services subsidiaries of the Company entered into a $300 million secured revolving credit and term loan facility. The facility is scheduled to expire in October 2019 and replaces the previous $75 million credit facility, which was scheduled to expire in June 2015. The 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, 2014 totaled $477 million.

Interest rates for Centuri’s $300 million secured 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 credit facility ranged from a low of $199 million during December 2014 to a high of $232 million during October 2014. All amounts outstanding are considered long-term borrowings. The outstanding amount on the facility at December 31, 2014 includes term loans in the amount of $142 million. The effective interest rate on the facility was 3.31% at December 31, 2014.

In November 2014, Southwest’s $65 million 2004 5.25% Series A fixed-rate IDRBs (originally due in 2034) were redeemed at par plus accrued interest.

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

	December 31, 2014			December 31, 2013
2003 Series A		0.85	%		1.43	%
2008 Series A		0.90	%		1.41	%
2009 Series A		0.89	%		1.01	%
Tax-exempt Series A		0.84	%		1.07	%

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):

2015	$	19,192
2016		20,991
2017		43,899
2018		16,985
2019		304,328

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, 2014, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $1.9 billion in additional debt and meet the leverage ratio requirement. The Company has at least $900 million 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, 2014, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $88 million in additional debt and meet the leverage ratio requirement. Centuri has at least $35 million of cushion in equity relating to the minimum fixed charge ratio coverage requirement.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 8 – 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 2014 to July 2015, these liability insurance policies require Southwest to be responsible for the first $1 million dollars (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. 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.

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Amount Recognized Before Income Tax in Accumulated Other Comprehensive Income (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Prior service cost	$ 6,661	$ 2,423
Less: amount recognized in regulatory assets	578,484		368,421
Recognized in AOCI	(57,211)		(41,223)
Defined Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net actuarial (loss) gain	(439,131)		(289,141)
Prior service cost	(8,373)		(2,067)
Less: amount recognized in regulatory assets	390,293		249,985
Recognized in AOCI	$ (57,211)		$ (41,223)

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Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options, maximum term, years	10 years
Weighted-average remaining contractual life of outstanding options, years	1 year
Cash received from exercise of stock options	$ 379,000
Tax benefit realized from exercise of stock options	167,000
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		$ 44.83	$ 41.34
Total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized	$ 2,900,000

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Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Nov. 30, 2014
Notes, 4.45%, due 2020 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	4.45%	4.45%
Debt instrument due date	Dec. 01, 2020	Dec. 01, 2020
Notes, 6.1%, due 2041 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate			6.10%
Notes, 6.1%, due 2041 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	6.10%	6.10%
Debt instrument due date	Feb. 15, 2041	Feb. 15, 2041
Notes, 3.875%, due 2022 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	3.875%	3.875%
Debt instrument due date	Apr. 01, 2022	Apr. 01, 2022
Notes, 4.875%, due 2043 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	4.875%	4.875%
Debt instrument due date	Oct. 01, 2043	Oct. 01, 2043
8% Series, due 2026 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	8.00%	8.00%
Debt instrument due date	Aug. 01, 2026	Aug. 01, 2026
Medium-term notes, 7.59% series, due 2017 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	7.59%	7.59%
Debt instrument due date	Jan. 17, 2017	Jan. 17, 2017
Medium-term notes, 7.78% series, due 2022 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	7.78%	7.78%
Debt instrument due date	Feb. 03, 2022	Feb. 03, 2022
Medium-term notes, 7.92% series, due 2027 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	7.92%	7.92%
Debt instrument due date	Jun. 04, 2027	Jun. 04, 2027
Medium-term notes, 6.76% series, due 2027 [Member] | Debentures [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	6.76%	6.76%
Debt instrument due date	Sep. 24, 2027	Sep. 24, 2027
Tax-exempt Series A, due 2028 [Member] | Variable-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument due date	Dec. 01, 2028	Dec. 01, 2028
2003 Series A, due 2038 [Member] | Variable-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument due date	Mar. 01, 2038	Mar. 01, 2038
2008 Series A, due 2038 [Member] | Variable-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument due date	Mar. 01, 2038	Mar. 01, 2038
2009 Series A, due 2039 [Member] | Variable-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument due date	Dec. 01, 2039	Dec. 01, 2039
5.25% 2003 Series D, due 2038 [Member] | Fixed-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	5.25%	5.25%
Debt instrument due date	Mar. 01, 2038	Mar. 01, 2038
5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Debt instrument interest rate				5.25%
5.25% 2004 Series A, due 2034 [Member] | Fixed-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	5.25%	5.25%
Debt instrument due date	Jul. 01, 2034	Jul. 01, 2034
5.00% 2004 Series B, due 2033 [Member] | Fixed-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	5.00%	5.00%
Debt instrument due date	Dec. 01, 2033	Dec. 01, 2033
4.85% 2005 Series A, due 2035 [Member] | Fixed-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	4.85%	4.85%
Debt instrument due date	Oct. 01, 2035	Oct. 01, 2035
4.75% 2006 Series A, due 2036 [Member] | Fixed-rate bonds [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	4.75%	4.75%
Debt instrument due date	Sep. 01, 2036	Sep. 01, 2036

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Derivatives and Fair Values Measurements - Gains (Losses) Recognized in Other Comprehensive Income for Derivatives as Cash Flow Hedging Instruments (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative			$ 2,959

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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Rollforward of Accumulated Other Comprehensive Income (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance AOCI December 31, 2013, Defined Benefit Plans Before-Tax	$ (41,223)
Net actuarial gain/(loss), Defined Benefit Plans Before-Tax	(173,646)	100,345	(74,853)
Translation adjustments, Defined Benefit Plans Before-Tax	0
FSIRS amounts reclassified from AOCI, FSIRS - Tax (Expense) Benefit	(1,272)	(1,271)	(1,064)
Amortization of prior service costs, Defined Benefit Plans Before-Tax	355	355
Amortization of net actuarial loss, Defined Benefit Plans Before-Tax	23,656	34,177	25,597
Prior service cost, Defined Benefit Plans Before-Tax	(6,661)		(2,423)
Regulatory adjustment, Defined Benefit Plans Before-Tax	140,308	(123,630)	42,771
Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax	(15,988)	11,247	(8,041)
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	(15,988)
Ending Balance AOCI December 31, 2014, Defined Benefit Plans Before-Tax	(57,211)	(41,223)
Beginning Balance AOCI December 31, 2013, Defined Benefit Plans Tax (Expense) Benefit	15,665
Net actuarial gain/(loss), Tax Expense or Benefit	65,985	(38,131)	28,444
Translation adjustments, Defined Benefit Plans Tax (Expense) Benefit	0
Amortization of prior service costs, Defined Benefit Plans Tax (Expense) Benefit	(135)	(135)
Amortization of net actuarial loss, Defined Benefit Plans Tax (Expense) Benefit	(8,989)	(12,987)	(9,727)
Prior service cost, Defined Benefit Plans Tax (Expense) Benefit	2,531		921
Regulatory adjustment, Defined Benefit Plans Tax (Expense) Benefit	(53,317)	46,979	(16,253)
Net current period other comprehensive income (loss), Defined Benefit Plans Tax (Expense) Benefit	6,075	(4,274)	3,056
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	6,075
Ending Balance AOCI December 31, 2014 Defined Benefit Plans Tax (Expense) Benefit	21,740	15,665
Beginning Balance AOCI December 31, 2013, Defined Benefit Plans After-Tax	(25,558)
Net actuarial gain/(loss), Defined Benefit Plans After-Tax	(107,661)	62,214	(46,409)
Translation adjustments, Defined Benefit Plans After-Tax	0
Amortization of prior service costs, Defined Benefit Plans After-Tax	220	220
Amortization of net actuarial (gain)/loss, Net-of-Tax Amount	14,667	21,190	15,870
Prior service cost	(4,130)		(1,502)
Regulatory adjustment, Defined Benefit Plans After-Tax	86,991
Net defined benefit pension plans	(9,913)	6,973	(4,985)
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	(9,913)
Ending Balance AOCI December 31, 2014, Defined Benefit Plans After-Tax	(35,471)	(25,558)
Beginning Balance AOCI December 31, 2013, FSIRS - Before-Tax	(26,033)
FSIRS amounts reclassified from AOCI, FSIRS - Before-Tax	3,345	3,345	2,801
FSIRS other comprehensive income (loss), Before-Tax Amount	3,345	3,345	5,760
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	3,345
Ending Balance AOCI December 31, 2014, FSIRS - Before-Tax	(22,688)	(26,033)
Beginning Balance AOCI December 31, 2013, FSIRS - Tax (Expense) Benefit	9,893
FSIRS other comprehensive income (loss), Tax (Expense) or Benefit	(1,272)	(1,271)	(2,189)
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	(1,272)
Ending Balance AOCI September 30, 2014, FSIRS - Tax (Expense) Benefit	8,621	9,893
Beginning Balance AOCI December 31, 2013, FSIRS - After-Tax	(16,140)
FSIRS amounts reclassified from AOCI, FSIRS - After-Tax	2,073	2,074	1,737
Net forward-starting interest rate swaps	2,073	2,074	3,571
Less: Translation adjustment attributable to redeemable noncontrolling interest, FSIRS - After-Tax	0
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - After-Tax	2,073
Ending Balance AOCI December 31, 2014, FSIRS - After-Tax	(14,067)	(16,140)
Net actuarial gain/(loss), Foreign Currency Items Before-Tax	0
Translation adjustments, Foreign Currency Items Before-Tax	(659)
Other comprehensive income before reclassifications, Foreign Currency Items Before-Tax	(659)
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
Prior service cost, Foreign Currency Items Before-Tax	0
Regulatory adjustment, Foreign Currency Items Before-Tax	0
Net current period other comprehensive income (loss), Foreign Currency Items Before-Tax	(659)
Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency Items Before-Tax	(22)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items Before-Tax	(659)
Ending Balance AOCI December 31, 2014, Foreign Currency Items Before-Tax	(637)
Beginning Balance AOCI December 31, 2013,Foreign Currency items - Tax (Expense) Benefit	0
Net actuarial gain/(loss),Foreign Currency items - Tax (Expense) Benefit	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
Prior service cost ,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, 2014,Foreign Currency items - Tax (Expense) Benefit	0	0
Net actuarial gain/(loss), Foreign Currency items - After-Tax	0
Translation adjustments, Foreign Currency items - After-Tax	(659)
Other comprehensive income before reclassifications, Foreign Currency items - After-Tax	(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
Prior service cost, 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	(659)
Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency items - After-Tax	(22)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items - After-Tax	(659)
Ending Balance AOCI December 31, 2014, Foreign Currency items - After-Tax	(637)
Beginning Balance AOCI December 31, 2013, AOCI	(41,698)
Net actuarial gain/(loss), AOCI	(107,661)	62,214	(46,409)
Translation adjustments, AOCI	(659)
Amounts reclassified into net income (Notes 5 and 12)	2,073	2,074	1,737
Amortization of prior service cost, AOCI	220	220
Amortization of net actuarial loss	14,667	21,190	15,870
Prior service cost, AOCI	(4,130)
Regulatory adjustment, AOCI	86,991
Net current period other comprehensive income (loss)	(8,499)
Less: Translation adjustment attributable to redeemable noncontrolling interest, AOCI	(22)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, AOCI	(8,477)
Ending Balance AOCI December 31, 2014, AOCI	(50,175)	(41,698)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income before reclassifications, FSIRS - Tax (Expense) Benefit	0
FSIRS amounts reclassified from AOCI, FSIRS - Tax (Expense) Benefit	(1,272)
Other comprehensive income before reclassifications, Defined Benefit Plans Before-Tax	(173,646)
Prior service cost, FSIRS - Tax (Expense) Benefit	0
Translation adjustments, Defined Benefit Plans Tax (Expense) Benefit	0
Other comprehensive income before reclassifications, Defined Benefit Plans Tax (Expense) Benefit	65,985
Other comprehensive income before reclassifications, Defined Benefit Plans After-Tax	(107,661)
Translation adjustments, FSIRS - Before-Tax	0
Other comprehensive income before reclassifications, FSIRS - Before-Tax	0
FSIRS amounts reclassified from AOCI, FSIRS - Before-Tax	3,345
Prior service cost, FSIRS - Before-Tax	0
Translation adjustments, FSIRS - After-Tax	0
Other comprehensive income before reclassifications, FSIRS - After-Tax	0
FSIRS amounts reclassified from AOCI, FSIRS - After-Tax	2,073
Prior service cost, FSIRS - After-Tax	0
Other comprehensive income before reclassifications, AOCI	(108,320)
Amounts reclassified into net income (Notes 5 and 12)	$ 2,073

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Income Taxes - Summary of Income Tax Expense (Benefit) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$ 1,739	$ 3,549	$ 2,296
State	5,073	5,107	5,744
Foreign	2,193
Income tax expense (benefit), Current	9,005	8,656	8,040
Deferred:
Federal	71,439	67,414	65,551
State	614	1,872	1,685
Foreign	(2,685)
Total deferred income tax expense	69,368	69,286	67,236
Total income tax expense	$ 78,373	$ 77,942	$ 75,276

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

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,	2014			2013		2012
U.S.	$	221,471		$	222,815	$	207,915
Foreign		(1,950	)		—		—
Total income before income taxes	$	219,521		$	222,815	$	207,915

Summary of Income Tax Expense (Benefit)

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

Year Ended December 31,	2014			2013		2012
Current:
Federal	$	1,739		$	3,549	$	2,296
State		5,073			5,107		5,744
Foreign		2,193			—		—
		9,005			8,656		8,040
Deferred:
Federal		71,439			67,414		65,551
State		614			1,872		1,685
Foreign		(2,685	)		—		—
		69,368			69,286		67,236
Total income tax expense	$	78,373		$	77,942	$	75,276

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,	2014			2013			2012
Deferred federal and state:
Property-related items	$	52,814		$	62,737		$	64,249
Purchased gas cost adjustments		15,049			16,189			1,755
Employee benefits		109			(2,769	)		564
All other deferred		2,257			(6,010	)		1,529
Total deferred federal and state		70,229			70,147			68,097
Deferred ITC, net		(861	)		(861	)		(861	)
Total deferred income tax expense	$	69,368		$	69,286		$	67,236

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 2012, 2013, and 2014 (and the sources of these differences and the effect of each) are summarized as follows:

Year Ended December 31,	2014			2013			2012
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.9			2.4			2.6
Property-related items		0.1			0.1			0.2
Tax credits		(0.5	)		(0.4	)		(0.4	)
Company owned life insurance		(1.0	)		(2.1	)		(1.3	)
All other differences		0.2			—			0.1
Consolidated effective income tax rate		35.7	%		35.0	%		36.2	%

Deferred Tax Assets and Liabilities

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

December 31,	2014			2013
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	2,146		$	2,679
Employee benefits		31,557			25,591
Alternative minimum tax credit		20,172			19,739
Net operating losses and credits		9,719			15,113
Interest rate swap		8,622			9,893
Other		25,872			22,334
Valuation allowance		(253	)		(200	)
		97,835			95,149
Deferred tax liabilities:
Property-related items, including accelerated depreciation		736,810			694,024
Regulatory balancing accounts		33,736			18,688
Property-related items previously flowed through		28			836
Unamortized ITC		3,410			4,271
Debt-related costs		5,066			4,713
Intangibles		12,792			—
Other		27,572			15,898
		819,414			738,430
Net deferred tax liabilities		721,579			643,281
Current		(2,109	)		(31,130	)
Noncurrent		723,688			674,411
Net deferred tax liabilities	$	721,579		$	643,281

Reconciliation of Unrecognized Tax Benefits

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

	2014		2013
Unrecognized tax benefits at beginning of year	$	—	$	—
Gross increases-tax positions in prior period		305		—
Gross decreases-tax positions in prior period		—		—
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	$	305	$	—

Summary of Tax-Related Interest Income

Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):

	2014		2013		2012
Tax-related interest income	$	—	$	—	$	24

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Utility Plant and Leases - Schedule of Capital Leases of Equipment (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Leases [Abstract]
Capital leases of equipment	$ 5,763
Less: accumulated amortization	(287)
Net capital leases	$ 5,476

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Segment Information

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segment Information

Note 13 – 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.

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, 2014		December 31, 2013
Accounts receivable for Centuri services	$	9,169	$	10,787

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

	December 31, 2014		December 31, 2013
Revenues (a)
United States	$	2,069,513	$	1,950,782
Canada		52,194		—
Total	$	2,121,707	$	1,950,782
Long-lived assets
United States	$	6,021,476		5,674,449
Canada		14,475		—
Total	$	6,035,951	$	5,674,449

(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, 2014 is as follows (thousands of dollars):

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	$	4,657,709	$	567,405	$	(10,599	)	$	5,214,515
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
2012	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,321,728	$	522,676				$	1,844,404
Intersegment sales		—		83,374					83,374
Total	$	1,321,728	$	606,050				$	1,927,778
Interest revenue	$	915	$	9				$	924
Interest expense	$	66,957	$	1,063				$	68,020
Depreciation and amortization	$	186,035	$	37,387				$	223,422
Income tax expense	$	64,973	$	10,303				$	75,276
Segment net income	$	116,619	$	16,712				$	133,331
Segment assets	$	4,204,948	$	283,109				$	4,488,057
Capital expenditures	$	308,951	$	86,761				$	395,712

(a) Construction services segment assets include 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 include 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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Acquisition of Construction Services Businesses - Schedule of Unaudited Pro Forma Consolidated Financial Information (Detail) (Link-Line, W.S. Nicholls, and Brigadier [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Link-Line, W.S. Nicholls, and Brigadier [Member]
Business Acquisition [Line Items]
Total operating revenues	$ 2,295,318	$ 2,203,272
Net income attributable to Southwest Gas Corporation	$ 149,588	$ 143,424
Basic earnings per share	$ 3.22	$ 3.10
Diluted earnings per share	$ 3.19	$ 3.07

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Schedule of Other Property and Investments

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

	2014			2013
Centuri property, equipment, and intangibles	$	405		$	320
Centuri accumulated provision for depreciation and amortization		(187	)		(163	)
Net cash surrender value of COLI policies		99			93
Other property		10			11
Total	$	327		$	261

Schedule of Accumulated Removal Costs

The reclassified amounts are presented in the table below (thousands of dollars):

	December 31, 2014		December 31, 2013
Accumulated removal costs	$	304,000	$	279,000

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.

	2014		2013		2012
(In thousands)
AFUDC:
Debt portion	$	1,228	$	1,260	$	1,129
Equity portion		1,995		2,274		1,943
AFUDC capitalized as part of utility plant	$	3,223	$	3,534	$	3,072

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):

	2014			2013			2012
Change in COLI policies	$	5,300		$	12,400		$	6,600
Interest income		2,602			461			924
Pipe replacement costs		—			(132	)		(2,680	)
Foreign currency transaction gain (loss)		(178	)		—			—
Miscellaneous income and (expense)		(617	)		(429	)		(433	)
Total other income (deductions)	$	7,107		$	12,300		$	4,411

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.

	2014		2013		2012
(In thousands)
Average basic shares		46,494		46,318		46,115
Effect of dilutive securities:
Stock options		17		26		42
Performance shares		215		231		254
Restricted stock units		218		183		144
Average diluted shares		46,944		46,758		46,555

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Income Taxes - Deferred Tax Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$ 2,146	$ 2,679
Employee benefits	31,557	25,591
Alternative minimum tax credit	20,172	19,739
Net operating losses and credits	9,719	15,113
Interest rate swap	8,622	9,893
Other	25,872	22,334
Valuation allowance	(253)	(200)
Deferred tax assets, total	97,835	95,149
Deferred tax liabilities:
Property-related items, including accelerated depreciation	736,810	694,024
Regulatory balancing accounts	33,736	18,688
Property-related items previously flowed through	28	836
Unamortized ITC	3,410	4,271
Debt-related costs	5,066	4,713
Intangibles	12,792
Other	27,572	15,898
Deferred tax liabilities, total	819,414	738,430
Net deferred tax liabilities	721,579	643,281
Current	(2,109)	(31,130)
Noncurrent	723,688	674,411
Net deferred tax liabilities	$ 721,579	$ 643,281

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Utility Plant and Leases - Schedule of Rental Payments for Operating Leases (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	$ 35,342	$ 35,426	$ 31,816
Southwest Gas [Member]
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	5,330	8,308	7,762
Centuri Construction Group [Member]
Rental Payments And Lease Payments Included In Operating Expenses [Line Items]
Consolidated rental payments/lease expense	$ 30,012	$ 27,118	$ 24,054

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Derivatives and Fair Value Measurements - Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Consolidated Balance Sheets (Detail) (Swaps [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Prepaids and other current assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ 5,062	$ 156
Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	363	4
Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Net Total		(180)
Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total		$ (801)

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Summary of Significant Accounting Policies - Schedule of Other Property and Investments (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Investment [Line Items]
Net cash surrender value of COLI policies	$ 99,000,000	$ 93,000,000
Other property	10,000,000	11,000,000
Total	326,743,000	260,871,000
Centuri Construction Group [Member]
Investment [Line Items]
Centuri property, equipment, and intangibles	405,000,000	320,000,000
Centuri accumulated provision for depreciation and amortization	$ (187,000,000)	$ (163,000,000)

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Segment Information - Accounts Receivable for Services (Detail) (Centuri Construction Group [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Centuri Construction Group [Member]
Segment Reporting Information [Line Items]
Accounts receivable for Centuri services	$ 9,169	$ 10,787

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	$ 141,148	$ 144,873	$ 132,639
Defined benefit pension plans (Notes 5 and 9):
Net actuarial gain (loss)	(107,661)	62,214	(46,409)
Amortization of prior service cost	220	220
Amortization of transition obligation			538
Amortization of net actuarial loss	14,667	21,190	15,870
Prior service cost	(4,130)		(1,502)
Regulatory adjustment	86,991	(76,651)	26,518
Net defined benefit pension plans	(9,913)	6,973	(4,985)
Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 12)			1,834
Amounts reclassified into net income (Notes 5 and 12)	2,073	2,074	1,737
Net forward-starting interest rate swaps	2,073	2,074	3,571
Foreign currency translation adjustments	(659)
Total other comprehensive income (loss), net of tax	(8,499)	9,047	(1,414)
Comprehensive income	132,649	153,920	131,225
Comprehensive income (loss) attributable to noncontrolling interests		(447)	(692)
Comprehensive income attributable to Southwest Gas Corporation	$ 132,649	$ 154,367	$ 131,917

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Stock-Based Compensation - Summary of Market Prices of Common Stock (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Market value of Southwest Gas stock	$ 61.81	$ 55.91	$ 42.41

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Utility Plant and Leases

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Utility Plant and Leases

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2014 and 2013 was as follows (thousands of dollars):

December 31,	2014			2013
Gas plant:
Storage	$	22,531		$	21,282
Transmission		312,300			313,306
Distribution		4,655,640			4,410,598
General		356,072			324,490
Software and software-related intangibles		196,035			168,815
Other		14,021			13,978
		5,556,599			5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413
Net utility plant	$	3,658,383		$	3,486,108

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

	2014		2013		2012
Depreciation and amortization expense	$	194,360	$	185,283	$	182,612

Included in the figures above is amortization of intangibles of $11.7 million in 2014, $10.3 million in 2013, and $9.3 million in 2012.

Operating Leases and Rentals.    In July 2014, the Company purchased for $16.5 million a portion of its corporate headquarters office complex in Las Vegas that it had previously leased. With the completion of the purchase, the lease terminated.

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):

	2014		2013		2012
Southwest Gas	$	5,330	$	8,308	$	7,762
Centuri		30,012		27,118		24,054
Consolidated rental payments/lease expense	$	35,342	$	35,426	$	31,816

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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	5,957
2016		4,236
2017		2,532
2018		1,582
2019		912
Thereafter		831
Total minimum lease payments	$	16,050

Capital Leases.    Centuri leases certain construction equipment. These leases are considered capital leases. The amount of capital leases of equipment as of December 31, 2014 and 2013 is as follows (thousands of dollars):

December 31,	2014			2013
Capital leases of equipment	$	5,763		$	—
Less: accumulated amortization		(287	)		—
Net capital leases	$	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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	1,690
2016		1,632
2017		813
2018		591
2019		—
Thereafter		—
		4,726
Less: amount representing interest		(497	)
Total minimum lease payments	$	4,229

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Parenthetical) (Detail) (Swaps [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred charges and other assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	$ 363	$ 4
Prepaids and other current assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	5,062	156
Other current liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value		(801)
Other deferred credits [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value		$ (180)

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Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Amounts not included in funded status table	$ 8,572,000	$ 7,842,000
Qualified Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Amounts not included in funded status table	8,312,000	7,581,000
PBOP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Amounts not included in funded status table	260,000	261,000
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [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 Plans and Other Postretirement Benefit Plans [Line Items]
Redemption notice period		30 days

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Derivatives and Fair Value Measurements - Significant Other Observable Inputs (Detail) (Level 2 - Significant other observable inputs [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Net Assets (Liabilities)	$ (5,425)	$ 821
Swaps [Member] | Prepaids and other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets		801
Swaps [Member] | Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets		180
Swaps [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	(5,062)	(156)
Swaps [Member] | Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	$ (363)	$ (4)

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Long-Term Debt - Estimated Maturities of Long-Term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014
Debt Disclosure [Abstract]
2015	$ 19,192
2016	20,991
2017	43,899
2018	16,985
2019	$ 304,328

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Utility Plant and Leases (Tables)

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Schedule of Net Utility Plant

Net utility plant as of December 31, 2014 and 2013 was as follows (thousands of dollars):

December 31,	2014			2013
Gas plant:
Storage	$	22,531		$	21,282
Transmission		312,300			313,306
Distribution		4,655,640			4,410,598
General		356,072			324,490
Software and software-related intangibles		196,035			168,815
Other		14,021			13,978
		5,556,599			5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413
Net utility plant	$	3,658,383		$	3,486,108

Schedule of Depreciation and Amortization Expense

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

	2014		2013		2012
Depreciation and amortization expense	$	194,360	$	185,283	$	182,612

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):

	2014		2013		2012
Southwest Gas	$	5,330	$	8,308	$	7,762
Centuri		30,012		27,118		24,054
Consolidated rental payments/lease expense	$	35,342	$	35,426	$	31,816

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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	5,957
2016		4,236
2017		2,532
2018		1,582
2019		912
Thereafter		831
Total minimum lease payments	$	16,050

Schedule of Capital Leases of Equipment

The amount of capital leases of equipment as of December 31, 2014 and 2013 is as follows (thousands of dollars):

December 31,	2014			2013
Capital leases of equipment	$	5,763		$	—
Less: accumulated amortization		(287	)		—
Net capital leases	$	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, 2014 (thousands of dollars):

Year Ending December 31,
2015	$	1,690
2016		1,632
2017		813
2018		591
2019		—
Thereafter		—
		4,726
Less: amount representing interest		(497	)
Total minimum lease payments	$	4,229

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Construction Services Noncontrolling Interests - Additional Information (Detail) (USD $)	3 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2014	Oct. 31, 2014	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Redeemable non-controlling interest, redemption value	$ 20,000		20,000
Increase in redemption value of redeemable noncontrolling interest	$ 961,000
Intellichoice Energy, LLC [Member]
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by noncontrolling owners	65.00%		65.00%
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member]
Noncontrolling Interest [Line Items]
Indirect equity interest percentage		10.00%
Description of indirect equity interest			The agreement, associated with the approximate 10% indirect equity interest of the sellers, provides special dividend rights which entitle the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri. and Subject to certain conditions, such interests may become exchangeable for a 3.4% equity interest in Centuri. Additionally, the previous owners may exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021.
Indirect equity interest dividend rights, percentage of dividends paid by Centuri		3.40%
Noncontrolling interest purchase date			2016-10
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Construction Services [Member]
Noncontrolling Interest [Line Items]
Indirect equity interest exchangeable percentage in Centuri		3.40%
Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Indirect equity interest percentage	100.00%		100.00%

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Pension and Other Postretirement Benefits - Schedule of Allocation of Plan Assets (Detail)	12 Months Ended
	Dec. 31, 2014
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%

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Acquisition of Construction Services Businesses (Tables)

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Preliminary Estimated Fair Values of Assets Acquired and Liabilities Assumed

The preliminary estimated fair values of assets acquired and liabilities assumed as of October 1, 2014, are as follows (in millions of dollars):

Cash, cash equivalents, and restricted cash	$	3
Contracts receivable and other receivables		62
Property, plant and equipment		17
Other assets		17
Intangible assets		52
Goodwill		130
Total assets acquired		281
Current liabilities		39
Deferred income tax—long-term		17
Other long-term liabilities		4
Net assets acquired	$	221

Schedule of Estimated Future Amortization of Intangible Assets Acquired

The estimated future amortization of the intangible assets acquired in the acquisition for the next five years is as follows (in thousands):

2015	$	4,615
2016		3,371
2017		3,371
2018		3,123
2019		2,370

Schedule of Unaudited Pro Forma Consolidated Financial Information

The unaudited pro forma consolidated financial information for fiscal 2014 and fiscal 2013 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning fiscal 2013) is as follows (in thousands of dollars, except per share amounts):

	Year Ended December 31,
	2014		2013
Total operating revenues	$	2,295,318	$	2,203,272
Net income attributable to Southwest Gas Corporation	$	149,588	$	143,424
Basic earnings per share	$	3.22	$	3.10
Diluted earnings per share	$	3.19	$	3.07

Schedule of Actual Results Included In Consolidated Statements of Income

Actual results from Link-Line, W.S. Nicholls, and Brigadier operations included in the Consolidated Statements of Income since the date of acquisition are as follows (in thousands of dollars):

	Year ended December 31, 2014
Construction revenues	$	54,264
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier	$	1,859

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Derivatives and Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Fair Value Measurements

Note 12 – 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.

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

The fixed-price contracts and Swaps are utilized by Southwest under its ongoing volatility mitigation programs to effectively fix the price on a portion (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2015 through March 2016. 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, 2014		December 31, 2013
Contract notional amounts		5,105		13,571

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

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2014, 2013, and 2012 and their location in the Consolidated Statements of Income (thousands of dollars):

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	2014			2013			2012
Swaps	Net cost of gas sold	$	(2,363	)	$	976		$	(4,854	)
Swaps	Net cost of gas sold		2,363	*		(976	)*		4,854	*
Total		$	—		$	—		$	—

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

In January 2010, 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 fixed-rate debt to replace maturing debt. The first FSIRS terminated in December 2010. The second FSIRS terminated in March 2012. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss (ineffective portion) was recognized in income for either FSIRS during any period, including the period presented in the following table.

Gains (losses) recognized in other comprehensive income for derivatives designated as cash flow hedging instruments:

	Year Ended December 31, 2014		Year Ended December 31, 2013		Year Ended December 31, 2012
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	—	$	—	$	2,959

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, 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	)
December 31, 2013 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	257	$	(77	)	$	180
Swaps	Prepaids and other current assets		1,054		(253	)		801
Swaps	Other current liabilities		126		(282	)		(156	)
Swaps	Other deferred credits		7		(11	)		(4	)
Total		$	1,444	$	(623	)	$	821

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

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under 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, 2014		Year ended December 31, 2013		Year ended December 31, 2012
(Thousands of dollars)
Paid to counterparties	$	829	$	3,148	$	14,843
Received from counterparties	$	4,713	$	915	$	634

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

December 31, 2014 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	5,062
Swaps	Deferred charges and other assets		363
December 31, 2013 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(180	)
Swaps	Other current liabilities		(801	)
Swaps	Prepaids and other current assets		156
Swaps	Deferred charges and other assets		4

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

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (see Note 9 – Pension and Other Post Retirement Benefits for definitions of the levels of the fair value hierarchy):

Level 2 - Significant other observable inputs

	December 31, 2014			December 31, 2013
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets - Swaps	$	—		$	801
Deferred charges and other assets - Swaps		—			180
Liabilities at fair value:
Other current liabilities - Swaps		(5,062	)		(156	)
Other deferred credits - Swaps		(363	)		(4	)
Net Assets (Liabilities)	$	(5,425	)	$	821

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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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, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$ (2,363)	$ 976	$ (4,854)
Regulatory deferral accounting treatment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain or (loss) recognized in income on derivative	$ 2,363	$ (976)	$ 4,854