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, 2012

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  ü    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   ü

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   ü    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   ü    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. 

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   ü 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   ü 

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

$2,013,502,347 as of June 30, 2012

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 46,294,796 shares as of February 15, 2013

DOCUMENTS INCORPORATED BY REFERENCE

Description	Part Into Which Incorporated
Annual Report to Shareholders for the Year Ended December 31, 2012 2013 Proxy Statement	Parts I, II, and IV Part III

TABLE OF CONTENTS

PART I		1
Item 1.	BUSINESS	1
	NATURAL GAS OPERATIONS	1
	General Description	1
	Rates and Regulation	2
	Demand for Natural Gas	3
	Natural Gas Supply	3
	Competition	5
	Environmental Matters	5
	Employees	5
	CONSTRUCTION SERVICES	5
Item 1A.	RISK FACTORS	7
Item 1B.	UNRESOLVED STAFF COMMENTS	9
Item 2.	PROPERTIES	9
Item 3.	LEGAL PROCEEDINGS	10
Item 4.	MINE SAFETY DISCLOSURES	10
Item 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	10
PART II		10
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	10
Item 6.	SELECTED FINANCIAL DATA	11
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	11
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	12
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	12
Item 9A.	CONTROLS AND PROCEDURES	12
Item 9B.	OTHER INFORMATION	12
PART III		12
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	12
Item 11.	EXECUTIVE COMPENSATION	14
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	14
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	16
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	16
PART IV		16
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	16
	LIST OF EXHIBITS	17
SIGNATURES		23

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.

NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

Financial information concerning the Company’s business segments is included in Note 14 of the Notes to Consolidated Financial Statements, which is included in the 2012 Annual Report to Shareholders and is incorporated herein by reference.

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

NATURAL GAS OPERATIONS

General Description

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

As of December 31, 2012, Southwest purchased and distributed or transported natural gas to 1,876,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. The southwestern United States had historically been one of the highest growth regions of the country. However, the customer growth levels experienced in recent years have greatly diminished due to the overall slowdown in the new housing market and increase in idle/vacant homes, resulting from foreclosures and challenging economic conditions. Southwest completed 17,000 first-time meter sets over the last twelve months. These meter sets led to 17,000 net additional active customers during 2012, an increase of about 1%. Given the current housing and economic environment, management expects that customer growth will be approximately 1% in the near term. Southwest estimates that the number of excess inactive meters is approximately 37,000 at December 31, 2012. Management cannot predict the timing of when currently idle and vacant homes will return to service, but to date it has been gradual.

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

	Distribution
For the Year Ended	Residential and     Small Commercial	Other Sales     Customers	Transportation
December 31, 2012	85%	4%	11%
December 31, 2011	86%	4%	10%
December 31, 2010	86%	4%	10%

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.

Transportation of customer-secured gas to end-users accounted for 48% of total system throughput in 2012. Customers who utilized this service transported 100 million dekatherms in 2012, 94 million dekatherms in 2011, and 100 million dekatherms in 2010. Although these volumes are significant, these customers provided a much smaller proportionate share of operating margin.

The demand for natural gas is seasonal, with a 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.

As of January 2012, rate structures in all service territories allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption, though decoupled structures vary by state. In California, authorized operating margin levels vary by month. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin. In Arizona, a full revenue decoupling mechanism with a winter-period monthly weather adjuster is in place, for most customer classes.

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

Information with respect to recent general rate cases and PGA filings is included in the Rates and Regulatory Proceedings section of Management’s Discussion and Analysis (“MD&A”) in the 2012 Annual Report to Shareholders.

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

Ratemaking Area	Type of Filing	Month Filed	Month Final Rates Effective
Arizona:	General rate case	November 2010	January 2012
California:
Northern and Southern	Annual attrition	October 2012	January 2013
Northern and Southern	General rate case	December 2012	Pending
Nevada:
Northern and Southern	General rate case	April 2012	November 2012
FERC:
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”), required to be in place by August 2011, that 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 increases/strengthens 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 requires 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 the crafting of associated mandates and reporting. As 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 six times greater than on warm days because of increased use of gas for space heating. To fully satisfy this increased high-priority demand, gas is withdrawn from storage in certain service areas, or peaking supplies are purchased from suppliers. If necessary, service to interruptible lower-priority customers may be curtailed to provide the needed delivery system capacity. Southwest maintains no significant backlog on its orders for gas service.

Natural Gas Supply

Southwest is responsible for acquiring and arranging delivery of natural gas to its system in sufficient quantities to meet its sales customers’ needs. Southwest’s primary natural gas acquisition objective is to ensure that adequate supplies of natural gas are available at the best 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 2012, 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. Competitive pricing, flexibility in meeting Southwest’s requirements, and aggressive 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

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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 (currently ranging from 25% to about 35%, 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 and Nevada jurisdictional areas. 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 PGA mechanisms in the respective jurisdictional area.

For the 2012/2013 heating season, fixed-price purchases ranged from approximately $3 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 Arizona or southern Nevada rate jurisdictions. Limited storage availability exists in southern and northern California and northern Nevada.

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

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

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 has changed dramatically during recent years. Advanced drilling techniques have provided access to abundant and sustainable natural gas supplies. The natural gas market has responded with reductions to both price volatility and the total price of the commodity. Most recently, natural gas has reached the lowest prices recorded in a decade. 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

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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 home market among the residential and small commercial customer classes.

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

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

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 Environmental Protection Agency (“EPA”) has issued regulations that require the reporting of greenhouse gas emissions (“GHG”) from large sources and suppliers in the United States in order to facilitate the development of policies and programs to reduce GHGs. The Company reports required information to the EPA under the Mandatory Reporting Rule (“MRR”) including the volumes of natural gas it receives for distribution to LDC customers (Subpart NN) and its fugitive GHG emissions that result from the operation of its LDC pipelines (Subpart W). While some parts of the MRR do not apply to Southwest, other required information is already 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 other climate legislation which could result in additional requirements or have financial implications.

Employees

At December 31, 2012, the natural gas operations segment had 2,245 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

NPL is a full-service contractor whose customers are primarily energy services utility companies. NPL derives revenue from installation, replacement, and maintenance of energy distribution systems. NPL 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 NPL operations is distribution pipe and service hook-up replacements as well as line installations for new business

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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 Midwest. In the warmer climate areas, such as the southwestern United States, construction continues year round.

During the past few years, several factors have impacted the nation’s natural gas distribution system and resulted in an increase in large multi-year distribution pipe replacement projects. The Department of Transportation’s Pipeline and Hazardous Materials Safety Administration instituted DIMP, which requires 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 the 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. Additionally, funding for planned replacement projects increased due to the general improvement of the national credit markets.

The above factors resulted in several large multi-year distribution pipe replacement projects being awarded to NPL. NPL was selected as the contractor on certain of these projects, or one of several contractors to work on others. These contracts are usually multi-year, and the amount of work to be completed by NPL will vary from year to year. NPL continues to bid on pipe replacement projects throughout the country and has made structural and transitional changes to match the increased size and complexity of the business, including key management changes.

The American Taxpayer Relief Act of 2012 was enacted recently which extends the 50% bonus tax depreciation deduction from January 1, 2013 through December 31, 2013 providing further incentive for replacement projects.

NPL business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with NPL 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 2012, approximately 83% of revenue was earned under unit-price contracts. As of December 31, 2012, a backlog of approximately $35 million existed with respect to outstanding fixed-priced construction contracts.

Materials used by NPL in its construction activities are typically specified, purchased, and supplied by NPL’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, NPL’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 local competitors in what has been a largely fragmented industry. Some national competitors also exist within the industry. NPL currently operates in 18 major markets nationwide. Its customers are primarily the principal LDCs in those markets. During 2012, NPL served 73 major customers, with Southwest accounting for approximately 14% of NPL revenues. Additionally, two customers accounted for approximately 26% of total revenue, while five other customers individually accounted for 5% or more of NPL revenues.

Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2012, NPL had 3,770 regular full-time equivalent employees. Employment peaked in August 2012 when there were 4,134 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.

Operations are conducted from 18 field locations 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.

NPL is not directly affected by regulations promulgated by the ACC, PUCN, CPUC, or FERC in its construction services. NPL is an unregulated energy services subsidiary of Southwest Gas Corporation. However, because NPL performs work for the regulated natural gas segment of the Company, its 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 NPL under the regulatory jurisdiction of any of the commissions noted above.

NPL has a 65% interest in IntelliChoice Energy, LLC (“ICE”) and consolidates ICE as a majority owned subsidiary. ICE was established in late 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 NPL operating results.

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Item 1A. RISK FACTORS

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

Governmental policies and regulatory actions can reduce our earnings.

Regulatory commissions set our 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 and policies, can reduce our earnings. Risks and uncertainties relating to delays in obtaining regulatory approvals, conditions imposed in regulatory approvals, or 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 during the stay-out period. If approval of the decoupling mechanism is rescinded by Arizona regulators, the prohibition against the filing of general rate cases will be eliminated.

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

The 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) have also been impacted, resulting in reductions in operations or closures. A continued slow recovery could result in customers voluntarily reducing consumption. If the recovery process is prolonged or regresses, 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 recovery, or any future economic slowdowns. If the economy or the markets in which we operate do not improve (or worsen) 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, 2012 of approximately $230 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 $80 million

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at December 31, 2012 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 2012, Southwest recognized $6.6 million in Other income (deductions) due to increases in the cash surrender values of its company-owned life insurance policies (compared to an increase of $700,000 resulting from recognized death benefits net of decreases in cash surrender values in 2011). 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 and purchase additional policies as necessary. 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.

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 2013, 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 a 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 $5 million in total claims above our self-insured retention in the policy year. We cannot predict the

8

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.

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

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

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

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

Any future downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in 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.

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, including a portion of the corporate headquarters office complex located in Las Vegas, Nevada and the administrative offices in Phoenix, Arizona. Total gas plant, exclusive of leased property, at December 31, 2012 was $5.1 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.

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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 NPL can be found on pages 5 and 6 of this Form 10-K under Construction Services.

Item 3. LEGAL PROCEEDINGS

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

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

Item 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

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

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 15, 2013, there were 15,969 holders of record of common stock, and the market price of the common stock was $44.50. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2012 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

In February 2013, the Board of Directors (“Board”) increased the quarterly dividend payout to 33 cents per share, effective with the June 2013 payment. This marks the seventh 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

10

prospects. The quarterly common stock dividend declared was 25 cents per share throughout 2010, 26.5 cents per share throughout 2011, and 29.5 cents per share throughout 2012.

Item 6. SELECTED FINANCIAL DATA

Information required by this item is included in the 2012 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 2012 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, and interest 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 2013 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 (currently ranging from 25% to 35%, 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.

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. However, 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 ($100 million prior to November 2012) 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, 2012 and 2011, Southwest had $161 million and $209 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 million.

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

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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 2012 Annual Report to Shareholders and are incorporated herein by reference.

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

None.

Item 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Based on the most recent evaluation, as of December 31, 2012, 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 2012 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 79.

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 2012 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 80.

There have been no changes in the Company’s internal controls over financial reporting 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 2013 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, 2012 are as follows:

Name	Age	Position	Period Position Held
Jeffrey W. Shaw	54	President and Chief Executive Officer	2012-Present
		Chief Executive Officer	2008-2012
Roy R. Centrella	55	Senior Vice President/Chief Financial Officer	2010-Present
		Vice President/Controller and Chief Accounting Officer	2008-2010
Eric DeBonis	45	Senior Vice President/Operations	2012-Present
		Senior Vice President/Staff Operations & Technology	2011-2012
		Vice President/Special Projects	2010-2011
		Vice President/Central Arizona Division	2008-2010
		General Manager/East Region/Central Arizona Division	2008
Karen S. Haller	49	Senior Vice President/General Counsel and Corporate Secretary	2012-Present
		Vice President/General Counsel, Compliance Officer,
		and Corporate Secretary	2010-2012
		Vice President/General Counsel and Compliance Officer	2008-2010
		Vice President/Deputy General Counsel and Compliance Officer	2008
		Assistant General Counsel and Director/Legal Affairs	2008
John P. Hester	50	Senior Vice President/Regulatory Affairs & Energy Resources	2008-Present
Laura Lopez Hobbs	53	Senior Vice President/Human Resources and Administration	2012-Present
		Vice President/Administration	2010-2012
		Vice President/Human Resources	2008-2010
		Director/Human Resources	2008
Edward A. Janov	58	Senior Vice President/Corporate Development	2010-Present
		Senior Vice President/Finance	2008-2010
William N. Moody	56	Senior Vice President/Staff Operations & Technology	2012-Present
		Vice President/Gas Resources	2008-2012
Kenneth J. Kenny	50	Vice President/Finance/Treasurer	2010-Present
		Vice President/Treasurer	2008-2010
Gregory J. Peterson	53	Vice President/Controller and Chief Accounting Officer	2010-Present
		Assistant Controller	2008-2010

(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 2013 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 2013 Proxy Statement, which by this reference is incorporated herein.

(i) Identification of the Audit Committee. Information with respect to the composition of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive 2013 Proxy Statement, which by this reference is incorporated herein.

(j) Material Changes in Director Nomination Procedures for Security Holders. On July 31, 2012, the Board approved the amendment of the Company’s Bylaws (as amended, the “Bylaws”). The amendment, which was effective immediately upon approval, implemented a change to Section 3 of Article III of the Bylaws. Prior to the

13

amendment, the Bylaws allowed shareholders to make nominations of individuals to be elected to the Board 20 days prior to the anniversary of the date that the prior year’s annual meeting was held. The amended provision requires that the Company receive notice of any such nominations from shareholders at least 120 days before the anniversary of the date of the proxy statement for the prior year’s annual meeting.

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 2012 with the reporting requirements of Section 16(a) of the Exchange Act, except for the following Form 4:

The purchase of Company common stock by director José A. Cárdenas of 1,500 shares on March 2, 2012 was reported on March 7, 2012.

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 & Ethics can be viewed on the Company’s website (www.swgas.com). If any substantive amendments to the Code of Business Conduct & 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 2013 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 2013 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 2013 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 2013 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 2013 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, 2012, 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.

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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		125	$	28.13		-
Equity compensation plans not approved by security holders		-		-		-
Total		125	$	28.13		-

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		348	$	36.03		243
Equity compensation plans not approved by security holders		-		-		-
Total		348	$	36.03		243

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		207	$	37.18		236
Equity compensation plans not approved by security holders		-		-		-
Total		207	$	37.18		236

Additional information regarding the three equity compensation plans is included in Note 11 of the Notes to Consolidated Financial Statements in the 2012 Annual Report to Shareholders.

15

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 2013 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 2013 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 2012 Annual Report to Shareholders under the following captions:

Consolidated Balance Sheets	38
Consolidated Statements of Income	40
Consolidated Statements of Comprehensive Income	41
Consolidated Statements of Cash Flows	42
Consolidated Statements of Equity	44
Notes to Consolidated Financial Statements	46
Management’s Report on Internal Control Over Financial Reporting	79
Report of Independent Registered Public Accounting Firm	80

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

(3) See LIST OF EXHIBITS.

(b) See LIST OF EXHIBITS.

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LIST OF EXHIBITS

Exhibit Number	Description of Document
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	Form of Deposit Agreement. Incorporated herein by reference to Exhibit 4.01 to Form S-3 dated September 26, 1994, File No. 33-55621.
4.03	Form of Depositary Receipt (attached as Exhibit A to Form of Deposit Agreement included as Exhibit 4.02 hereto). Incorporated herein by reference to Exhibit 4.01 to Form S-3 dated September 26, 1994, File No. 33-55621.
4.04	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.
4.05	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.
4.06	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.
4.07	Indenture between Clark County, Nevada, and Harris Trust and Savings Bank as Trustee, dated as of October 1, 1999, with respect to the issuance of $35,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), Series 1999A and Taxable Series 1999B or convertibles of Series B (Series C and D), due 2038. Incorporated herein by reference to Exhibit 4.20 to Form 10-K for the year ended December 31, 1999, File No. 1-07850.
4.08	Third Supplemental Indenture between the Company and The Bank of New York, as successor to Harris Trust and Savings Bank, dated as of February 13, 2001, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the $200,000,000, 8.375% Notes, due 2011. Incorporated herein by reference to Exhibit 4.01 to Form 8-K dated February 8, 2001, File No. 1-07850.
4.09	Fourth Supplemental Indenture of the Company to The Bank of New York, as successor to Harris Trust and Savings Bank, dated as of May 6, 2002, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the 7.625% Senior Unsecured Notes due 2012. Incorporated herein by reference to Exhibit 4.01 to Form 8-K dated May 1, 2002, File No. 1-07850.

17

Exhibit Number	Description of Document
4.10	Certificate of Trust of Southwest Gas Capital II. Incorporated herein by reference to Exhibit 4.03 to Form S-3 dated August 7, 2003, File No. 333-106419.
4.11	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.
4.12	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.
4.13	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.
4.14	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.
4.15	Form of Common Stock Certificate. Incorporated herein by reference to Exhibit 4 to Form 8-K dated July 22, 2003, File No. 1-07850.
4.16	Form of Amended and Restated Trust Agreement of Southwest Gas Capital II. Incorporated herein by reference to Exhibit 4.09 to Form 8-K dated August 20, 2003, File No. 1-07850.
4.17	Indenture between Clark County, Nevada, and BNY Midwest Trust Company as Trustee, dated as of July 1, 2004, with respect to the issuance of $65,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), Series 2004A, due 2034. Incorporated herein by reference to Exhibit 4 to Form 10-Q for the quarter ended September 30, 2004, File No. 1-07850.
4.18	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.
4.19	Indenture of Trust between Clark County, Nevada, and the Bank of New York Trust Company, N.A. as Trustee, dated as of October 1, 2005, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2005A. Incorporated herein by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005, File No. 1-07850.
4.20	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.
4.21	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.
4.22	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.
4.23	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.

18

Exhibit Number	Description of Document
4.24	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.
4.25	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.
4.26	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.
4.27	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.
4.28	Form of Indenture for Senior Notes Due 2022. Incorporated herein by reference to Exhibit 4.1 to Form S-3ASR dated March 20, 2012, File No. 333-180226.
4.29	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.
4.30	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.
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	Amended and Restated Lease Agreement between the Company and Spring Mountain Road Associates, dated as of July 1, 1996. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 1996, File No. 1-07850.
10.03     *	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.
10.04     *	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.
10.05	Financing Agreement between the Company and Clark County, Nevada, dated as of October 1, 1999. Incorporated herein by reference to Exhibit 10.16 to Form 10-K for the year ended December 31, 1999, File No. 1-07850.
10.06     *	Amended Form of Employment Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998, Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2000, Exhibit 10 to Form 10-Q for the quarter ended September 30, 2001, Form 8-K dated September 21, 2004, Form 8-K dated August 1, 2006, and Exhibit 10.19 to Form 10-K for the year ended December 31, 2006, File No. 1-07850.

19

Exhibit Number	Description of Document
10.07    *	Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 2011, File No. 1-07850.
10.08    *	Form of General Release - Attachment A to Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2011, File No. 1-07850.
10.09    *	Southwest Gas Corporation Management Incentive Plan, amended and restated effective January 20, 2009. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 18, 2009, File No. 1-07850.
10.10    *	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.
10.11    *	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.
10.12    *	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.
10.13	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.
10.14    *	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.
10.15	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.
10.16	$300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2005, File No. 1-07850. First Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2006, File No. 1-07850. Second Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2007, File No. 1-07850. Third Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended June 30, 2007, File No. 1-07850.
10.17	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.

20

Exhibit Number	Description of Document
10.18	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.
10.19	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.
10.20	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.
10.21	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.
10.22	$300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 15, 2012, File No. 1-07850.
10.23    *	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.
10.24    *	Change in Control Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation. Incorporated herein by reference to Exhibit 10.23 to Form 10-K for the year ended December 31, 2011, File No. 1-07850.
10.25    *	Letter Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation, with respect to post-termination benefits. Incorporated herein by reference to Exhibit 10.24 to Form 10-K for the year ended December 31, 2011, File No. 1-07850.
10.26    *	NPL Employment Agreement with James P. Kane. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2012, File No. 1-07850.
99.01	NPL Credit Facility Agreement. Incorporated herein by reference to Exhibit 99.01 to Form 10-Q for the quarter ended June 30, 2012, File No. 1-07850.
99.02	NPL Credit Facility Agreement - First Amendment. Incorporated herein by reference to Exhibit 99.01 to Form 10-Q for the quarter ended September 30, 2012, File No. 1-07850.
99.03	NPL Credit Facility Agreement - Second Amendment. Incorporated herein by reference to Exhibit 99.02 to Form 10-Q for the quarter ended September 30, 2012, File No. 1-07850.
12.01	Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.
13.01	Portions of 2012 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.

21

Exhibit Number	Description of Document
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, 2012, 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 (vi) the Notes to the Consolidated Financial Statements.

*  Management Contracts or Compensation Plans

22

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 27, 2013	By /s/ JEFFREY W. SHAW
	Jeffrey W. Shaw
	President and Chief Executive Officer

23

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 27, 2013
/s/ JOSÉ A. CÁRDENAS (José A. Cárdenas)	Director	February 27, 2013
/s/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	February 27, 2013
/s/ STEPHEN C. COMER (Stephen C. Comer)	Director	February 27, 2013
/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	February 27, 2013
/s/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director	February 27, 2013
/s/ ANNE L. MARIUCCI (Anne L. Mariucci)	Director	February 27, 2013
/s/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Chairman of the Board of Directors	February 27, 2013
/s/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director, President and Chief Executive Officer	February 27, 2013
/s/ A. RANDALL THOMAN (A. Randall Thoman)	Director	February 27, 2013
/s/ THOMAS A. THOMAS (Thomas A. Thomas)	Director	February 27, 2013
/s/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	February 27, 2013
/s/ ROY R. CENTRELLA (Roy R. Centrella)	Senior Vice President/ Chief Financial Officer	February 27, 2013
/s/ GREGORY J. PETERSON (Gregory J. Peterson)	Vice President, Controller, and Chief Accounting Officer	February 27, 2013

24

EX-12.01

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)

	December 31,
	2012		2011		2010		2009		2008
1. Fixed charges:
A) Interest expense	$	67,148	$	68,183	$	75,481	$	81,861	$	90,403
B) Amortization		2,001		2,137		2,620		2,097		2,880
C) Interest portion of rentals		10,605		8,943		6,455		6,644		7,802
Total fixed charges	$	79,754	$	79,263	$	84,556	$	90,602	$	101,085
2. Earnings (as defined):
D) Pretax income from continuing operations	$	207,915	$	175,066	$	158,378	$	132,035	$	101,808
Fixed Charges (1. above)		79,754		79,263		84,556		90,602		101,085
Total earnings as defined	$	287,669	$	254,329	$	242,934	$	222,637	$	202,893
		3.61		3.21		2.87		2.46		2.01

EX-13.01

15

Exhibit 13.01

Consolidated Selected Financial Statistics

Year Ended December 31,	2012			2011			2010			2009			2008
(Thousands of dollars, except per share amounts)
Operating revenues	$	1,927,778		$	1,887,188		$	1,830,371		$	1,893,824		$	2,144,743
Operating expenses		1,656,254			1,637,108			1,598,254			1,685,433			1,936,881
Operating income	$	271,524		$	250,080		$	232,117		$	208,391		$	207,862
Net income	$	133,331		$	112,287		$	103,877		$	87,482		$	60,973
Total assets at year end	$	4,488,057		$	4,276,007		$	3,984,193		$	3,906,292		$	3,820,384
Capitalization at year end
Total equity	$	1,308,498		$	1,225,031		$	1,166,996		$	1,102,086		$	1,037,841
Subordinated debentures		—			—			—			100,000			100,000
Long-term debt, excluding current maturities		1,268,373			930,858			1,124,681			1,169,357			1,185,474
	$	2,576,871		$	2,155,889		$	2,291,677		$	2,371,443		$	2,323,315
Current maturities of long-term debt	$	50,137		$	322,618		$	75,080		$	1,327		$	7,833
Common stock data
Common equity percentage of capitalization		50.8	%		56.8	%		50.9	%		46.5	%		44.7	%
Return on average common equity		10.4	%		9.3	%		9.1	%		8.1	%		6.0	%
Basic earnings per share	$	2.89		$	2.45		$	2.29		$	1.95		$	1.40
Diluted earnings per share	$	2.86		$	2.43		$	2.27		$	1.94		$	1.39
Dividends declared per share	$	1.18		$	1.06		$	1.00		$	0.95		$	0.90
Payout ratio		41	%		43	%		44	%		49	%		64	%
Book value per share at year end	$	28.39		$	26.68		$	25.60		$	24.44		$	23.48
Market value per share at year end	$	42.41		$	42.49		$	36.67		$	28.53		$	25.22
Market value per share to book value per share		149	%		159	%		143	%		117	%		107	%
Common shares outstanding at year end (000)		46,148			45,956			45,599			45,092			44,192
Number of common shareholders at year end		16,028			16,834			17,821			20,489			22,244
Ratio of earnings to fixed charges		3.61			3.21			2.87			2.46			2.01

16

Natural Gas Operations

Year Ended December 31,	2012			2011			2010			2009			2008
(Thousands of dollars)
Sales	$	1,238,513		$	1,329,512		$	1,438,809		$	1,547,081		$	1,728,924
Transportation		83,215			73,854			73,098			67,762			62,471
Operating revenue		1,321,728			1,403,366			1,511,907			1,614,843			1,791,395
Net cost of gas sold		479,602			613,489			736,175			866,630			1,055,977
Operating margin		842,126			789,877			775,732			748,213			735,418
Expenses
Operations and maintenance		369,979			358,498			354,943			348,942			338,660
Depreciation and amortization		186,035			175,253			170,456			166,850			166,337
Taxes other than income taxes		41,728			40,949			38,869			37,318			36,780
Operating income	$	244,384		$	215,177		$	211,464		$	195,103		$	193,641
Contribution to consolidated net income	$	116,619		$	91,420		$	91,382		$	79,420		$	53,747
Total assets at year end	$	4,204,948		$	4,048,613		$	3,845,111		$	3,782,913		$	3,680,327
Net gas plant at year end	$	3,343,794		$	3,218,944		$	3,072,436		$	3,034,503		$	2,983,307
Construction expenditures and property additions	$	308,951		$	305,542		$	188,379		$	212,919		$	279,254
Cash flow, net
From operating activities	$	344,441		$	216,745		$	342,522		$	371,416		$	261,322
From (used in) investing activities		(296,886	)		(289,234	)		(178,685	)		(265,850	)		(237,093	)
From (used in) financing activities		(43,453	)		(2,327	)		(107,779	)		(81,744	)		(34,704	)
Net change in cash	$	4,102		$	(74,816	)	$	56,058		$	23,822		$	(10,475	)
Total throughput (thousands of therms)
Residential		655,046			718,765			704,693			669,736			704,986
Small commercial		270,665			303,923			300,940			294,225			314,555
Large commercial		116,582			112,256			111,833			117,241			125,121
Industrial/Other		47,830			50,208			58,922			72,623			97,702
Transportation		998,095			941,544			998,600			1,043,894			1,164,190
Total throughput		2,088,218			2,126,696			2,174,988			2,197,719			2,406,554
Weighted average cost of gas purchased ($/therm)	$	0.42		$	0.58		$	0.62		$	0.71		$	0.84
Customers at year end		1,876,000			1,859,000			1,837,000			1,824,000			1,819,000
Employees at year end		2,245			2,298			2,349			2,423			2,447
Customer to employee ratio		836			809			782			753			743
Degree days – actual		1,740			2,002			1,998			1,824			1,902
Degree days – ten-year average		1,866			1,888			1,876			1,882			1,893

17

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, 2012, Southwest had 1,876,000 residential, commercial, industrial, and other natural gas customers, of which 1,010,000 customers were located in Arizona, 681,000 in Nevada, and 185,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2012, 56% of operating margin was earned in Arizona, 34% in Nevada, and 10% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting operating margin changes are general rate relief, weather, conservation and efficiencies, and customer growth. Weather has traditionally been the primary reason for volatility in margin, which continued throughout 2011 with respect to Southwest’s Arizona service territories. In January 2012, however, a full revenue decoupling mechanism, which includes a monthly weather adjuster, was implemented in the Arizona service territories. With this change, all of Southwest’s service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on margin and allow the Company to aggressively pursue energy efficiency initiatives.

NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in 18 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented 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 country. Generally, revenues are lowest during the first quarter of the year due to less favorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. In certain circumstances, such as with large, longer duration bid contracts, or unit-price contracts with caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid.

18

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 86% 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,	2012		2011		2010
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	116,619	$	91,420	$	91,382
Construction services		16,712		20,867		12,495
Consolidated	$	133,331	$	112,287	$	103,877
Average number of common shares outstanding		46,115		45,858		45,405
Basic earnings per share
Consolidated	$	2.89	$	2.45	$	2.29
Natural Gas Operations
Operating margin	$	842,126	$	789,877	$	775,732

2012 Overview

Consolidated operating results for 2012 increased compared to 2011 due to improved operating results from the natural gas segment. Basic earnings per share were $2.89 in 2012 compared to basic earnings per share of $2.45 in 2011.

Natural gas operations highlights include the following:

• Operating margin increased $52 million, or 7%, compared to the prior year

• Operating expenses increased $23 million, or 4%, between years

• Net financing costs decreased $2 million between 2012 and 2011

• Other income increased $10 million between years

• Replacement of expiring credit facility with a new $300 million facility in March 2012

• Issued $250 million 3.875% Senior Notes in March 2012 with approximately $200 million of the net proceeds used to repay $200 million of 7.625% Senior Notes that matured in May 2012

• The Company’s credit rating was upgraded from Baa2 to Baa1 by Moody’s and from BBB+ to A- by Fitch, in March and May 2012, respectively

• Nevada general rate increase of $7 million was approved effective November 2012

Construction services highlights include the following:

• Revenues in 2012 increased $122 million, or 25%, compared to 2011

• Construction expenses increased $118 million or 28%, compared to 2011

• Replacement of a $30 million credit facility with a new $75 million facility in June 2012

Arizona Rate Relief.    During 2012, Southwest realized $45 million of incremental operating margin from rate relief in its Arizona operating areas. See Rates and Regulatory Proceedings for additional information on the associated general rate case with new rates that were effective January 2012.

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Weather and Conservation.    Weather has traditionally been the primary reason for volatility in margin, which continued throughout 2011 with respect to Southwest’s Arizona service territories. In January 2012, however, a full revenue decoupling mechanism, which includes a winter-period monthly weather adjuster, was implemented in the Arizona service territories for most customer classes. With this change, all of Southwest’s service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on margin and allow the Company to aggressively pursue energy efficiency initiatives on behalf of its customers.

Nevada General Rate Case.    In the fourth quarter of 2012, a decision was reached at a public hearing (the “Decision”) in the general rate application Southwest filed with the Public Utilities Commission of Nevada (“PUCN”), with rates effective November 2012. The Decision is estimated to provide a revenue increase of $5.8 million in southern Nevada based on an overall rate of return of 6.49% and a 9.85% return on 42.6% common equity. For northern Nevada, the Decision is estimated to provide a revenue increase of $1.2 million with an overall rate of return of 8.01% and a 9.20% return on 65.6% common equity. Approximately $2 million in incremental margin was recorded in the fourth quarter of 2012. Factoring in other aspects of the Decision, including lower depreciation rates, the Decision is expected to increase annual operating income by $11.4 million. Following the Decision, the Company filed a Petition for Reconsideration requesting reconsideration of the findings in the Decision relating to the capital structure and other cost of service issues. See Rates and Regulatory Proceedings for more information.

California General Rate Case.    In December 2012, Southwest filed a general rate case application with the California Public Utilities Commission (“CPUC”) requesting $11.6 million in annual rate increases for its California rate jurisdictions with a proposed effective date of January 2014. See Rates and Regulatory Proceedings for more information.

Customer Growth.    Southwest added 17,000 net new customers over the last twelve months. First-time meter sets also approximated 17,000 during the year. Recently, Southwest has experienced customer growth in excess of first-time meter sets as meters on previously vacant homes return to service. Southwest estimates the remaining number of excess inactive meters is approximately 37,000 at December 31, 2012. Southwest projects customer growth associated with new meter sets of about 1% for 2013, along with a gradual return of customers associated with previously vacant homes.

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 $230 million at December 31, 2012. 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 $80 million at December 31, 2012 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration and purchase additional policies as necessary. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the 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, cash surrender values of COLI policies increased $6.6 million in 2012. Investment returns during 2012 were significantly higher than normal. In 2011, income from changes in the cash surrender value of COLI policies

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and recognized death benefits was $700,000. Management currently expects average returns of $2 million to $4 million annually on the COLI policies, excluding any net death benefits recognized. Based on the current investment mix, both positive and negative deviations from expected levels are likely to continue.

Credit Facility and Commercial Paper Program.    In March 2012, Southwest replaced its $300 million credit facility, which would have expired in May 2012, with a new $300 million facility that expires in March 2017. Southwest has a $50 million commercial paper program, which is supported by (and not incremental to) the credit facility. See Capital Resources and Liquidity for more information.

Liquidity.    Southwest believes its liquidity position is solid. As noted above, Southwest has a $300 million credit facility maturing in March 2017. The facility is provided through a consortium of eight major banking institutions. Historically, facility borrowings have been low and concentrated in the first half of the winter heating period when gas purchases require temporary financing. The maximum amount outstanding on the credit facility during 2012 was $130 million in the fourth quarter. At December 31, 2012, $91 million was outstanding on the long-term portion, and no borrowings were outstanding on the short-term portion of the credit facility. At December 31, 2012, the amount outstanding under the commercial paper program was $20 million.

Southwest also believes its ability to obtain funding for ongoing expenditures and future expansions is secure and adequate. Historically, Southwest has accessed the public debt markets for funding, most recently in March 2012 in connection with the issuance of $250 million of 3.875% Senior Notes. Southwest’s solid liquidity position also provided an opportunity to redeem $12.4 million of 6.10% IDRBs and $14.3 million of 5.95% IDRBs in 2012. Each of these redemptions was at par. Southwest plans to redeem $30 million of 5.45% IDRBs and $15 million of 5.80% IDRBs at par in March 2013. Southwest has no subsequent long-term debt maturities until 2017.

Credit Rating Upgrades.    Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings (“Fitch”) upgraded the Company’s senior unsecured rating to Baa1 from Baa2 in March 2012 and to A- from BBB+ in May 2012, respectively. See Credits Ratings for more information.

Loss on NPL Contract.    In the first half of 2012, NPL recorded $18 million in losses on a large fixed-price pipe replacement contract in a single geographic location. A number of factors contributed to the loss on the contract, which was the largest fixed-price contract ever undertaken by NPL. Approved change orders during the fourth quarter of 2012 helped to reduce current-year losses on the contract to $15 million. At December 31, 2012, work on the contract is substantially complete with the exception of some restoration work. Since inception in 2011, NPL has recognized approximately $75 million of revenues on this contract, including $37 million in 2011. Construction costs recorded to date total approximately $85 million, including $32 million during 2011. No significant additional losses are anticipated on the remaining work to be performed, although no assurances can be provided that additional losses on this contract will not occur.

NPL has another contract with the same customer in the same geographical area with a fixed-price component of approximately $28 million. Work began in the middle of 2012 and will continue into 2013. Based on the progress to date and review of estimated costs to complete, management expects this contract to be marginally profitable overall.

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Results of Natural Gas Operations

Year Ended December 31,	2012		2011			2010
(Thousands of dollars)
Gas operating revenues	$	1,321,728	$	1,403,366		$	1,511,907
Net cost of gas sold		479,602		613,489			736,175
Operating margin		842,126		789,877			775,732
Operations and maintenance expense		369,979		358,498			354,943
Depreciation and amortization		186,035		175,253			170,456
Taxes other than income taxes		41,728		40,949			38,869
Operating income		244,384		215,177			211,464
Other income (deductions)		4,165		(5,404	)		4,016
Net interest deductions		66,957		68,777			75,113
Net interest deductions on subordinated debentures		—		—			1,912
Income before income taxes		181,592		140,996			138,455
Income tax expense		64,973		49,576			47,073
Contribution to consolidated net income	$	116,619	$	91,420		$	91,382

2012 vs. 2011

Contribution to consolidated net income from natural gas operations increased by $25 million between 2012 and 2011. The improvement was primarily due to increases in operating margin and other income, partially offset by higher operating expenses.

Operating margin increased $52 million between years. Rate relief in Arizona ($45 million) and Nevada ($2 million) provided $47 million of the increase in operating margin. New customers contributed the remaining $5 million increase in operating margin during 2012. A $4 million increase between years due to an adjustment (related to a regulatory deferral mechanism) that decreased operating margin in 2011 was offset by a reduction of $4 million in operating margin between years primarily due to moderately cold weather experienced in Arizona in the first half of 2011. With a new rate decoupling mechanism in Arizona, effective January 2012, weather is no longer a significant factor in operating margin overall.

Operations and maintenance expense increased $11.5 million, or 3%, between years primarily due to higher general costs and employee-related costs including approximately $6 million of net pension expense, and to approximately $1 million in leak survey costs associated with a special Arizona program (see Pipe Replacement Tracking Mechanisms in the Rates and Regulatory Proceedings section).

Depreciation expense increased $10.8 million, or 6%, as a result of additional plant in service. Average gas plant in service for 2012 increased $247 million, or 5%, compared to 2011. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and to a lesser degree, new business. The increase was partially offset by approximately $1 million due to a reduction in depreciation rates in Nevada, which became effective in November 2012.

Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, increased $9.6 million between 2012 and 2011. Cash surrender values of COLI policies increased $6.6 million in 2012, while COLI-related income (resulting from recognized death benefits net of decreases in cash surrender values) was $700,000 in the prior year. COLI income in 2012 was especially high due to strong equity-market returns on investments underlying the policies. In addition, Arizona non-recoverable pipe replacement and other non-utility costs were lower in 2012, especially during the fourth quarter, as compared to 2011. The non-recoverable portion of this pipe replacement activity is complete.

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Net interest deductions decreased $1.8 million between 2012 and 2011 primarily due to cost savings from refinancing, partially offset by a temporary increase in debt outstanding for approximately two months associated with the issuance of $250 million 3.875% Senior Notes in March 2012 to repay $200 million 7.625% Senior Notes that matured in May 2012, and by additional interest on variable-rate IDRBs.

2011 vs. 2010

The contribution to consolidated net income from natural gas operations was relatively unchanged between 2011 and 2010; however, operating income improved by $3.7 million between years. The increase in operating margin and reduced financing costs were offset by higher operating expenses and a decrease in other income.

Operating margin increased $14 million between 2011 and 2010. Differences in heating demand, caused primarily by weather variations, accounted for the $14 million increase as colder-than-normal temperatures were experienced in Arizona in 2011. Incremental margin from rate relief in California ($2 million) and new customers ($2 million) was offset by an adjustment recorded during the third quarter of 2011 related to a regulatory deferral mechanism.

Operations and maintenance expense increased $3.6 million, or 1%, between 2011 and 2010 primarily due to general cost increases, partially offset by favorable claims experience under Southwest’s self-insured medical plan. The increase also included approximately $1 million of costs associated with restoring service to approximately 20,000 Arizona customers in early February 2011, following an outage due to extreme weather conditions. Cost containment efforts (including lower staffing levels) mitigated the increases.

Depreciation expense increased $4.8 million, or 3%, as a result of additional plant in service. Average gas plant in service for 2011 increased $151 million, or 3%, as compared to 2010. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business.

Taxes other than income taxes increased $2.1 million primarily due to higher property tax rates in Arizona.

Other income declined $9.4 million between 2011 and 2010. COLI-related income in 2011 (resulting from recognized death benefits net of decreases in cash surrender values) was $700,000, while 2010 included income of $9.8 million due to an increase in COLI cash surrender values and recognized net death benefits. COLI income in 2010 was especially high due to strong equity-market returns on investments underlying the policies.

Net financing costs decreased $8.2 million between 2011 and 2010 primarily due to the redemption of $100 million of subordinated debentures in March 2010, cost savings from debt refinancing, and reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs).

Income tax expense included $1.6 million of previously unrecognized tax benefits and related interest associated with the expiration of the statute of limitations with respect to a previously recorded uncertain tax position.

Outlook for 2013

Operating margin for 2013 is expected to be favorably influenced by customer growth similar to 2012, as well as incremental margin associated with the Nevada rate case decision and California attrition adjustment.

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Operating expenses for 2013 compared to 2012 will continue to be impacted by inflation, general cost increases, and depreciation expense on plant additions. A reduction in depreciation rates in Nevada will mitigate the depreciation expense increase. Incremental costs, including a $6.4 million increase in pension expense ($5 million net) for 2013 and higher property and general taxes, are expected to result in an overall operating expense increase of approximately 3% to 4%.

Southwest anticipates approximately $5 million in interest savings on an annualized basis due to debt refinancings and redemptions. These savings relate to the March 2012 issuance of $250 million in 3.875% Senior Notes and the repayment of the $200 million of 7.625% debt that occurred in May 2012, as well as the August 2012 redemption of the $14.3 million 1999 5.95% Series C IDRBs. Also included are interest savings expected to be realized from the planned redemption of the $30 million 5.45% 2003 Series C and $15 million 5.80% 2003 Series E IDRBs in the first quarter of 2013.

Results of Construction Services

Year Ended December 31,	2012			2011			2010
(Thousands of dollars)
Construction revenues	$	606,050		$	483,822		$	318,464
Operating expenses:
Construction expenses		541,523			423,703			277,804
Depreciation and amortization		37,387			25,216			20,007
Operating income		27,140			34,903			20,653
Other income (deductions)		246			(8	)		(166	)
Net interest deductions		1,063			825			564
Income before income taxes		26,323			34,070			19,923
Income tax expense		10,303			13,727			7,852
Net income		16,020			20,343			12,071
Net income (loss) attributable to noncontrolling interest		(692	)		(524	)		(424	)
Contribution to consolidated net income attributable to NPL	$	16,712		$	20,867		$	12,495

2012 vs. 2011

Contribution to consolidated net income from construction services for 2012 decreased $4.2 million compared to 2011. The decline was primarily due to the loss on a large fixed-price contract in 2012, partially offset by additional replacement work and increased gains on sale of equipment.

Revenues increased $122 million, or 25%, when compared to 2011 due primarily to an increase in the volume of replacement work. The construction revenues included NPL contracts with Southwest totaling $83.4 million in 2012 and $92.1 million in 2011. NPL accounts for the services provided to Southwest at contractual (market) prices at contract inception.

Construction expenses increased $118 million, or 28%, due to the increase in replacement construction work. See Loss on NPL Contract on page 5 for additional information. Depreciation expense increased $12.2 million between the current year and the prior year due to an increase in equipment purchases. Gains on sale of equipment, included in construction expenses, were $8 million and $3.3 million in 2012 and 2011, respectively.

NPL’s revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Typically, revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions.

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Revenues typically improve as more favorable weather conditions occur during the summer and fall months. The current low interest rate environment, the impact of bonus depreciation legislation, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on NPL’s revenue growth.

During the past several years, NPL has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2012 and 2011, approximately 75% of revenues were from replacement work. Federal and state pipeline safety-related programs and bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. NPL continues to bid on pipe replacement projects throughout the country and has made structural and transitional changes to match the increased size and complexity of the business, including key management changes. Though it sustained a sizeable individual contract loss during 2012, it nonetheless experienced its second highest net income in its history.

2011 vs. 2010

Contribution to consolidated net income from construction services for 2011 increased $8.4 million compared to 2010.

Revenues increased $165 million in 2011, a 52% improvement, when compared to 2010 primarily due to increased replacement construction. The construction revenues included NPL contracts with Southwest totaling $92.1 million in 2011 and $61.3 million in 2010. NPL accounts for the services provided to Southwest at contractual (market) prices.

Construction expenses increased $146 million, or 53%, between 2010 and 2011 due primarily to costs associated with the increase in replacement construction work. Depreciation expense increased $5.2 million as a result of an increase in the construction equipment fleet. Interest expense increased $261,000 between 2010 and 2011 due to an increase in outstanding debt. Gains on sales of equipment were $3.3 million and $1.5 million in 2011 and 2010, respectively.

Outlook for 2013

Revenues are subject to the timing and amount of work awarded to NPL by its utility customers. While it is very early in this process, current expectations are for 2013 revenues to approximate 2012 levels. Construction expenses for 2013 are expected to be favorably impacted by elimination of the loss on the fixed-price contract, partially offset by reduced gains on sales of equipment and increased costs associated with the structural changes made to management and support functions, as well as general cost increases in labor and materials.

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.

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Nevada General Rate Case.    Southwest filed a general rate application with the PUCN in April 2012 to recover increased costs for operations in northern and southern Nevada. In addition, the filing reflected additional investments in infrastructure and included changes in depreciation, cost of service, and cost of capital. Southwest requested an increase in revenue of $1.5 million, or 1.41%, in northern Nevada and $25.4 million, or 6.15%, in southern Nevada. In the application, Southwest requested an overall rate of return of 8.45% on original cost rate base of $115 million for northern Nevada and an overall rate of return of 7.44% on original cost rate base of $821 million for southern Nevada, a return on common equity of 10.65%, and a capital structure utilizing 54% common equity. Southwest also requested to implement an infrastructure replacement mechanism to defer and recover certain costs associated with up to $40 million annually of proposed accelerated replacement of early vintage plastic and steel pipe.

The PUCN reached a decision in this proceeding in the fourth quarter of 2012 with rates effective November 2012. The Decision provides an annual revenue increase of $5.8 million in southern Nevada based on an overall rate of return of 6.49% and a 9.85% return on 42.6% common equity on original cost rate base of $825 million. For northern Nevada, the Decision provides a revenue increase of $1.2 million with an overall rate of return of 8.01% and a 9.20% return on 65.6% common equity on original cost rate base of $116 million. The 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 Decision reclassified approximately $2.5 million of modified business and mill taxes from pass-through items to operating expenses. On a combined basis, the Decision is expected to increase annual operating income by $11.4 million.

The Company reviewed the Decision and identified certain items that it ultimately submitted to the PUCN for reconsideration. Notably, the PUCN employed alternative capital structures for northern and southern Nevada instead of the actual capital structure of the Company that was supported by all parties. A Petition for Reconsideration (“Petition”) was filed with the PUCN after the PUCN issued its order in this proceeding, requesting reconsideration of the findings in the decision relating to the capital structure and other cost of service issues. Similarly, the PUCN Staff filed a Petition for Rehearing on the same alternative capital structure issue addressed in Southwest’s Petition. In December 2012, a decision was received which granted Southwest’s Petition on certain issues pertaining to the cost of service items, denied the Company’s request related to the capital structure, but granted the PUCN Staff’s requested Petition for Rehearing on the capital structure. The reconsideration of the cost of service issues required a modification of the final Order, however ultimately continued to deny cost recovery for these items. The hearing related to the capital structure was held in January 2013, and the parties to the proceeding presented evidence in support of their respective positions on what capital structure the PUCN should utilize in establishing rates. A final PUCN decision on the rehearing is expected in the first quarter of 2013.

As it relates to the proposed infrastructure replacement mechanism, the PUCN Decision indicated a separate rulemaking docket will be needed to address the regulatory issues necessary to implement such a mechanism. In January 2013, the PUCN authorized the opening of a new docket to review the merits of such mechanisms. An initial round of comments and reply comments were submitted and a workshop on the matter has already been convened. The scope of the rulemaking was recently expanded in order to consider additional forms of recovery mechanisms. The next steps in the proceeding include the filing of additional comments by interested parties, reply comments, and the convening of another workshop in the first quarter of 2013. The Company anticipates the PUCN will issue a decision in this rulemaking docket by the end of the third quarter of this year.

California Annual Attrition.    As part of the 2009 rate decision by the CPUC in Southwest’s last California general rate case, attrition increases were authorized for the years 2010-2013. The level of increase authorized for 2013 was $1.8 million in southern California, $500,000 in northern California, and $100,000 in

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South Lake Tahoe. However, the continued low interest rate environment has triggered an automatic rate of return adjustment mechanism, which resulted in decreases of $700,000 in southern California, $500,000 in northern California, and $100,000 in South Lake Tahoe. The resulting net margin impact for the California rate jurisdictions is $1.1 million.

California General Rate Case.    In December 2012, Southwest filed a general rate case application with the CPUC requesting annual revenue increases of $5.6 million for southern California, $3.2 million for northern California, and $2.8 million for the South Lake Tahoe rate jurisdiction. The application included a capital structure consisting of 43% debt and 57% common equity, with an overall rate of return of 7.32% in southern California and 8.61% in both northern California and South Lake Tahoe. Southwest is also seeking to continue the Post-Test Year Ratemaking Mechanism, which allows for annual attrition increases. The application includes the addition of an Infrastructure Reliability and Replacement Adjustment Mechanism to facilitate and complement projects involving the enhancement and replacement of gas infrastructure, providing timely cost recovery for qualifying non-revenue producing capital expenditures. Hearings on the general rate case application are anticipated in the third quarter of 2013 with new rates proposed to be effective January 2014.

Arizona General Rate Case.    In November 2010, Southwest filed a general rate application with the Arizona Corporation Commission (“ACC”) for its Arizona rate jurisdiction. The ACC authorized a general rate increase of $52.6 million effective January 2012 which included a return on common equity of 9.50%, a fair value rate of return of 6.92% and a capital structure consisted of 47.7% long-term debt and 52.3% common equity, with an embedded cost of debt of 8.34%. The ACC also approved a full revenue decoupling mechanism with a monthly weather adjuster. Management has not determined the timing of filing its next general rate case in Arizona; however, Southwest agreed in the settlement in the most recent Arizona general rate case filing to not file a general rate case in Arizona until April 30, 2016. If approval of the decoupling mechanism is rescinded by the ACC, the prohibition against the filing of general rate cases will be eliminated.

Pipe Replacement Tracking Mechanisms

Customer-Owned Yardline (“COYL”) Program.    At December 31, 2011, there were approximately 100,000 customers in Arizona whose natural gas meters are set-off away from the customer’s home (e.g., near a backyard property line), as opposed to a more traditional configuration in which the meter is adjacent to the home. Under the COYL configuration, the customer owns, operates, and is responsible for maintaining the service line that runs from the meter to the home. As these lines age, they periodically develop low pressure leaks which result in immediate termination of natural gas service, and a subsequent need for the customer to repair or replace the COYL prior to service restoration. To address the cost normally borne by the customer to repair or replace the COYL, the Company received approval to implement a program (as part of its 2010 Arizona rate case decision) under which the Company will replace the customer’s facilities at no immediate direct cost to the customer, and relocate the customer’s meter adjacent to the home, thereby eliminating the customer’s previous operating and maintenance responsibilities associated with the COYL. In addition, the program provides for the Company to endeavor to leak survey all such COYLs over a 3-year period; anticipated costs for the survey are reflected in current rates. As of December 31, 2012, approximately 50,000 COYL services had been inspected and 2,000 relocated. The costs of the replacement portion of this program are capitalized by the Company and were approximately $4 million in 2012. Subject to an annual reporting requirement, a surcharge is added to all bills to recover an amount approximately equal to the amount that the Company would have earned if the additional pipe replacement costs had been included in the rate base amount filed in the 2010 Arizona rate case. Recovery of the surcharge will cease as of the next Arizona general rate case (as the expenditures will then be included in rate base).

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Nevada Pipe Replacement Program.    The Company identified specific pipe replacement projects (including early vintage plastic pipe) for accelerated replacement in its Northern Nevada jurisdiction during 2011 and for its Southern Nevada jurisdiction during 2011 and 2012. The PUCN authorized Southwest to accumulate the incremental depreciation and carrying costs associated with these projects as a regulatory asset through January 2015, by which time any accumulated costs must be reflected in rates pursuant to a general rate case filing, or become subject to an eight-year amortization period; recovery of unamortized post-2015 balances may also be requested in a general rate case filing. As part of the Decision reached in the 2012 general rate case, Southwest was authorized to recover costs accumulated through May 2012 over an eight-year period and to continue to defer the incremental depreciation and carrying costs for approved projects, which will be included in a future general rate case proceeding.

FERC Jurisdiction.    In February 2009, Paiute Pipeline Company, a wholly owned subsidiary of the Company, filed its most recent general rate case with the Federal Energy Regulatory Commission (“FERC”). In April 2010, the FERC approved an offer of settlement from Paiute which resolved all issues related to its general rate case. The settlement provided for an increase of approximately $900,000 in Paiute’s annual operating income and was effective September 2009. Management has not determined the timing of filing its next general rate case with the FERC; however, in the settlement, Paiute agreed to file its next general rate case on or by February 28, 2014.

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, 2012, over-collections in Arizona and Nevada resulted in a liability of $98.9 million and under-collections in California resulted in an asset of $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):

	2012			2011
Arizona	$	(46.6	)	$	(28.4	)
Northern Nevada		(7.1	)		(7.9	)
Southern Nevada		(45.2	)		(36.1	)
California		6.0			2.3
	$	(92.9	)	$	(70.1	)

Arizona PGA Filings.    In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits measured on a twelve-month rolling average. A temporary surcredit of $0.08 per therm was put into place in December 2009 to help accelerate the refund of the over-collected balance to customers. During 2012, approximately $40 million was refunded to customers via the surcredit; however, continued low natural gas prices resulted in a continuing balance due customers. In order to accelerate the refunds to customers, Southwest filed to temporarily increase this rate to $0.10 per therm effective January 2013, which was approved by the ACC in December 2012. A prudence review of gas costs is conducted in conjunction with general rate cases.

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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 2012, Southwest filed its ARA application with the PUCN to establish revised Deferred Energy Account Adjustment (“DEAA”) rates (in addition to adjustments to the Variable Interest Expense rate, the Uncollectible Gas Cost Expense rates, and other rate-related items), which was approved effective January 2013. Southwest makes quarterly DEAA adjustments based upon a twelve-month rolling average. During 2012, approximately $53 million was refunded to customers via billing credits; however, base tariff rates continued to exceed average rates paid for natural gas in 2012 resulting in a net increase in the balance payable to customers.

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 fixed-for-floating swap contracts (“Swaps”) under its collective volatility mitigation programs for a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its annual normal weather supply needs. For the 2012/2013 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $3 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.

Capital Resources and Liquidity

Cash on hand and cash flows from operations have generally been sufficient over the past three years to provide for net investing activities (primarily construction expenditures and property additions). Certain pipe replacement work was accelerated during 2011 and 2012 to take advantage of bonus depreciation tax incentives. During the same three-year period, the Company was able to achieve cost savings from debt refinancing and strategic debt redemptions. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs.

Cash Flows

Operating Cash Flows.    Cash flows provided by consolidated operating activities increased $134 million in 2012 as compared to 2011. The improvement in operating cash flows was attributable to greater net income and non-cash depreciation expense and temporary net cash flow increases resulting from changes in working capital components.

Investing Cash Flows.    Cash used in consolidated investing activities increased $15.2 million in 2012 as compared to 2011. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by NPL due to the increased replacement construction work of its customers.

Financing Cash Flows.    Net cash used in consolidated financing activities increased $21.3 million in 2012 as compared to 2011. A forward-starting interest rate swap (“FSIRS”) contract was settled by paying $21.8 million during the first quarter of 2012 (at maturity). See Note 13 – Derivatives and Fair Value Measurements for more information regarding the FSIRS. Dividends paid increased in 2012 as compared to 2011 as a result of an increase in the quarterly dividend and an increase in the number of shares

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outstanding. The issuance of new debt including the $250 million 3.875% Senior Notes and borrowings on the long-term portion of the credit facility was partially offset by debt repayments including the $12.4 million 1999 6.1% Series A fixed-rate IDRBs repaid in January 2012, the $200 million 7.625% Senior Notes repaid in May 2012, the $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038) repaid in August 2012. The remaining issuance amounts and retirements of long-term debt primarily relate to borrowings and repayments under NPL’s line of credit. The prior year included the repayment of the $200 million 8.375% Notes and the issuance of the $125 million 6.1% Notes.

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.

2012 Construction Expenditures

During the three-year period ended December 31, 2012, total gas plant increased from $4.4 billion to $5 billion, or at an average annual rate of 4%. 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 47,000 meters during the three-year period.

During 2012, construction expenditures for the natural gas operations segment were $309 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant (see also Bonus Depreciation below). Cash flows from operating activities of Southwest were $344 million and provided approximately 95% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and existing credit facilities.

2012 Financing Activity

In January 2012, the Company redeemed at par its $12.4 million 1999 6.1% Series A fixed-rate IDRBs. The IDRBs were originally due in 2038. In February 2012, the Company drew down the remaining $12.8 million in restricted cash from a 2009 IDRB offering. In March 2012, the Company issued $250 million in 3.875% Senior Notes. The notes will mature on April 1, 2022. Management used approximately $200 million of the net proceeds in connection with the repayment of the $200 million 7.625% Senior Notes that matured in May 2012. The remaining net proceeds were used for general corporate purposes. In August 2012, the Company redeemed at par its $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038). During 2012, the Company issued shares of common stock through its various stock plans, including the Stock Incentive Plan, raising approximately $2 million.

Bonus Depreciation.    In September 2010, the Small Business Jobs Act of 2010 (“Act”) was signed into law. The Act provided a 50% bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2010. In December 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (“Tax Relief Act”) was signed into law. The Tax Relief Act provided for a temporary 100% bonus tax depreciation deduction for qualified property acquired or constructed and placed in service after September 8, 2010 and before January 1, 2012 and extended the availability of the 50% bonus tax depreciation deduction through December 31, 2012. In January 2013, the American Taxpayer Relief Act of 2012 (“Taxpayer Relief Act”) was enacted extending the 50% bonus tax depreciation deduction for qualified property acquired or constructed and placed in-service during 2013. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provisions of the two acts will defer the payment of approximately $30 million and $37 million of federal income taxes for 2012 and 2013, respectively.

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Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2015 will be approximately $1 billion. Of this amount, approximately $320 million to $360 million are expected to be incurred in 2013 depending on the approval and timing of requested infrastructure replacement mechanisms in Nevada (see Rates and Regulatory Proceedings). Southwest has taken advantage of bonus depreciation tax benefits 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. During the three-year period, cash flows from operating activities of Southwest (including the bonus depreciation benefits) are expected to provide approximately 85% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including 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.

The Company’s $30 million 2003 5.45% Series C fixed-rate IDRBs and $15 million 2003 5.8% Series E fixed-rate IDRBs include a put feature that requires the remarketing of these IDRBs on March 1, 2013. The Company has the option to remarket these IDRBs at various intervals until the due date of 2038. However, once the remarketing process in March 2013 is complete, the Company intends to redeem these IDRB’s at par. These IDRBs are shown as current maturities in the Company’s consolidated balance sheet. The Company will facilitate the redemption primarily from borrowings under its $300 million credit facility.

Liquidity

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

On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2012, the combined balance in the PGA accounts totaled an over-collection of $92.9 million. See PGA Filings for more information.

In March 2012, the Company replaced a $300 million revolving credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. 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 the Company’s current unsecured debt rating, the applicable margin is 1.125% for loans bearing interest with reference to LIBOR and 0.125% for loans bearing interest with reference to the alternative base rate. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the

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remaining $150 million for working capital purposes. The borrowings at December 31, 2011 (and additional borrowings which resulted in a maximum outstanding balance of $128 million during the first quarter) under the predecessor facility were repaid during the first quarter of 2012. At December 31, 2012, $111 million was outstanding on the long-term portion of the new credit facility (including $20 million under the commercial paper program), and no borrowings were outstanding on the short-term portion. No borrowings occurred under the new facility during the second quarter of 2012, and the maximum amount outstanding during the third and fourth quarters of 2012 was $40 million and $130 million, respectively. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any, or meeting the refund needs of over-collected balances. This credit facility has been, 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, 2012, $20 million was outstanding on the commercial paper program. The maximum amount outstanding during the year was $20 million.

In June 2012, NPL replaced its existing $30 million revolving credit facility that was to expire in June 2013 with a $75 million facility that is scheduled to expire in June 2015. The credit facility was amended in October 2012 to temporarily increase the facility from $75 million to $85 million until December 29, 2012 and then reverted back to $75 million. Interest rates for the credit facility were also amended in October 2012 and are now calculated at either LIBOR or a base rate, plus, in each case, 1.00% or 0.75% depending on NPL’s leverage ratio at the end of each quarter. At December 31, 2012, $41.6 million was outstanding on the NPL 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 March 2012, Moody’s upgraded the Company’s senior unsecured long-term debt rating to Baa1 from Baa2 (the outlook remains stable). Moody’s cited the Company’s prospects for continued strong financial results and credit metrics, as well as the resolution of the Arizona rate case as factors in its decision. Moody’s applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.

In May 2012, Fitch upgraded the Company’s senior unsecured long-term debt rating to A- from BBB+ (the outlook has been revised to positive from stable). Fitch cited the Company’s strong operational performance for 2011 and expectations for continued strong performance for 2012, due in part to the recent rate design changes adopted in Arizona. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of A- indicates low credit risk and a strong ability to pay financial commitments.

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The Company’s unsecured long-term debt rating from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as of April 2011. 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.

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 agencies. 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. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2012, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.7 billion in additional debt and meet the leverage ratio requirement. The Company has at least $700 million of cushion in equity relating to the minimum net worth requirement.

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 leases, which are described in Note 2 – Utility Plant 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, 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, 2012 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2013		2014-2015		2016-2017		Thereafter
Operating activities:
Operating leases (Note 2)	$	18	$	7	$	7	$	4	$	—
Gas purchase obligations		165		117		48		—		—
Pipeline capacity		793		110		194		123		366
Derivatives (Note 13)		3		2		1		—		—
Other commitments		15		7		7		1		—
Financing activities:
Long-term debt, including current maturities (Note 7)		1,319		50		52		141		1,076
Interest on long-term debt		843		52		102		99		590
Other		16		—		1		2		13
Total	$	3,172	$	345	$	412	$	370	$	2,045

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 147 million dekatherms. Fixed-price contracts range in price from approximately $3 to $5 per dekatherm. Variable-price contracts reflect minimum contractual obligations.

Southwest has pipeline capacity 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.

Obligations for Financing Activities:    Contractual obligations for financing activities are debt obligations consisting of scheduled principal and interest payments over the life of the debt. Southwest’s plans to redeem $45 million of IDRBs in March 2013 (originally due in 2038) are also reflected in the table above. See Capital Resources and Liquidity.

Other:    Estimated funding for pension and other postretirement benefits during calendar year 2013 is $47 million.

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to offsetting of assets and liabilities on the balance sheets, testing of indefinite-lived intangible

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assets for impairment, and technical corrections and improvements. 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. The Company reviews these 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.

Accounting for Income Taxes

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

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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 $31.4 million and future pension expense by $3.3 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.8 million and expense by $1.6 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.5 million (but has no impact on the pension obligation).

At December 31, 2012, the Company lowered the discount rate to 4.25% from a rate of 5.00% at December 31, 2011. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase decreased to 2.75% at December 31, 2012 from 3.00% in the prior year. The asset return assumption remains the same at 8.00%. The significant reduction in the discount rate will increase the expense level for 2013. Pension expense for 2013 is estimated to increase by $6.4 million. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Certifications

The Securities and Exchange Commission (“SEC”) requires the 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, 2012 are included as exhibits to the 2012 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,

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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,” 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, use of proceeds, 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, forecasted operating cash flows and results of operations, incremental operating margin in 2013, operating expense increases in 2013, funding sources of cash requirements, sufficiency of working capital, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, NPL’s projected financial performance and related market growth potential, NPL’s bid contracts (or contracts with caps) and results thereunder, including expectations regarding estimates of costs and revenues, pension and post-retirement benefits, certain benefits of tax acts, the effect of rate decoupling in Arizona, the effect of any rate changes or regulatory proceedings, including the Decision from the PUCN and the California general rate case filing, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, 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, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, results of NPL bid work, impacts of structural and management changes at NPL, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

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).

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Common Stock Price and Dividend Information

	2012				2011				Dividends Declared
	High		Low		High		Low		2012		2011
First quarter	$	43.64	$	40.51	$	39.68	$	36.33	$	0.295	$	0.265
Second quarter		44.64		39.46		40.59		36.61		0.295		0.265
Third quarter		46.08		42.19		39.92		32.12		0.295		0.265
Fourth quarter		44.83		39.01		43.20		34.55		0.295		0.265
									$	1.180	$	1.060

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2013, there were 15,969 holders of record of common stock, and the market price of the common stock was $44.50.

In reviewing dividend policy, the Board of Directors (“Board”) considers the adequacy and sustainability of earnings and cash flows of the Company and its subsidiaries; the strength of the Company’s capital structure; the sustainability of the dividend through all business cycles; and whether the dividend is within a normal payout range for its respective businesses. The quarterly common stock dividend declared was 25 cents per share throughout 2010, 26.5 cents per share throughout 2011, and 29.5 cents per share throughout 2012. As a result of its ongoing review of dividend policy, in February 2013, the Board increased the quarterly dividend from 29.5 cents to 33 cents per share, effective with the June 2013 payment. This marks the seventh 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.

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SOUTHWEST GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

December 31,	2012			2011
ASSETS
Utility plant:
Gas plant	$	5,019,500		$	4,811,050
Less: accumulated depreciation		(1,750,795	)		(1,638,091	)
Acquisition adjustments, net		911			1,091
Construction work in progress		74,178			44,894
Net utility plant (Note 2)		3,343,794			3,218,944
Other property and investments		242,096			192,004
Restricted cash		—			12,785
Current assets:
Cash and cash equivalents		25,530			21,937
Accounts receivable, net of allowances (Note 3)		196,913			209,246
Accrued utility revenue		72,000			70,300
Income taxes receivable, net		2,945			7,793
Deferred income taxes (Note 12)		47,088			53,435
Deferred purchased gas costs (Note 4)		6,031			2,323
Prepaids and other current assets (Notes 1 and 4)		107,910			96,598
Total current assets		458,417			461,632
Deferred charges and other assets (Notes 4 and 13)		443,750			390,642
Total assets	$	4,488,057		$	4,276,007

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CONSOLIDATED BALANCE SHEETS - Continued

December 31,	2012			2011
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized – 60,000,000 shares; issued and outstanding – 46,147,788 and 45,956,088 shares) (Note 11)	$	47,778		$	47,586
Additional paid-in capital		828,777			821,640
Accumulated other comprehensive income (loss), net (Note 5)		(50,745	)		(49,331	)
Retained earnings		484,369			406,125
Total Southwest Gas Corporation equity		1,310,179			1,226,020
Noncontrolling interest		(1,681	)		(989	)
Total equity		1,308,498			1,225,031
Long-term debt, less current maturities (Note 7)		1,268,373			930,858
Total capitalization		2,576,871			2,155,889
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		50,137			322,618
Accounts payable		155,667			186,755
Customer deposits		77,858			83,839
Accrued general taxes		37,644			42,102
Accrued interest		16,080			16,699
Deferred purchased gas costs (Note 4)		98,957			72,426
Other current liabilities (Notes 4 and 13)		98,786			123,129
Total current liabilities		535,129			847,568
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 12)		616,184			557,118
Taxes payable		551			828
Accumulated removal costs (Note 4)		256,000			233,000
Other deferred credits (Notes 4 and 10)		503,322			481,604
Total deferred income taxes and other credits		1,376,057			1,272,550
Total capitalization and liabilities	$	4,488,057		$	4,276,007

The accompanying notes are an integral part of these statements.

40

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

Year Ended December 31,	2012			2011			2010
Operating revenues:
Gas operating revenues	$	1,321,728		$	1,403,366		$	1,511,907
Construction revenues		606,050			483,822			318,464
Total operating revenues		1,927,778			1,887,188			1,830,371
Operating expenses:
Net cost of gas sold		479,602			613,489			736,175
Operations and maintenance		369,979			358,498			354,943
Depreciation and amortization		223,422			200,469			190,463
Taxes other than income taxes		41,728			40,949			38,869
Construction expenses		541,523			423,703			277,804
Total operating expenses		1,656,254			1,637,108			1,598,254
Operating income		271,524			250,080			232,117
Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(68,020	)		(69,602	)		(75,677	)
Net interest deductions on subordinated debentures (Note 6)		—			—			(1,912	)
Other income (deductions)		4,411			(5,412	)		3,850
Total other income and (expenses)		(63,609	)		(75,014	)		(73,739	)
Income before income taxes		207,915			175,066			158,378
Income tax expense (Note 12)		75,276			63,303			54,925
Net income		132,639			111,763			103,453
Net income (loss) attributable to noncontrolling interest		(692	)		(524	)		(424	)
Net income attributable to Southwest Gas Corporation	$	133,331		$	112,287		$	103,877
Basic earnings per share (Note 15)	$	2.89		$	2.45		$	2.29
Diluted earnings per share (Note 15)	$	2.86		$	2.43		$	2.27
Average number of common shares outstanding		46,115			45,858			45,405
Average shares outstanding (assuming dilution)		46,555			46,291			45,823

The accompanying notes are an integral part of these statements.

41

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

Year Ended December 31,	2012			2011			2010
Net Income	$	132,639		$	111,763		$	103,453
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)		(46,409	)		(84,005	)		(5,616	)
Amortization of transition obligation		538			537			538
Amortization of net actuarial loss		15,870			9,653			7,516
Prior service cost		(1,502	)		—			—
Regulatory adjustment		26,518			65,677			404
Net defined benefit pension plans		(4,985	)		(8,138	)		2,842
Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 13)		1,834			(11,134	)		(11,436	)
Amounts reclassified into net income (Notes 5 and 13)		1,737			725			60
Net forward-starting interest rate swaps		3,571			(10,409	)		(11,376	)
Total other comprehensive income (loss), net of tax		(1,414	)		(18,547	)		(8,534	)
Comprehensive income		131,225			93,216			94,919
Comprehensive income (loss) attributable to noncontrolling interest		(692	)		(524	)		(424	)
Comprehensive income attributable to Southwest Gas Corporation	$	131,917		$	93,740		$	95,343

The accompanying notes are an integral part of these statements.

42

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

Year Ended December 31,	2012			2011			2010
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	132,639		$	111,763		$	103,453
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		223,422			200,469			190,463
Deferred income taxes		66,280			56,467			50,111
Changes in current assets and liabilities:
Accounts receivable, net of allowances		12,333			(61,641	)		10,117
Accrued utility revenue		(1,700	)		(5,900	)		7,300
Deferred purchased gas costs		22,823			(52,885	)		33,013
Accounts payable		(25,998	)		15,826			6,680
Accrued taxes		113			14,979			(15,240	)
Other current assets and liabilities		(18,948	)		(3,347	)		12,895
Gains on sale		(8,040	)		(3,307	)		(1,547	)
Changes in undistributed stock compensation		5,137			6,125			4,429
AFUDC and property-related changes		(1,943	)		(1,154	)		(945	)
Changes in other assets and deferred charges		(15,367	)		11,025			(12,262	)
Changes in other liabilities and deferred credits		(4,427	)		(36,378	)		(17,474	)
Net cash provided by operating activities		386,324			252,042			370,993

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CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued

Year Ended December 31,	2012			2011			2010
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(395,712	)		(380,991	)		(215,439	)
Restricted cash		12,785			24,996			11,988
Changes in customer advances		(3,025	)		(7,771	)		(830	)
Miscellaneous inflows		13,963			7,686			4,075
Miscellaneous outflows		(2,004	)		(2,719	)		(2,800	)
Net cash used in investing activities		(373,993	)		(358,799	)		(203,006	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		1,581			7,402			11,098
Dividends paid		(53,040	)		(47,929	)		(44,846	)
Interest rate swap settlement		(21,754	)		—			(11,691	)
Issuance of long-term debt, net		489,518			274,598			123,960
Retirement of long-term debt		(427,043	)		(330,473	)		(3,327	)
Redemption of subordinated debentures		—			—			(100,000	)
Change in credit facility and commercial paper		2,000			109,000			(92,400	)
Net cash provided by (used in) financing activities		(8,738	)		12,598			(117,206	)
Change in cash and cash equivalents		3,593			(94,159	)		50,781
Cash and cash equivalents at beginning of period		21,937			116,096			65,315
Cash and cash equivalents at end of period	$	25,530		$	21,937		$	116,096
Supplemental information:
Interest paid, net of amounts capitalized	$	87,439		$	69,842		$	87,000
Income taxes paid (received)	$	2,843		$	(13,635	)	$	19,200

The accompanying notes are an integral part of these statements.

44

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(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
	Shares		Amount
DECEMBER 31, 2009		45,092	$	46,722	$	792,339	$	(22,250	)	$	285,316		$	(41	)	$	1,102,086
Common stock issuances		507		507		15,546											16,053
Net income (loss)											103,877			(424	)		103,453
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)								2,842									2,842
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13)								(11,436	)								(11,436	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)								60									60
Dividends declared Common: $1.00 per share											(46,062	)					(46,062	)
DECEMBER 31, 2010		45,599		47,229		807,885		(30,784	)		343,131			(465	)		1,166,996
Common stock issuances		357		357		13,755											14,112
Net income (loss)											112,287			(524	)		111,763
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)								(8,138	)								(8,138	)
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13)								(11,134	)								(11,134	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)								725									725
Dividends declared Common: $1.06 per share											(49,293	)					(49,293	)

45

CONSOLIDATED STATEMENTS OF EQUITY - Continued

Southwest Gas Corporation Equity
	Common Stock					Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total
	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 10)									(4,985	)								(4,985	)
FSIRS realized and unrealized gain, net of tax (Notes 5 and 13)									1,834									1,834
Amounts reclassified to net income, net of tax (Notes 5 and 13)									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

* At December 31, 2012, 2.2 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 125,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 11).

The accompanying notes are an integral part of these statements.

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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. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

Basis of Presentation.    The Company follows generally accepted accounting principles in the United States (“U.S. GAAP”) in accounting for all of its businesses. 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. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities.

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):

	2012			2011
NPL property and equipment	$	287		$	237
Accumulated provision for depreciation and amortization		(136	)		(128	)
Net cash surrender value of COLI policies		80			74
Other property		11			9
Total	$	242		$	192

47

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 plant materials and operating supplies of $25 million in 2012 and $21 million in 2011.

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.

Cash and Cash Equivalents.    For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. Cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. During 2012, approximately $20 million of customer advances, upon contract expiration, were applied as contributions offsetting construction expenditures as a non-cash investing activity.

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, 2012		December 31, 2011
Accumulated removal costs	$	256,000	$	233,000

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.

48

Construction Revenues.    The majority of NPL contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two 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 the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps, that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.

In 2011, NPL recorded $5 million in estimated pretax profit associated with a large fixed-price contract. In connection with significant changes in estimated costs to complete the fixed-price contract, NPL results reflect pretax losses (with after-tax earnings per share impacts) of $15 million ($0.20 per share) for the year ended December 31, 2012, including $18 million ($0.24 per share) in the first half of 2012. The estimated cost changes that resulted in the losses recognized included reductions in projected productivity and higher costs of restoration work. Change orders approved during the fourth quarter of 2012 helped to reduce losses overall on the contract. On a contract-to-date basis the cumulative loss is $10 million. At December 31, 2012, work on this sizeable contract is over 95% complete.

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, and office-related fixed costs of NPL.

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

49

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.

	2012		2011		2010
(In thousands)
AFUDC:
Debt portion	$	1,129	$	718	$	512
Equity portion		1,943		1,154		945
AFUDC capitalized as part of utility plant	$	3,072	$	1,872	$	1,457

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):

	2012			2011			2010
Change in COLI policies	$	6,600		$	700		$	9,770
Interest income		924			485			194
Pipe replacement costs		(2,680	)		(4,761	)		(5,024	)
Miscellaneous income and (expense)		(433	)		(1,836	)		(1,090	)
Total other income (deductions)	$	4,411		$	(5,412	)	$	3,850

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, is 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 completed in 2012.

Earnings Per Share.    Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of 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 shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.

	2012		2011		2010
(In thousands)
Average basic shares		46,115		45,858		45,405
Effect of dilutive securities:
Stock options		42		52		56
Performance shares		254		271		260
Restricted stock units		144		110		102
Average diluted shares		46,555		46,291		45,823

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Recently Issued Accounting Standards Updates.    In October 2012, the Financial Accounting Standards Board (“FASB”) issued the update “Technical Corrections and Improvements” which clarifies or corrects unintended application of accounting guidance. Many of these changes are not expected to have a significant effect on current accounting practice but some improvements are more substantive and are not technical corrections. Amendments included in the update without transition guidance were effective upon issuance. Amendments subject to transition guidance were effective for the Company on January 1, 2013 for interim and annual reporting periods. The adoption of the update is not expected to have a material impact on the Company’s disclosures, financial position, or results of operations.

In July 2012, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment,” which provides that an entity has the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that an indefinite-lived intangible asset is impaired. If, in electing the qualitative evaluation step, there is no indication of impairment, quantitative impairment testing would not be required to be performed. The update would provide consistency in evaluation for goodwill and indefinite-lived intangibles other than goodwill. The Company adopted this update, as required, on January 1, 2013. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.

In December 2011, the FASB issued the update “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entity’s financial statements to understand the effect of those arrangements on the entity’s financial position. In January 2013, the FASB issued the update “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“Clarification”) that clarifies the scope of the “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” update. The amendments included in the Clarification apply to entities that have derivatives, repurchase agreements and reverse repurchase agreements, and certain securities borrowing and securities lending transactions that are offset, or subject to a master netting or similar agreement. Entities with other types of financial assets and financial liabilities subject to a master netting or similar agreements would no longer be subject to the disclosure requirements in the initial update. All disclosures are required to be provided retrospectively for all periods presented. The Company adopted both updates, as required, on January 1, 2013 for interim and annual reporting periods. These updates are 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.

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Note 2 – Utility Plant

Net utility plant as of December 31, 2012 and 2011 was as follows (thousands of dollars):

December 31,	2012			2011
Gas plant:
Storage	$	20,503		$	20,496
Transmission		301,505			295,103
Distribution		4,224,560			4,048,078
General		310,936			291,639
Other		161,996			155,734
		5,019,500			4,811,050
Less: accumulated depreciation		(1,750,795	)		(1,638,091	)
Acquisition adjustments, net		911			1,091
Construction work in progress		74,178			44,894
Net utility plant	$	3,343,794		$	3,218,944

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

	2012		2011		2010
Depreciation and amortization expense	$	182,612	$	172,712	$	167,050

Operating Leases and Rentals.    Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The table below presents the rental payments and the current term expiration dates, although both leases have optional renewal terms available.

	2013		2014		2015		2016		2017
(In thousands)
Corporate headquarters (expires in 2017)	$	2,140	$	2,190	$	2,270	$	2,343	$	1,194
Phoenix administrative offices (expires in 2014)		1,446		243		—		—		—

In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases and, for the gas segment, are also treated as such for regulatory purposes. NPL has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest rental payments and NPL lease payments that are included in operating expenses for all operating leases (in thousands):

	2012		2011		2010
Southwest Gas	$	7,762	$	7,812	$	7,585
NPL		24,054		19,017		11,780
Consolidated rental payments/lease expense	$	31,816	$	26,829	$	19,365

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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, 2012 (thousands of dollars):

Year Ending December 31,
2013	$	6,757
2014		4,304
2015		3,181
2016		2,510
2017		1,238
Thereafter		61
Total minimum lease payments	$	18,051

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 at December 31, 2012, and the percentage of customers in each of the three states.

Gas utility customer accounts receivable balance (in thousands)	$	94,695
		December 31, 2012
Percent of customers by state
Arizona		54	%
Nevada		36	%
California		10	%

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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, 2009	$	3,953
Additions charged to expense		2,646
Accounts written off, less recoveries		(3,405	)
Balance, December 31, 2010		3,194
Additions charged to expense		2,678
Accounts written off, less recoveries		(2,690	)
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

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”). Southwest accounting policies conform to U.S. GAAP applicable to rate-regulated entities and reflect the effects of the ratemaking process. Accounting treatment for rate-regulated entities allows for deferral as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

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

December 31,	2012			2011
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	373,615		$	330,844
Unrealized net loss on non-trading derivatives (Swaps) (2)		2,395			11,743
Deferred purchased gas costs (3)		6,031			2,323
Accrued purchased gas costs (4)		30,300			18,400
Unamortized premium on reacquired debt (5)		19,452			19,011
Other (6)		44,927			32,988
		476,720			415,309
Regulatory liabilities:
Deferred purchased gas costs (3)		(98,957	)		(72,426	)
Accumulated removal costs		(256,000	)		(233,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		(6	)		—
Deferred gain on southern Nevada division operations facility (7)		(392	)		(806	)
Unamortized gain on reacquired debt (8)		(11,934	)		(12,470	)
Other (9)		(6,951	)		(14,501	)
Net regulatory assets	$	102,480		$	82,106

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

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

Instrument	Balance Sheet Location	2012			2011
Swaps	Deferred charges and other assets	$	319		$	621
Swaps	Prepaids and other current assets		2,076			11,122
Swaps	Other deferred credits		(6	)		—

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

(4) Included in Prepaids and other current assets on the Consolidated Balance Sheets and recovered over one year or less.

(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 Decision, the amortization period was extended through 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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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.

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

	2012									2011									2010
	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)	$	(74,853	)	$	28,444		$	(46,409	)	$	(135,492	)	$	51,487		$	(84,005	)	$	(9,058	)	$	3,442		$	(5,616	)
Amortization of transition obligation		867			(329	)		538			867			(330	)		537			867			(329	)		538
Amortization of net actuarial (gain)/loss		25,597			(9,727	)		15,870			15,569			(5,916	)		9,653			12,122			(4,606	)		7,516
Prior service cost		(2,423	)		921			(1,502	)		—			—			—			—			—			—
Regulatory adjustment		42,771			(16,253	)		26,518			105,931			(40,254	)		65,677			652			(248	)		404
Pension plans other comprehensive income (loss)		(8,041	)		3,056			(4,985	)		(13,125	)		4,987			(8,138	)		4,583			(1,741	)		2,842
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		2,959			(1,125	)		1,834			(17,958	)		6,824			(11,134	)		(18,446	)		7,010			(11,436	)
Amounts reclassified into net income		2,801			(1,064	)		1,737			1,169			(444	)		725			97			(37	)		60
FSIRS other comprehensive income (loss)		5,760			(2,189	)		3,571			(16,789	)		6,380			(10,409	)		(18,349	)		6,973			(11,376	)
Total other comprehensive income (loss)	$	(2,281	)	$	867		$	(1,414	)	$	(29,914	)	$	11,367		$	(18,547	)	$	(13,766	)	$	5,232		$	(8,534	)

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

Approximately $2.1 million of realized losses (net of tax) related to the forward-starting interest rate swaps (“FSIRS”), reported in AOCI at December 31, 2012, will be reclassified into expense within the next twelve months as the related interest payments on long-term debt occur.

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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	$	32,400
SERP net actuarial loss		1,000
PBOP net actuarial loss		1,000
PBOP prior service cost		400

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

AOCI – Rollforward

(Thousands of dollars)

	Defined Benefit Plans (Note 10)								FSIRS (Note 13)
	Before- Tax			Tax (Expense) Benefit		After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			AOCI
Beginning Balance AOCI December 31, 2011	$	(44,429	)	$	16,883	$	(27,546	)	$	(35,138	)	$	13,353		$	(21,785	)	$	(49,331	)
Current period other comprehensive income (loss)		(8,041	)		3,056		(4,985	)		5,760			(2,189	)		3,571			(1,414	)
Ending Balance AOCI December 31, 2012	$	(52,470	)	$	19,939	$	(32,531	)	$	(29,378	)	$	11,164		$	(18,214	)	$	(50,745	)

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, 2012 and 2011:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2012			2011
Net actuarial (loss) gain	$	(423,662	)	$	(374,406	)
Prior service cost		(2,423	)		—
Net transition obligation		—			(867	)
Less: amount recognized in regulatory assets		373,615			330,844
Recognized in AOCI	$	(52,470	)	$	(44,429	)

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

Note 6 – Preferred Trust Securities and Subordinated Debentures

In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In

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August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures (“Subordinated Debentures”) to Trust II. The Subordinated Debentures became redeemable at the option of the Company in August 2008.

In February 2010, the Company notified holders of the Subordinated Debentures that all of these debentures (and the associated preferred and common securities) would be redeemed (at par) by the Company in March 2010. All of the outstanding Subordinated Debentures were redeemed in March 2010. The Company accomplished the redemption using existing cash and borrowings under the previous $300 million credit facility.

Interest payments and amortizations associated with the Subordinated Debentures are classified on the 2010 consolidated statement of income as Net interest deductions on subordinated debentures.

Note 7 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2012 and December 31, 2011 are disclosed in the following table. The fair values of the revolving credit facility, the NPL revolving credit facility, and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, and are categorized as Level 1 (quoted prices for identical financial instruments) within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The market values of debentures (except the 4.45% Notes) and fixed-rate IDRBs are categorized as Level 2. The 4.45% Notes and NPL other debt obligations are categorized as Level 3 (based on significant unobservable inputs to their fair values). Fair values for the debentures, fixed-rate IDRBs, and NPL other debt obligations were determined through a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

December 31,	2012					2011
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 7.625%, due 2012	$	—		$	—	$	200,000		$	204,312
Notes, 4.45%, due 2020		125,000			141,771		125,000			128,673
Notes, 6.1%, due 2041		125,000			165,779		125,000			143,074
Notes, 3.875%, due 2022		250,000			277,950		—			—
8% Series, due 2026		75,000			111,501		75,000			96,340
Medium-term notes, 7.59% series, due 2017		25,000			30,710		25,000			30,199
Medium-term notes, 7.78% series, due 2022		25,000			34,637		25,000			31,932
Medium-term notes, 7.92% series, due 2027		25,000			36,953		25,000			31,648
Medium-term notes, 6.76% series, due 2027		7,500			10,058		7,500			8,510
Unamortized discount		(3,403	)				(2,087	)
		654,097					605,413
Revolving credit facility and commercial paper		111,000			111,000		109,000			109,000

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December 31,	2012					2011
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
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:
6.10% 1999 Series A, due 2038		—			—		12,410			12,410
5.95% 1999 Series C, due 2038		—			—		14,320			14,449
5.55% 1999 Series D, due 2038		8,270			8,375		8,270			8,253
5.45% 2003 Series C, due 2038 (rate resets in March 2013)		30,000			30,152		30,000			31,332
5.25% 2003 Series D, due 2038		20,000			20,571		20,000			19,583
5.80% 2003 Series E, due 2038 (rate resets in March 2013)		15,000			15,102		15,000			15,634
5.25% 2004 Series A, due 2034		65,000			66,955		65,000			64,291
5.00% 2004 Series B, due 2033		31,200			31,655		31,200			30,283
4.85% 2005 Series A, due 2035		100,000			101,184		100,000			94,836
4.75% 2006 Series A, due 2036		24,855			25,189		24,855			23,179
Unamortized discount		(3,195	)				(3,360	)
		491,130					517,695
NPL credit facility		41,562			41,562		16,566			16,566
NPL other debt obligations		20,721			20,991		4,802			4,814
		1,318,510					1,253,476
Less: current maturities		(50,137	)				(322,618	)
Long-term debt, less current maturities	$	1,268,373				$	930,858

In January 2012, the Company redeemed at par its $12.4 million 1999 6.1% Series A fixed-rate IDRBs (originally due in 2038). In August 2012, the Company redeemed at par its $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038).

In March 2012, the Company issued $250 million in 3.875% Senior Notes at a 0.034% discount. The notes will mature on April 1, 2022. Management used approximately $200 million of the net proceeds in connection with the repayment of the $200 million 7.625% Senior Notes that matured in May 2012. The remaining net proceeds were used for general corporate purposes.

In March 2012, the Company replaced the existing $300 million revolving credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or the “alternate base rate,” plus, in each case, an applicable margin that is determined based on the Company’s senior unsecured debt rating. At the Company’s current unsecured debt rating, the applicable margin is 1.125% for loans bearing interest with reference to LIBOR and 0.125% for loans bearing interest with reference to the

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alternative base rate. Southwest has designated $150 million of the $300 million facility for long-term purposes and the remaining $150 million for working capital purposes. At December 31, 2012, $91 million was outstanding on the credit facility. Borrowings under the credit facility ranged from $0 during the second quarter of 2012 to a high of $130 million during November 2012. The effective interest rate on the long-term portion of the credit facility was 1.43% at December 31, 2012. There were no borrowings outstanding on the short-term portion of the credit facility at December 31, 2011 and 2012. (See Note 8 – Short-Term Debt).

The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the new program are calculated at the then current commercial paper rate. At December 31, 2012, $20 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.84% at December 31, 2012.

In February 2013, a notice of mandatory tender was sent to holders of the Clark County, Nevada 5.45% Series 2003C and 5.80% Series 2003E IDRBs. These IDRBs (totaling $45 million) are subject to mandatory tender on March 1, 2013 at a price of 100% plus accrued interest, and the Company intends to tender these IDRBs to the trustee for cancellation immediately following the mandatory tender, thereby extinguishing this debt. Therefore, these IDRBs are shown as current maturities in the Company’s consolidated balance sheet. The Company will facilitate the redemption primarily from borrowings under its $300 million credit facility.

In June 2012, NPL replaced its existing $30 million revolving credit facility that was to expire in June 2013 with a $75 million facility that is scheduled to expire in June 2015. The credit facility was amended in October 2012 to temporarily increase the facility from $75 million to $85 million until December 29, 2012 and then reverted back to $75 million. Interest rates for the credit facility were also amended in October 2012 and are now calculated at either LIBOR or a base rate, plus, in each case, 1.00% or 0.75% depending on NPL’s leverage ratio at the end of each quarter. At December 31, 2012, $41.6 million was outstanding on the NPL credit facility. The effective interest rate on NPL’s credit facility was 0.97% at December 31, 2012.

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

	December 31, 2012			December 31, 2011
2003 Series A		1.71	%		0.83	%
2008 Series A		1.59	%		1.62	%
2009 Series A		1.14	%		1.56	%
Tax-exempt Series A		1.25	%		2.22	%

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.

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

2013	$	50,137
2014		5,249
2015		46,705
2016		4,143
2017		137,049

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, 2012, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.7 billion in additional debt and meet the leverage ratio requirement. The Company has at least $700 million of cushion in equity relating to the minimum net worth requirement.

Note 8 — Short-Term Debt

As discussed in Note 7, Southwest replaced the existing $300 million credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Of the $300 million available under the facility, $150 million was designated by management for working capital purposes. The Company had no short-term borrowings outstanding at December 31 in either 2011 or 2012.

Note 9 — Commitments and Contingencies

The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is currently subject will have a material adverse impact on its financial position or results of operations.

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers are responsible for amounts up to the policy limits. The self-insured retention amount associated with general liability claims is $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million in the policy year.

Note 10 – Pension and Other Postretirement Benefits

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

	2012		2011		2010
Employee Investment Plan cost	$	4,707	$	4,626	$	4,583

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

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees and a separate unfunded supplemental 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. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are 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. The current 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

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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 the continuing low interest rate environment for high-quality fixed income investments, the Company lowered the discount rate in 2012 from 2011. 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) in 2012 from 2011 and the asset return assumption was unchanged between periods. The rates are presented in the table below:

	December 31, 2012			December 31, 2011
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.00	%
Asset return assumption		8.00	%		8.00	%

The significant reduction in the discount rate will increase the expense level for 2013. Pension expense for 2013 is estimated to increase by $6.4 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

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

	2012									2011
	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)	$	780,571		$	33,827		$	52,182		$	662,134		$	31,860		$	46,765
Service cost		20,319			274			977			17,725			217			858
Interest cost		38,266			1,629			2,547			37,276			1,766			2,631
Plan amendments		-			-			2,423			-			-			-
Actuarial loss (gain)		92,409			4,111			2,775			89,922			2,427			2,835
Benefits paid		(28,753	)		(2,468	)		(1,200	)		(26,486	)		(2,443	)		(907	)
Benefit obligation at end of year (PBO/PBO/APBO)		902,812			37,373			59,704			780,571			33,827			52,182
Change in plan assets
Market value of plan assets at beginning of year		521,829			-			29,944			475,931			-			29,640
Actual return on plan assets		68,174			-			4,454			2,384			-			(200	)
Employer contributions		48,500			2,468			1,256			70,000			2,443			904
Benefits paid		(28,753	)		(2,468	)		(404	)		(26,486	)		(2,443	)		(400	)
Market value of plan assets at end of year		609,750			-			35,250			521,829			-			29,944
Funded status at year end	$	(293,062	)	$	(37,373	)	$	(24,454	)	$	(258,742	)	$	(33,827	)	$	(22,238	)
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	%		2.75	%		3.00	%		3.00	%		3.00	%

Estimated funding for the plans above during calendar year 2013 is approximately $49 million of which $46 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, 2012		December 31, 2011
Retirement plan	$	811,184	$	699,269
SERP		35,362		32,695

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

	2013		2014		2015		2016		2017		2018-2022
Pension	$	33.2	$	34.9	$	36.7	$	38.5	$	40.6	$	234.4
PBOP		2.6		2.8		3.0		3.2		3.3		17.4
SERP		2.5		2.5		2.5		2.5		2.5		12.0

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 7.5% 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
	2012			2011			2010			2012			2011			2010			2012			2011			2010
(Thousands of dollars)
Service cost	$	20,319		$	17,725		$	16,932		$	274		$	217		$	372		$	977		$	858		$	856
Interest cost		38,266			37,276			35,614			1,629			1,766			2,045			2,547			2,631			2,491
Expected return on plan assets		(45,780	)		(40,114	)		(36,538	)		-			-			-			(2,404	)		(2,379	)		(2,093	)
Amortization of transition obligation		-			-			-			-			-			-			867			867			867
Amortization of net actuarial loss		23,883			14,348			10,478			683			631			1,155			1,031			590			489
Net periodic benefit cost	$	36,688		$	29,235		$	26,486		$	2,586		$	2,614		$	3,572		$	3,018		$	2,567		$	2,610
Weighted-average assumptions (net benefit cost)
Discount rate		5.00	%		5.75	%		6.00	%		5.00	%		5.75	%		6.00	%		5.00	%		5.75	%		6.00	%
Expected return on plan assets		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.00	%		3.25	%		3.25	%		3.00	%		3.25	%		3.25	%		3.00	%		3.25	%		3.25	%

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

	2012												2011												2010
	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)	$	74,853		$	70,016		$	4,111		$	726		$	135,492		$	127,651		$	2,427		$	5,414		$	9,058		$	10,994		$	(3,480	)	$	1,544
Amortization of transition obligation (b)		(867	)		-			-			(867	)		(867	)		-			-			(867	)		(867	)		-			-			(867	)
Amortization of net actuarial loss (b)		(25,597	)		(23,883	)		(683	)		(1,031	)		(15,569	)		(14,348	)		(631	)		(590	)		(12,122	)		(10,478	)		(1,155	)		(489	)
Prior service cost		2,423			-			-			2,423			-			-			-			-			-			-			-			-
Regulatory adjustment		(42,771	)		(41,520	)		-			(1,251	)		(105,931	)		(101,974	)		-			(3,957	)		(652	)		(464	)		-			(188	)
Recognized in other comprehensive (income) loss		8,041			4,613			3,428			-			13,125			11,329			1,796			-			(4,583	)		52			(4,635	)		-
Net periodic benefit costs recognized in net income		42,292			36,688			2,586			3,018			34,416			29,235			2,614			2,567			32,668			26,486			3,572			2,610
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,333		$	41,301		$	6,014		$	3,018		$	47,541		$	40,564		$	4,410		$	2,567		$	28,085		$	26,538		$	(1,063	)	$	2,610

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.

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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, 2012 and December 31, 2011. The SERP has no assets. There were no transfers between Levels 1 and 2.

	December 31, 2012						December 31, 2011
	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
Cash equivalents	$	—	$	—	$	—	$	20	$	1	$	21
Common stock
Capital equipment		3,510		106		3,616		4,332		133		4,465
Chemicals/materials		6,741		204		6,945		7,425		227		7,652
Consumer goods		49,247		1,492		50,739		40,806		1,249		42,055
Energy and mining		39,454		1,195		40,649		39,080		1,196		40,276
Finance/insurance		28,861		874		29,735		23,808		729		24,537
Healthcare		29,615		897		30,512		26,070		798		26,868
Information technology		30,534		925		31,459		29,052		889		29,941
Services		25,316		767		26,083		17,417		533		17,950
Telecommunications/utilities		24,355		738		25,093		16,257		498		16,755
Other		20,298		615		20,913		22,473		688		23,161
Real estate investment trusts		6,572		199		6,771		5,779		177		5,956
Mutual funds		67,749		17,802		85,551		57,512		14,154		71,666
Government fixed income securities		18,663		565		19,228		5,727		175		5,902
Futures contracts		—		—		—		4		—		4
Total Level 1 Assets (1)	$	350,915	$	26,379	$	377,294	$	295,762	$	21,447	$	317,209
Level 2—Significant other observable inputs
Commercial paper	$	635	$	19	$	654	$	—	$	—	$	—
Government fixed income and mortgage backed securities		42,997		1,302		44,299		42,361		1,297		43,658
Corporate fixed income securities
Asset-backed and mortgage-backed		16,637		504		17,141		16,969		519		17,488
Banking		17,966		544		18,510		16,192		496		16,688
Utilities		4,107		124		4,231		5,064		155		5,219
Other		28,925		876		29,801		25,769		789		26,558
Pooled funds and mutual funds		20,636		1,789		22,425		17,447		2,244		19,691
State and local obligations		1,273		39		1,312		936		29		965
Total Level 2 assets (2)	$	133,176	$	5,197	$	138,373	$	124,738	$	5,529	$	130,267

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	December 31, 2012						December 31, 2011
	Qualified Retirement Plan		PBOP		Total		Qualified Retirement Plan		PBOP		Total
Level 3—Significant unobservable inputs
Commingled equity funds	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Level 3 assets (3)	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Plan assets at fair value	$	607,810	$	35,324	$	643,134	$	517,795	$	29,954	$	547,749
Insurance company general account contracts (4)		4,626		—		4,626		4,952		—		4,952
Total Plan assets (5)	$	612,436	$	35,324	$	647,760	$	522,747	$	29,954	$	552,701

(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 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:

• Investing in various industries with growth and reasonable valuations, avoiding highly cyclical industries

• Diversification by country, limiting exposure in any one country

• Emerging markets

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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 an impact fee to be applied to redemptions and subscriptions of $5 million or greater.

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

(5) The assets in the above table exceed the market value of plan assets shown in the funded status table by $2,760,000 (qualified retirement plan – $2,685,000, PBOP – $75,000) and $928,000 (qualified retirement plan – $918,000, PBOP – $10,000) for 2012 and 2011, 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, 2010	$	97,469
Actual return on plan assets:
Relating to assets still held at the reporting date		(8,442	)
Relating to assets sold during the period		246
Purchases		12,000
Sales		(1,000	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2011		100,273
Actual return on plan assets:
Relating to assets still held at the reporting date		21,552
Relating to assets sold during the period		342
Purchases		6,800
Sales		(1,500	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2012	$	127,467

Note 11 – Stock-Based Compensation

At December 31, 2012, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income is shown in the table below (in thousands):

	2012		2011		2010
Stock-based compensation expense, net of related tax benefits	$	7,396	$	7,262	$	5,874
Stock-based compensation related tax benefits		4,533		4,451		3,600

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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):

	2012					2011					2010
	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		177		$	27.28		369		$	28.04		651		$	27.49
Exercised during the year		(52	)		25.25		(192	)		28.75		(273	)		26.67
Forfeited or expired during the year		—			—		—			—		(9	)		29.51
Outstanding and exercisable at year end		125		$	28.13		177		$	27.28		369		$	28.04

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):

	2012		2011		2010
Outstanding and exercisable	$	1,788	$	2,697	$	3,186
Exercised		928		1,949		1,689

	December 31, 2012		December 31, 2011		December 31, 2010
Market value of Southwest Gas stock	$	42.41	$	42.49	$	36.67

The weighted-average remaining contractual life for outstanding options was 2.7 years for 2012. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2012 (thousands of options):

	Options Outstanding and Exercisable
Range of     Exercise Price	Number outstanding	Weighted-average remaining contractual life	Weighted-average exercise price
$20.49 to $23.40	30	1.2 Years	$22.54
$25.00 to $26.10	34	2.5 Years	$25.74
$29.08 to $33.07	61	3.5 Years	$32.21

The Company received $1.4 million in cash from the exercise of options during 2012 and a corresponding tax benefit of $363,000 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

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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 then issued as common stock. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants to directors followed the vesting schedule for employees; however, beginning with grants in 2012, the directors’ restricted stock/units vest 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, 2012 (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		361		$	30.66		176		$	32.65
Granted		105			41.34		94			41.34
Dividends		10					5
Forfeited or expired		—			—		—			—
Vested and issued*		(128	)		25.68		(68	)		31.61
Nonvested/unissued at December 31, 2012		348		$	36.03		207		$	37.18

*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 2011 and 2010 was $37.87 and $29.04, respectively.

As of December 31, 2012, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.8 million.

Note 12 – Income Taxes

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is subject to examinations by the Internal Revenue Service for years after 2008, and is subject to examination by the various state taxing authorities for years after 2007.

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):

	2012		2011		2010
Tax-related interest income	$	24	$	100	$	500

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Tax-related interest receivable and payable included in the consolidated balance sheets are shown in the table below (in thousands):

	2012		2011
Tax-related interest receivable (payable)	$	—	$	6

The Company had no uncertain tax liabilities at December 31, 2012, or at any time during 2012. The Company expects no change in unrecognized tax benefits in the next twelve months.

A reconciliation of the beginning and ending amount of unrecognized tax benefits in 2011 is as follows (thousands of dollars):

	2011
Unrecognized tax benefits at beginning of year	$	1,445
Gross increases – tax positions in prior period		—
Gross decreases – tax positions in prior period		—
Gross increases – current period tax positions		—
Gross decreases – current period tax positions		—
Settlements		—
Lapse of statute of limitations		(1,445	)
Unrecognized tax benefits at end of year	$	—

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

Year Ended December 31,	2012		2011			2010
Current:
Federal	$	2,296	$	(265	)	$	4,204
State		5,744		2,122			4,442
		8,040		1,857			8,646
Deferred:
Federal		65,551		58,584			44,778
State		1,685		2,862			1,501
		67,236		61,446			46,279
Total income tax expense	$	75,276	$	63,303		$	54,925

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

Year Ended December 31,	2012			2011			2010
Deferred federal and state:
Property-related items	$	64,249		$	51,710		$	43,420
Purchased gas cost adjustments		1,755			(92	)		(315	)
Employee benefits		564			11,766			8,753
All other deferred		1,529			(1,070	)		(4,711	)
Total deferred federal and state		68,097			62,314			47,147
Deferred ITC, net		(861	)		(868	)		(868	)
Total deferred income tax expense	$	67,236		$	61,446		$	46,279

The consolidated effective income tax rate for the period ended December 31, 2012 and the two prior periods differ from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:

Year Ended December 31,	2012			2011			2010
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.6			2.7			2.8
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		—			(0.9	)		(0.3	)
Tax credits		(0.4	)		(0.6	)		(0.5	)
Company owned life insurance		(1.3	)		(0.1	)		(2.3	)
All other differences		0.1			(0.1	)		(0.2	)
Consolidated effective income tax rate		36.2	%		36.2	%		34.7	%

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

December 31,	2012			2011
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	3,211		$	3,743
Employee benefits		27,097			24,605
Alternative minimum tax credit		18,467			17,411
Net operating losses and credits		36,206			59,096
Interest rate swap		11,164			13,352
Other		17,866			15,099
Valuation allowance		(141	)		(142	)
		113,870			133,164
Deferred tax liabilities:
Property-related items, including accelerated depreciation		652,380			611,022
Regulatory balancing accounts		2,498			743
Property-related items previously flowed through		1,729			2,797
Unamortized ITC		5,131			5,992
Debt-related costs		4,602			4,379
Other		16,626			11,914
		682,966			636,847
Net deferred tax liabilities	$	569,096		$	503,683
Current	$	(47,088	)	$	(53,435	)
Noncurrent		616,184			557,118
Net deferred tax liabilities	$	569,096		$	503,683

At December 31, 2012, the Company has a federal net operating loss carryforward of $103 million and a federal general business credit carryforward of $306,000, both of which expire in 2031. The Company also has a net capital loss carryforward of $320,000, which expires in 2016. The Company also has charitable contribution carryforwards of $892,000 and $743,000, which expire in 2016 and 2017, respectively. On January 2, 2013, the American Taxpayer Relief Act of 2012 (“Taxpayer Relief Act”) was signed into law. The Taxpayer Relief Act extended the availability of the 50% bonus depreciation deduction through 2013. As a result, the Company will not utilize any of the current alternative minimum tax credit in 2013.

Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2013 through March 2015. Under such contracts,

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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, 2012		December 31, 2011
Contract notional amounts		14,579		10,827

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, 2012, 2011, and 2010 and their location in the income statements (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	2012			2011			2010
Swaps	Net cost of gas sold	$	(4,854	)	$	(18,201	)	$	(27,690	)
Swaps	Net cost of gas sold		4,854	*		18,201	*		27,690	*
Total		$	—		$	—		$	—

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

In January 2010, Southwest entered into two FSIRS to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt that matured in February 2011 and $200 million that matured in May 2012. The counterparties to each agreement were four major banking institutions. The first FSIRS was a designated cash flow hedge and terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. The second FSIRS was also a designated cash flow hedge and had a notional amount of $100 million. It terminated in March 2012 concurrent with the related issuance of $250 million 3.875% 10-year Senior Notes. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss was recognized in income (ineffective portion) for either FSIRS during any period, including the periods presented in the following table.

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

	Year Ended December 31, 2012		Year Ended December 31, 2011
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	2,959	$	(17,958	)

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The following table sets forth the fair values of the Company’s Swaps and FSIRS and their location in the balance sheets (thousands of dollars):

Fair values of derivatives not designated as hedging instruments:

December 31, 2012 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	132	$	(126	)	$	6
Swaps	Other current liabilities		391		(2,467	)		(2,076	)
Swaps	Other deferred credits		233		(552	)		(319	)
Total		$	756	$	(3,145	)	$	(2,389	)
December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(11,122	)	$	(11,122	)
Swaps	Other deferred credits		—		(621	)		(621	)
Total		$	—	$	(11,743	)	$	(11,743	)

Fair values of derivatives designated as hedging instruments:

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other current liabilities	$	—	$	(24,713	)	$	(24,713	)

As noted above, the FSIRS that remained at December 31, 2011 terminated in March 2012.

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.

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, 2012		Year ended December 31, 2011		Year ended December 31, 2010
(Thousands of dollars)
Paid to counterparties	$	14,843	$	17,283	$	16,574
Received from counterparties	$	634	$	—	$	831

76

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

December 31, 2012 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(6	)
Swaps	Prepaids and other current assets		2,076
Swaps	Deferred charges and other assets		319

December 31, 2011 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	11,122
Swaps	Deferred charges and other assets		621

Fair Value Measurements.    The estimated fair values of Southwest’s Swaps were determined at December 31, 2012 and 2011 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 estimated fair value of Southwest’s FSIRS at December 31, 2011 was determined using a discounted cash flow model that utilized forward interest rate curves. The inputs to the model were the terms of the FSIRS. These Level 2 inputs were observable in the marketplace throughout the full term of the FSIRS, but were credit-risk adjusted with no significant impact to the overall fair value measure. See Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income (“AOCI”) for more information on the FSIRS.

See Note 10 – Pension and Other Postretirement Benefits for definitions of the levels of the fair value hierarchy. 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:

Level 2 - Significant other observable inputs

	December 31, 2012			December 31, 2011
(Thousands of dollars)
Assets at fair value:
Deferred charges and other assets - Swaps	$	6		$	—
Liabilities at fair value:
Other current liabilities - Swaps		(2,076	)		(11,122	)
Other deferred credits - Swaps		(319	)		(621	)
Other current liabilities - FSIRS		—			(24,713	)
Net Assets (Liabilities)	$	(2,389	)	$	(36,456	)

No financial assets or liabilities accounted for at fair value fell within Level 1 or Level 3 of the fair value hierarchy.

77

Note 14 - Segment Information

Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

The accounting policies of the reported segments are the same as those described within Note 1 – Summary of Significant Accounting Policies. NPL 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, 2012		December 31, 2011
Accounts receivable for NPL services	$	8,179	$	6,205

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, 2012 is as follows (thousands of dollars):

2012	Gas Operations		Construction Services		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

2011	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,403,366	$	391,701	$	1,795,067
Intersegment sales		—		92,121		92,121
Total	$	1,403,366	$	483,822	$	1,887,188
Interest revenue	$	465	$	20	$	485
Interest expense	$	68,777	$	825	$	69,602
Depreciation and amortization	$	175,253	$	25,216	$	200,469
Income tax expense	$	49,576	$	13,727	$	63,303
Segment net income	$	91,420	$	20,867	$	112,287
Segment assets	$	4,048,613	$	227,394	$	4,276,007
Capital expenditures	$	305,542	$	75,449	$	380,991

78

2010	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,511,907	$	257,213	$	1,769,120
Intersegment sales		—		61,251		61,251
Total	$	1,511,907	$	318,464	$	1,830,371
Interest revenue	$	158	$	36	$	194
Interest expense	$	77,025	$	564	$	77,589
Depreciation and amortization	$	170,456	$	20,007	$	190,463
Income tax expense	$	47,073	$	7,852	$	54,925
Segment net income	$	91,382	$	12,495	$	103,877
Segment assets	$	3,845,111	$	139,082	$	3,984,193
Capital expenditures	$	188,379	$	27,060	$	215,439

Note 15 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,919		(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
2011
Operating revenues	$	628,440	$	388,505		$	352,592		$	517,651
Operating income		126,335		20,568			1,253			101,924
Net income (loss)		68,549		4,055			(15,641	)		55,324
Basic earnings (loss) per common share*		1.50		0.09			(0.34	)		1.20
Diluted earnings (loss) per common share*		1.48		0.09			(0.34	)		1.19
2010
Operating revenues	$	668,751	$	385,825		$	307,683		$	468,112
Operating income		121,732		24,031			184			86,170
Net income (loss)		64,648		(933	)		(4,823	)		44,985
Basic earnings (loss) per common share*		1.43		(0.02	)		(0.11	)		0.99
Diluted earnings (loss) per common share*		1.42		(0.02	)		(0.11	)		0.98

* 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.

79

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2012. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 27, 2013

80

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 present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 27, 2013

EX-21.01

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2012

SUBSIDIARY NAME	STATE OF INCORPORATION     OR ORGANIZATION TYPE
Paiute Pipeline Company	Nevada
NPL Construction Co.	Nevada
Southwest Gas Transmission Company	Limited partnership between Southwest Gas Corporation and Utility Financial Corp.
Southwest Gas Capital II, 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 Statements on Form S-3 (No. 333-180045) and Form S-8 (Nos. 333-185354, 333-168731, 333-147952, 333-155581, and 333-106762) of Southwest Gas Corporation of our report dated February 27, 2013 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K.

/s/ PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 27, 2013

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 27, 2013

/S/ JEFFREY W. SHAW

Jeffrey W. Shaw

President and Chief Executive Officer

Southwest Gas Corporation

Certification

I, Roy R. Centrella, certify that:

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

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

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

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

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

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: February 27, 2013

/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, 2012 as filed with the Securities and Exchange Commission (the “Report”), I, Jeffrey W. Shaw, the President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

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

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

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

Dated: February 27, 2013

/s/ Jeffrey W. Shaw

Jeffrey W. Shaw

President and Chief Executive Officer

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2012 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 27, 2013

/s/ Roy R. Centrella

Roy R. Centrella

Senior Vice President/Chief Financial Officer

XML

Summary of Significant Accounting Policies - Schedule of Accumulated Removal Costs (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Accumulated removal costs	$ 256,000	$ 233,000

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2012
Schedule Of Related Tax Effects Allocated To Each Component Of Other Comprehensive Income Loss [Line Items]
Other comprehensive income loss, effective income tax Rate	38.00%

XML

Receivables and Related Allowances - Schedule of Accounts Receivable (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Receivables And Related Allowances [Line Items]
Gas utility customer accounts receivable balance	$ 94,695

XML

Pension and Other Postretirement Benefits - Schedule of Assumptions Used (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.00%
Asset return assumption	8.00%	8.00%

XML

Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Amount of FSIRS existing AOCI losses expected to reclassified income in next 12 months	$ 2.1

XML

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, 2012	Dec. 31, 2011
Commingled equity funds [Member] | Level 3-Significant unobservable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	$ 100,273	$ 97,469
Actual return on plan assets, Relating to assets still held at the reporting date	21,552	(8,442)
Actual return on plan assets, Relating to assets sold during the period	342	246
Purchases	6,800	12,000
Sales	(1,500)	(1,000)
Settlements
Transfers in and/or out of Level 3
Ending balance	$ 127,467	$ 100,273

XML

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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Quarterly Financial Information [Line Items]
Operating revenues	$ 488,566	$ 371,799	$ 409,768	$ 657,645	$ 517,651	$ 352,592	$ 388,505	$ 628,440	$ 468,112	$ 307,683	$ 385,825	$ 668,751	$ 1,927,778	$ 1,887,188	$ 1,830,371
Operating income	115,211	6,310	15,380	134,623	101,924	1,253	20,568	126,335	86,170	184	24,031	121,732	271,524	250,080	232,117
Net income (loss)	$ 62,393	$ (4,305)	$ (3,676)	$ 78,919	$ 55,324	$ (15,641)	$ 4,055	$ 68,549	$ 44,985	$ (4,823)	$ (933)	$ 64,648	$ 133,331	$ 112,287	$ 103,877
Basic earnings (loss) per common share	$ 1.35	$ (0.09)	$ (0.08)	$ 1.71	$ 1.20	$ (0.34)	$ 0.09	$ 1.50	$ 0.99	$ (0.11)	$ (0.02)	$ 1.43	$ 2.89	$ 2.45	$ 2.29
Diluted earnings (loss) per common share	$ 1.34	$ (0.09)	$ (0.08)	$ 1.70	$ 1.19	$ (0.34)	$ 0.09	$ 1.48	$ 0.98	$ (0.11)	$ (0.02)	$ 1.42	$ 2.86	$ 2.43	$ 2.27

XML

Utility Plant - Schedule of Rental Payments for Operating Leases (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Public Utility, Property, Plant and Equipment [Line Items]
Consolidated rental payments/lease expense	$ 31,816	$ 26,829	$ 19,365
Southwest Gas [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Consolidated rental payments/lease expense	7,762	7,812	7,585
NPL services [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Consolidated rental payments/lease expense	$ 24,054	$ 19,017	$ 11,780

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

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):

	2012		2011		2010
Tax-related interest income	$	24	$	100	$	500

Tax-Related Interest Receivable and Payable

Tax-related interest receivable and payable included in the consolidated balance sheets are shown in the table below (in thousands):

	2012		2011
Tax-related interest receivable (payable)	$	—	$	6

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits in 2011 is as follows (thousands of dollars):

	2011
Unrecognized tax benefits at beginning of year	$	1,445
Gross increases – tax positions in prior period		—
Gross decreases – tax positions in prior period		—
Gross increases – current period tax positions		—
Gross decreases – current period tax positions		—
Settlements		—
Lapse of statute of limitations		(1,445	)
Unrecognized tax benefits at end of year	$	—

Summary of Income Tax Expense (Benefit)

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

Year Ended December 31,	2012		2011			2010
Current:
Federal	$	2,296	$	(265	)	$	4,204
State		5,744		2,122			4,442
		8,040		1,857			8,646
Deferred:
Federal		65,551		58,584			44,778
State		1,685		2,862			1,501
		67,236		61,446			46,279
Total income tax expense	$	75,276	$	63,303		$	54,925

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,	2012			2011			2010
Deferred federal and state:
Property-related items	$	64,249		$	51,710		$	43,420
Purchased gas cost adjustments		1,755			(92	)		(315	)
Employee benefits		564			11,766			8,753
All other deferred		1,529			(1,070	)		(4,711	)
Total deferred federal and state		68,097			62,314			47,147
Deferred ITC, net		(861	)		(868	)		(868	)
Total deferred income tax expense	$	67,236		$	61,446		$	46,279

Consolidated Effective Income Tax Rate

The sources of these differences and the effect of each are summarized as follows:

Year Ended December 31,	2012			2011			2010
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.6			2.7			2.8
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		—			(0.9	)		(0.3	)
Tax credits		(0.4	)		(0.6	)		(0.5	)
Company owned life insurance		(1.3	)		(0.1	)		(2.3	)
All other differences		0.1			(0.1	)		(0.2	)
Consolidated effective income tax rate		36.2	%		36.2	%		34.7	%

Deferred Tax Assets and Liabilities

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

December 31,	2012			2011
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	3,211		$	3,743
Employee benefits		27,097			24,605
Alternative minimum tax credit		18,467			17,411
Net operating losses and credits		36,206			59,096
Interest rate swap		11,164			13,352
Other		17,866			15,099
Valuation allowance		(141	)		(142	)
		113,870			133,164
Deferred tax liabilities:
Property-related items, including accelerated depreciation		652,380			611,022
Regulatory balancing accounts		2,498			743
Property-related items previously flowed through		1,729			2,797
Unamortized ITC		5,131			5,992
Debt-related costs		4,602			4,379
Other		16,626			11,914
		682,966			636,847
Net deferred tax liabilities	$	569,096		$	503,683
Current	$	(47,088	)	$	(53,435	)
Noncurrent		616,184			557,118
Net deferred tax liabilities	$	569,096		$	503,683

XML

Stock-Based Compensation - Schedule of Stock-Based Compensation Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense, net of related tax benefits	$ 7,396	$ 7,262	$ 5,874
Stock-based compensation related tax benefits	$ 4,533	$ 4,451	$ 3,600

XML

Pension and Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	$ 33.2
2014	34.9
2015	36.7
2016	38.5
2017	40.6
2018-2022	234.4
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	2.6
2014	2.8
2015	3.0
2016	3.2
2017	3.3
2018-2022	17.4
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	2.5
2014	2.5
2015	2.5
2016	2.5
2017	2.5
2018-2022	$ 12.0

XML

Income Taxes - Summary of Income Tax Expense (Benefit) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Federal	$ 2,296	$ (265)	$ 4,204
State	5,744	2,122	4,442
Income tax expense (benefit), current	8,040	1,857	8,646
Federal	65,551	58,584	44,778
State	1,685	2,862	1,501
Total deferred income tax expense	67,236	61,446	46,279
Total income tax expense	$ 75,276	$ 63,303	$ 54,925

XML

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, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Stockholders Equity [Line Items]
Beginning Balance AOCI December 31, 2011, Defined Benefit Plans Before-Tax	$ (44,429)
Ending Balance AOCI December 31, 2012, Defined Benefit Plans - Before Tax	(52,470)	(44,429)
Beginning Balance AOCI December 31, 2011, Defined Benefit Plans - Tax (Expense) Benefit	16,883
Ending Balance AOCI December 31, 2012, Defined Benefit Plans - Tax (Expense) Benefit	19,939	16,883
Beginning Balance AOCI December 31, 2011, Defined Benefit Plans - After-Tax	(27,546)
Ending Balance AOCI December 31, 2012, Defined Benefit Plans - After Tax	(32,531)	(27,546)
Beginning Balance AOCI December 31, 2011, FSIRS - Before-Tax	(35,138)
Ending Balance AOCI December 31, 2012, FSIRS - Before-Tax	(29,378)	(35,138)
Beginning Balance AOCI December 31, 2011, FSIRS - Tax (Expense) Benefit	13,353
Ending Balance AOCI December 31, 2012, FSIRS - Tax (Expense) Benefit	11,164	13,353
Beginning Balance AOCI December 31, 2011, FSIRS - After-Tax	(21,785)
Ending Balance AOCI December 31, 2012, FSIRS - After-Tax	(18,214)	(21,785)
Beginning Balance AOCI December 31,2011	(49,331)
Ending Balance AOCI December 31, 2012	(50,745)	(49,331)
Current period other comprehensive income (loss), Defined Benefit Plans - Before-Tax	(8,041)
Current period other comprehensive income (loss), Defined Benefit Plans - Tax (Expense) Benefit	3,056
Current period other comprehensive income (loss), Defined Benefit Plans - After-Tax	(4,985)	(8,138)	2,842
Current period other comprehensive income (loss), FSIRS - Before-Tax	5,760	(16,789)	(18,349)
Current period other comprehensive income (loss), FSIRS - Tax (Expense) Benefit	(2,189)
Net forward-starting interest rate swaps	3,571	(10,409)	(11,376)
Current period other comprehensive income (loss), AOCI	$ (1,414)

XML

Pension and Other Postretirement Benefits - Schedule of Changes in Fair Value of Plan Assets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, including investment contracts	$ 647,760	$ 552,701
Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	643,134	547,749
Insurance company general account contracts (Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,626	4,952
Level 1-Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	377,294	317,209
Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		21
Level 1-Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,616	4,465
Level 1-Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,945	7,652
Level 1-Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	50,739	42,055
Level 1-Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,649	40,276
Level 1-Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29,735	24,537
Level 1-Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,512	26,868
Level 1-Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,459	29,941
Level 1-Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26,083	17,950
Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	25,093	16,755
Level 1-Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,913	23,161
Level 1-Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,771	5,956
Level 1-Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85,551	71,666
Level 1-Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,228	5,902
Level 1-Quoted prices in active markets for identical financial assets [Member] | Futures contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4
Level 2-Significant other observable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	138,373	130,267
Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	654
Level 2-Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,299	43,658
Level 2-Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17,141	17,488
Level 2-Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18,510	16,688
Level 2-Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,231	5,219
Level 2-Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29,801	26,558
Level 2-Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22,425	19,691
Level 2-Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,312	965
Level 3-Significant unobservable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	127,467	100,273
Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	127,467	100,273
Qualified retirement plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, including investment contracts	612,436	522,747
Qualified retirement plan [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	607,810	517,795
Qualified retirement plan [Member] | Insurance company general account contracts (Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,626	4,952
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	350,915	295,762
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		20
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,510	4,332
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,741	7,425
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	49,247	40,806
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39,454	39,080
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28,861	23,808
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	29,615	26,070
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,534	29,052
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	25,316	17,417
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24,355	16,257
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,298	22,473
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,572	5,779
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	67,749	57,512
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18,663	5,727
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Futures contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	133,176	124,738
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	635
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	42,997	42,361
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16,637	16,969
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17,966	16,192
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,107	5,064
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28,925	25,769
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,636	17,447
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,273	936
Qualified retirement plan [Member] | Level 3-Significant unobservable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	123,719	97,295
Qualified retirement plan [Member] | Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	123,719	97,295
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, including investment contracts	35,324	29,954
PBOP [Member] | Derivative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,324	29,954
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	26,379	21,447
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Capital equipment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	106	133
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Chemicals/materials [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	204	227
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Consumer goods [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,492	1,249
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Energy and mining [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,195	1,196
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Finance/insurance [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	874	729
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Healthcare [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	897	798
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Information technology [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	925	889
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Services [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	767	533
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	738	498
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	615	688
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Real estate investment trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	199	177
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17,802	14,154
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Government fixed Income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	565	175
PBOP [Member] | Level 2-Significant other observable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,197	5,529
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Government fixed income and mortgage backed securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,302	1,297
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	504	519
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Banking [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	544	496
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Utilities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	124	155
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	876	789
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,789	2,244
PBOP [Member] | Level 2-Significant other observable inputs [Member] | State and local obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	39	29
PBOP [Member] | Level 3-Significant unobservable inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,748	2,978
PBOP [Member] | Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 3,748	$ 2,978

XML

Income Taxes - Summary of Tax-Related Interest Income (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Tax-related interest income	$ 24	$ 100	$ 500

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, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding number of options, Beginning balance	177	369	651
Number of options, Exercised during the year	(52)	(192)	(273)
Number of options, Forfeited or expired during the year			(9)
Outstanding number of options, Ending balance	125	177	369
Weighted-average exercise price, Beginning balance	$ 27.28	$ 28.04	$ 27.49
Weighted-average exercise price, Exercised during the year	$ 25.25	$ 28.75	$ 26.67
Weighted-average exercise price, Forfeited or expired during the year			$ 29.51
Weighted-average exercise price, Ending balance	$ 28.13	$ 27.28	$ 28.04

XML

Income Taxes - Tax-Related Interest Receivable and Payable (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]
Tax-related interest receivable (payable)		$ 6

XML

Pension and Other Postretirement Benefits - Schedule of Changes in Fair Value of Plan Assets (Parenthetical) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	$ 2,760,000	$ 928,000
Qualified retirement plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	2,685,000	918,000
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Amounts not included in funded status table	$ 75,000	$ 10,000

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, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain)	$ 74,853	$ 135,492	$ 9,058
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.00%
Qualified retirement plan [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	780,571	662,134
Service cost	20,319	17,725	16,932
Interest cost	38,266	37,276	35,614
Benefit obligation at end of year (PBO/PBO/APBO)	902,812	780,571	662,134
Beginning balance	521,829	475,931
Actual return on plan assets	68,174	2,384
Employer contributions	48,500	70,000
Ending balance	609,750	521,829	475,931
Funded status at year end	(293,062)	(258,742)
Qualified retirement plan [Member] | Change in benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain)	92,409	89,922
Benefits paid	(28,753)	(26,486)
Qualified retirement plan [Member] | Change in plan assets [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefits paid	(28,753)	(26,486)
Qualified retirement plan [Member] | Benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.00%
SERP [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	33,827	31,860
Service cost	274	217	372
Interest cost	1,629	1,766	2,045
Benefit obligation at end of year (PBO/PBO/APBO)	37,373	33,827	31,860
Employer contributions	2,468	2,443
Funded status at year end	(37,373)	(33,827)
SERP [Member] | Change in benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain)	4,111	2,427
Benefits paid	(2,468)	(2,443)
SERP [Member] | Change in plan assets [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefits paid	(2,468)	(2,443)
SERP [Member] | Benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.00%
PBOP [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	52,182	46,765
Service cost	977	858	856
Interest cost	2,547	2,631	2,491
Plan amendments	2,423
Benefit obligation at end of year (PBO/PBO/APBO)	59,704	52,182	46,765
Beginning balance	29,944	29,640
Actual return on plan assets	4,454	(200)
Employer contributions	1,256	904
Ending balance	35,250	29,944	29,640
Funded status at year end	(24,454)	(22,238)
PBOP [Member] | Change in benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain)	2,775	2,835
Benefits paid	(1,200)	(907)
PBOP [Member] | Change in plan assets [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Benefits paid	$ (404)	$ (400)
PBOP [Member] | Benefit obligation [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Discount rate	4.25%	5.00%
Weighted-average rate of compensation increase	2.75%	3.00%

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Other Property and Investments

Other property and investments includes (millions of dollars):

	2012			2011
NPL property and equipment	$	287		$	237
Accumulated provision for depreciation and amortization		(136	)		(128	)
Net cash surrender value of COLI policies		80			74
Other property		11			9
Total	$	242		$	192

Schedule of Accumulated Removal Costs

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

	December 31, 2012		December 31, 2011
Accumulated removal costs	$	256,000	$	233,000

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.

	2012		2011		2010
(In thousands)
AFUDC:
Debt portion	$	1,129	$	718	$	512
Equity portion		1,943		1,154		945
AFUDC capitalized as part of utility plant	$	3,072	$	1,872	$	1,457

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):

	2012			2011			2010
Change in COLI policies	$	6,600		$	700		$	9,770
Interest income		924			485			194
Pipe replacement costs		(2,680	)		(4,761	)		(5,024	)
Miscellaneous income and (expense)		(433	)		(1,836	)		(1,090	)
Total other income (deductions)	$	4,411		$	(5,412	)	$	3,850

Schedule of Earnings Per Share, Basic and Diluted

Net income was the same for Basic and Diluted EPS calculations.

	2012		2011		2010
(In thousands)
Average basic shares		46,115		45,858		45,405
Effect of dilutive securities:
Stock options		42		52		56
Performance shares		254		271		260
Restricted stock units		144		110		102
Average diluted shares		46,555		46,291		45,823

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Receivables and Related Allowances - Schedule of Allowance for Uncollectibles (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Beginning Balance	$ 3,182	$ 3,194	$ 3,953
Additions charged to expense	2,471	2,678	2,646
Accounts written off, less recoveries	(3,149)	(2,690)	(3,405)
Ending Balance	$ 2,504	$ 3,182	$ 3,194

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Average basic shares	46,115	45,858	45,405
Stock options	42	52	56
Performance shares	254	271	260
Restricted stock units	144	110	102
Average diluted shares	46,555	46,291	45,823

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 74,853	$ 135,492	$ 9,058
Amortization of transition obligation	(867)	(867)	(867)
Amortization of net actuarial loss	(25,597)	(15,569)	(12,122)
Prior service cost	2,423
Regulatory adjustment	(42,771)	(105,931)	(652)
Recognized in other comprehensive (income) loss	8,041	13,125	(4,583)
Net periodic benefit costs recognized in net income	42,292	34,416	32,668
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	50,333	47,541	28,085
Qualified retirement plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	70,016	127,651	10,994
Amortization of net actuarial loss	(23,883)	(14,348)	(10,478)
Regulatory adjustment	(41,520)	(101,974)	(464)
Recognized in other comprehensive (income) loss	4,613	11,329	52
Net periodic benefit costs recognized in net income	36,688	29,235	26,486
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	41,301	40,564	26,538
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	4,111	2,427	(3,480)
Amortization of net actuarial loss	(683)	(631)	(1,155)
Recognized in other comprehensive (income) loss	3,428	1,796	(4,635)
Net periodic benefit costs recognized in net income	2,586	2,614	3,572
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	6,014	4,410	(1,063)
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	726	5,414	1,544
Amortization of transition obligation	(867)	(867)	(867)
Amortization of net actuarial loss	(1,031)	(590)	(489)
Prior service cost	2,423
Regulatory adjustment	(1,251)	(3,957)	(188)
Net periodic benefit costs recognized in net income	3,018	2,567	2,610
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$ 3,018	$ 2,567	$ 2,610

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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, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$ 2,959	$ (17,958)

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011
NPL ownership in ICE percentage	65.00%	65.00%	65.00%
Prepaids and other current assets	$ 107,910,000	$ 107,910,000	$ 107,910,000	$ 96,598,000
Customer advances applied as contributions offsetting construction expenditures	20,000,000	20,000,000	20,000,000
Recognized pretax losses, after tax earnings per share impacts		$ 0.24	$ 0.20
NPL Construction Co [Member]
Recognized pretax profit/losses		18,000,000	15,000,000	5,000,000
Percentage of contract completion	95.00%
Recognized cumulative pretax losses on contract to date basis	10,000,000
Plant materials and operating supplies [Member]
Prepaids and other current assets	$ 25,000,000	$ 25,000,000	$ 25,000,000	$ 21,000,000

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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, 2012	Dec. 31, 2011
Deferred charges and other assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	$ 319	$ 621
Prepaids and other current assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	2,076	11,122
Other deferred credits [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets and liabilities offsetting derivatives at fair value	$ (6)

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Pension and Other Postretirement Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 Y BasisPoint
Pension Plans, Postretirement and Other Employee Benefits [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
Deferred compensation, percentage of multiple interest rate	150.00%
Increments of changes to the discount rate, basis points	25
Estimated increase in pension expense	$ 6.4
Future estimated funding amount	49
Future estimated funding amount of retirement plan	46
Minimum [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	5.00%
Minimum [Member] | Commingled Funds Equities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Redemption notice period	1
Payment of impact fee to be applied on redemptions and subscriptions	$ 5
Maximum [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Per capita cost of covered health care benefits medical rate trend assumption	7.50%
Maximum [Member] | Commingled Funds Equities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Redemption notice period	30

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Long-Term Debt - Schedule of Estimated Fair Values of Long-Term Debt (Parenthetical) (Detail)				12 Months Ended
	Jan. 31, 2012 6.10% 1999 Series A, due 2038 [Member]	Dec. 31, 2012 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]	Dec. 31, 2012 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]	Dec. 31, 2012 Debentures [Member] Notes, 7.625%, due 2012 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Notes, 7.625%, due 2012 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Notes, 7.625%, due 2012 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Notes, 7.625%, due 2012 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Notes, 4.45%, due 2020 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Notes, 4.45%, due 2020 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Notes, 4.45%, due 2020 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Notes, 4.45%, due 2020 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Notes, 6.1%, due 2041[Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Notes, 6.1%, due 2041[Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Notes, 6.1%, due 2041[Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Notes, 6.1%, due 2041[Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Notes, 3.875%, due 2022 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Notes, 3.875%, due 2022 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Notes, 3.875%, due 2022 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Notes, 3.875%, due 2022 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] 8% Series, due 2026 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] 8% Series, due 2026 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] 8% Series, due 2026 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] 8% Series, due 2026 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.59% Series, due 2017 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.59% Series, due 2017 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.59% Series, due 2017 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.59% Series, due 2017 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.78% Series, Due 2022 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.78% Series, Due 2022 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.78% Series, Due 2022 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.78% Series, Due 2022 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.92% Series, Due 2027 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.92% Series, Due 2027 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 7.92% Series, Due 2027 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 7.92% Series, Due 2027 [Member] Market Value [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 6.76% Series, Due 2027 [Member] Carrying Amount [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 6.76% Series, Due 2027 [Member] Carrying Amount [Member]	Dec. 31, 2012 Debentures [Member] Medium-term notes, 6.76% Series, Due 2027 [Member] Market Value [Member]	Dec. 31, 2011 Debentures [Member] Medium-term notes, 6.76% Series, Due 2027 [Member] Market Value [Member]	Dec. 31, 2012 Variable-rate bonds [Member] Tax-exempt Series A, Due 2028 [Member] Carrying Amount [Member]	Dec. 31, 2011 Variable-rate bonds [Member] Tax-exempt Series A, Due 2028 [Member] Carrying Amount [Member]	Dec. 31, 2012 Variable-rate bonds [Member] Tax-exempt Series A, Due 2028 [Member] Market Value [Member]	Dec. 31, 2011 Variable-rate bonds [Member] Tax-exempt Series A, Due 2028 [Member] Market Value [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2003 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2003 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2003 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2003 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2008 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2008 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2008 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2008 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2009 Series A, due 2039 [Member] Carrying Amount [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2009 Series A, due 2039 [Member] Carrying Amount [Member]	Dec. 31, 2012 Variable-rate bonds [Member] 2009 Series A, due 2039 [Member] Market Value [Member]	Dec. 31, 2011 Variable-rate bonds [Member] 2009 Series A, due 2039 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 6.10% 1999 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 6.10% 1999 Series A, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 6.10% 1999 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 6.10% 1999 Series A, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.95% 1999 Series C, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.95% 1999 Series C, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.95% 1999 Series C, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.95% 1999 Series C, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.55% 1999 Series D, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.55% 1999 Series D, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.55% 1999 Series D, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.55% 1999 Series D, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.25% 2003 Series D, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.25% 2003 Series D, due 2038 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.25% 2003 Series D, due 2038 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.25% 2003 Series D, due 2038 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.25% 2004 Series A, due 2034 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.25% 2004 Series A, due 2034 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.25% 2004 Series A, due 2034 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.25% 2004 Series A, due 2034 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.00% 2004 Series B, due 2033 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.00% 2004 Series B, due 2033 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 5.00% 2004 Series B, due 2033 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 5.00% 2004 Series B, due 2033 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 4.85% 2005 Series A, due 2035 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 4.85% 2005 Series A, due 2035 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 4.85% 2005 Series A, due 2035 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 4.85% 2005 Series A, due 2035 [Member] Market Value [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 4.75% 2006 Series A, due 2036 [Member] Carrying Amount [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 4.75% 2006 Series A, due 2036 [Member] Carrying Amount [Member]	Dec. 31, 2012 Fixed-rate bonds [Member] 4.75% 2006 Series A, due 2036 [Member] Market Value [Member]	Dec. 31, 2011 Fixed-rate bonds [Member] 4.75% 2006 Series A, due 2036 [Member] Market Value [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	6.10%	5.45%	5.80%	7.625%	7.625%	7.625%	7.625%	4.45%	4.45%	4.45%	4.45%	6.10%	6.10%	6.10%	6.10%	3.875%	3.875%	3.875%	3.875%	8.00%	8.00%	8.00%	8.00%	7.59%	7.59%	7.59%	7.59%	7.78%	7.78%	7.78%	7.78%	7.92%	7.92%	7.92%	7.92%	6.76%	6.76%	6.76%	6.76%																	6.10%	6.10%	6.10%	6.10%	5.95%	5.95%	5.95%	5.95%	5.55%	5.55%	5.55%	5.55%	5.45%	5.45%	5.45%	5.45%	5.25%	5.25%	5.25%	5.25%	5.80%	5.80%	5.80%	5.80%	5.25%	5.25%	5.25%	5.25%	5.00%	5.00%	5.00%	5.00%	4.85%	4.85%	4.85%	4.85%	4.75%	4.75%	4.75%	4.75%
Debt instrument due date				2012	2012	2012	2012	2020	2020	2020	2020	2041	2041	2041	2041	2022	2022	2022	2022	2026	2026	2026	2026	2017	2017	2017	2017	2022	2022	2022	2022	2027	2027	2027	2027	2027	2027	2027	2027	2028	2028	2028	2028	2038	2038	2038	2038	2038	2038	2038	2038	2039	2039	2039	2039	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2038	2034	2034	2034	2034	2033	2033	2033	2033	2035	2035	2035	2035	2036	2036	2036	2036
Debt instrument rate reset																																																																				March 2,013	March 2,013	March 2,013	March 2,013					March 2,013	March 2,013	March 2,013	March 2,013

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Utility Plant - Schedule of Future Minimum Lease Payments for Operating Leases (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
2013	$ 6,757
2014	4,304
2015	3,181
2016	2,510
2017	1,238
Thereafter	61
Total minimum lease payments	$ 18,051

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

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. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

Basis of Presentation.    The Company follows generally accepted accounting principles in the United States (“U.S. GAAP”) in accounting for all of its businesses. 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. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities.

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):

	2012			2011
NPL property and equipment	$	287		$	237
Accumulated provision for depreciation and amortization		(136	)		(128	)
Net cash surrender value of COLI policies		80			74
Other property		11			9
Total	$	242		$	192

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 plant materials and operating supplies of $25 million in 2012 and $21 million in 2011.

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.

Cash and Cash Equivalents.    For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. Cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. During 2012, approximately $20 million of customer advances, upon contract expiration, were applied as contributions offsetting construction expenditures as a non-cash investing activity.

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, 2012		December 31, 2011
Accumulated removal costs	$	256,000	$	233,000

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 NPL contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two 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 the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps, that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.

In 2011, NPL recorded $5 million in estimated pretax profit associated with a large fixed-price contract. In connection with significant changes in estimated costs to complete the fixed-price contract, NPL results reflect pretax losses (with after-tax earnings per share impacts) of $15 million ($0.20 per share) for the year ended December 31, 2012, including $18 million ($0.24 per share) in the first half of 2012. The estimated cost changes that resulted in the losses recognized included reductions in projected productivity and higher costs of restoration work. Change orders approved during the fourth quarter of 2012 helped to reduce losses overall on the contract. On a contract-to-date basis the cumulative loss is $10 million. At December 31, 2012, work on this sizeable contract is over 95% complete.

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, and office-related fixed costs of NPL.

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.

	2012		2011		2010
(In thousands)
AFUDC:
Debt portion	$	1,129	$	718	$	512
Equity portion		1,943		1,154		945
AFUDC capitalized as part of utility plant	$	3,072	$	1,872	$	1,457

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):

	2012			2011			2010
Change in COLI policies	$	6,600		$	700		$	9,770
Interest income		924			485			194
Pipe replacement costs		(2,680	)		(4,761	)		(5,024	)
Miscellaneous income and (expense)		(433	)		(1,836	)		(1,090	)
Total other income (deductions)	$	4,411		$	(5,412	)	$	3,850

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, is 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 completed in 2012.

Earnings Per Share.    Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of 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 shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.

	2012		2011		2010
(In thousands)
Average basic shares		46,115		45,858		45,405
Effect of dilutive securities:
Stock options		42		52		56
Performance shares		254		271		260
Restricted stock units		144		110		102
Average diluted shares		46,555		46,291		45,823

Recently Issued Accounting Standards Updates.    In October 2012, the Financial Accounting Standards Board (“FASB”) issued the update “Technical Corrections and Improvements” which clarifies or corrects unintended application of accounting guidance. Many of these changes are not expected to have a significant effect on current accounting practice but some improvements are more substantive and are not technical corrections. Amendments included in the update without transition guidance were effective upon issuance. Amendments subject to transition guidance were effective for the Company on January 1, 2013 for interim and annual reporting periods. The adoption of the update is not expected to have a material impact on the Company’s disclosures, financial position, or results of operations.

In July 2012, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment,” which provides that an entity has the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that an indefinite-lived intangible asset is impaired. If, in electing the qualitative evaluation step, there is no indication of impairment, quantitative impairment testing would not be required to be performed. The update would provide consistency in evaluation for goodwill and indefinite-lived intangibles other than goodwill. The Company adopted this update, as required, on January 1, 2013. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.

In December 2011, the FASB issued the update “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entity’s financial statements to understand the effect of those arrangements on the entity’s financial position. In January 2013, the FASB issued the update “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“Clarification”) that clarifies the scope of the “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” update. The amendments included in the Clarification apply to entities that have derivatives, repurchase agreements and reverse repurchase agreements, and certain securities borrowing and securities lending transactions that are offset, or subject to a master netting or similar agreement. Entities with other types of financial assets and financial liabilities subject to a master netting or similar agreements would no longer be subject to the disclosure requirements in the initial update. All disclosures are required to be provided retrospectively for all periods presented. The Company adopted both updates, as required, on January 1, 2013 for interim and annual reporting periods. These updates are 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.

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Long-Term Debt - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended			12 Months Ended		12 Months Ended			12 Months Ended				1 Months Ended			12 Months Ended					12 Months Ended
	Nov. 30, 2012	Dec. 31, 2012	Dec. 31, 2012 Short-term credit facility [Member]	Dec. 31, 2011 Short-term credit facility [Member]	Dec. 31, 2012 Revolving credit facility expire in June 2013 [Member]	Jun. 30, 2012 Revolving credit facility expire in June 2013 [Member]	Dec. 31, 2012 Revolving credit facility expire in June 2015 [Member]	Jun. 30, 2012 Revolving credit facility expire in June 2015 [Member] Minimum [Member]	Jun. 30, 2012 Revolving credit facility expire in June 2015 [Member] Maximum [Member]	Dec. 31, 2012 May 2012 [Member]	Dec. 31, 2012 March 2017 [Member]	Dec. 31, 2012 LIBOR [Member] Southwest Gas Credit Facility [Member]	Dec. 31, 2012 Alternative base rate [Member] Southwest Gas Credit Facility [Member]	Dec. 31, 2012 Three Point Eight Seven Five Percent Senior Unsecured Notes Due In Two Thousand And Twenty Two [Member]	Dec. 31, 2012 Seven Point Six Two Five Percentage Senior Notes Due Two Thousand Twelve [Member]	Jan. 31, 2012 6.10% 1999 Series A, due 2038 [Member]	Dec. 31, 2012 Commercial paper program [Member]	Nov. 30, 2012 Commercial paper program [Member]	Dec. 31, 2012 IDRBs [Member]	Dec. 31, 2012 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]	Dec. 31, 2012 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]	Dec. 31, 2012 NPL credit facility [Member]	Jun. 30, 2012 NPL credit facility [Member]
Debt Instrument [Line Items]
Senior notes																$ 12,400,000
Debt instrument interest rate														3.875%	7.625%	6.10%				5.45%	5.80%
Senior Notes issued														250,000,000
Senior Notes issued maturity date														April 1, 2022	May 2012
Senior debt repayment															200,000,000
Discount on issuance of debt														0.034%
Credit facility maximum borrowing capacity		300,000,000				30,000,000		75,000,000	85,000,000	300,000,000	300,000,000							50,000,000
Credit facility expiration date		May 01, 2012			Jun. 01, 2013		Jun. 01, 2015			May 01, 2012	Mar. 01, 2017
Applicable margin												1.125%	0.125%
Line of credit designated as long term debt		150,000,000
Line of credit designated for working capital purposes		150,000,000
Credit facility outstanding		91,000,000	0	0													20,000,000					41,600,000
Current borrowing capacity		0
Maximum current borrowing usage	130,000,000
Credit facility interest rate		1.43%
Effective interest rate																	0.84%					0.97%
IDRBs to be redeemed																			45,000,000
Interest rate of LIBOR																							1.00%
Interest rate of base																							0.75%
Issuance of additional debt		1,700,000,000
Minimum net worth		$ 700,000,000

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Utility Plant - Schedule of Net Utility Plant (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 5,019,500	$ 4,811,050
Less: accumulated depreciation	(1,750,795)	(1,638,091)
Acquisition adjustments, net	911	1,091
Construction work in progress	74,178	44,894
Net utility plant	3,343,794	3,218,944
Storage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	20,503	20,496
Transmission [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	301,505	295,103
Distribution [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	4,224,560	4,048,078
General [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	310,936	291,639
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Gas plant	$ 161,996	$ 155,734

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

12 Months Ended

Dec. 31, 2012

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

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

	2012									2011									2010
	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)	$	(74,853	)	$	28,444		$	(46,409	)	$	(135,492	)	$	51,487		$	(84,005	)	$	(9,058	)	$	3,442		$	(5,616	)
Amortization of transition obligation		867			(329	)		538			867			(330	)		537			867			(329	)		538
Amortization of net actuarial (gain)/loss		25,597			(9,727	)		15,870			15,569			(5,916	)		9,653			12,122			(4,606	)		7,516
Prior service cost		(2,423	)		921			(1,502	)		—			—			—			—			—			—
Regulatory adjustment		42,771			(16,253	)		26,518			105,931			(40,254	)		65,677			652			(248	)		404
Pension plans other comprehensive income (loss)		(8,041	)		3,056			(4,985	)		(13,125	)		4,987			(8,138	)		4,583			(1,741	)		2,842
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		2,959			(1,125	)		1,834			(17,958	)		6,824			(11,134	)		(18,446	)		7,010			(11,436	)
Amounts reclassified into net income		2,801			(1,064	)		1,737			1,169			(444	)		725			97			(37	)		60
FSIRS other comprehensive income (loss)		5,760			(2,189	)		3,571			(16,789	)		6,380			(10,409	)		(18,349	)		6,973			(11,376	)
Total other comprehensive income (loss)	$	(2,281	)	$	867		$	(1,414	)	$	(29,914	)	$	11,367		$	(18,547	)	$	(13,766	)	$	5,232		$	(8,534	)

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

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	$	32,400
SERP net actuarial loss		1,000
PBOP net actuarial loss		1,000
PBOP prior service cost		400

Rollforward of Accumulated Other Comprehensive Income

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

AOCI – Rollforward

(Thousands of dollars)

	Defined Benefit Plans (Note 10)								FSIRS (Note 13)
	Before- Tax			Tax (Expense) Benefit		After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			AOCI
Beginning Balance AOCI December 31, 2011	$	(44,429	)	$	16,883	$	(27,546	)	$	(35,138	)	$	13,353		$	(21,785	)	$	(49,331	)
Current period other comprehensive income (loss)		(8,041	)		3,056		(4,985	)		5,760			(2,189	)		3,571			(1,414	)
Ending Balance AOCI December 31, 2012	$	(52,470	)	$	19,939	$	(32,531	)	$	(29,378	)	$	11,164		$	(18,214	)	$	(50,745	)

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, 2012 and 2011:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2012			2011
Net actuarial (loss) gain	$	(423,662	)	$	(374,406	)
Prior service cost		(2,423	)		—
Net transition obligation		—			(867	)
Less: amount recognized in regulatory assets		373,615			330,844
Recognized in AOCI	$	(52,470	)	$	(44,429	)

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Regulatory Assets and Liabilities

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

December 31,	2012			2011
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	373,615		$	330,844
Unrealized net loss on non-trading derivatives (Swaps) (2)		2,395			11,743
Deferred purchased gas costs (3)		6,031			2,323
Accrued purchased gas costs (4)		30,300			18,400
Unamortized premium on reacquired debt (5)		19,452			19,011
Other (6)		44,927			32,988
		476,720			415,309
Regulatory liabilities:
Deferred purchased gas costs (3)		(98,957	)		(72,426	)
Accumulated removal costs		(256,000	)		(233,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		(6	)		—
Deferred gain on southern Nevada division operations facility (7)		(392	)		(806	)
Unamortized gain on reacquired debt (8)		(11,934	)		(12,470	)
Other (9)		(6,951	)		(14,501	)
Net regulatory assets	$	102,480		$	82,106

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

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

Instrument	Balance Sheet Location	2012			2011
Swaps	Deferred charges and other assets	$	319		$	621
Swaps	Prepaids and other current assets		2,076			11,122
Swaps	Other deferred credits		(6	)		—

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

(4) Included in Prepaids and other current assets on the Consolidated Balance Sheets and recovered over one year or less.

(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 Decision, the amortization period was extended through 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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Derivatives and Fair Value Measurements - Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Balance Sheet (Detail) (Swaps [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ (6)
Prepaids and other current assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	2,076	11,122
Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ 319	$ 621

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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, 2012
Qualified Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	$ 32,400
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	1,000
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Retirement plan net actuarial loss	1,000
PBOP prior service cost	$ 400

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Utility Plant - Schedule of Depreciation and Amortization Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 223,422	$ 200,469	$ 190,463
Gas plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization expense	$ 182,612	$ 172,712	$ 167,050

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Estimated Fair Values of Long-Term Debt

The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

December 31,	2012					2011
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 7.625%, due 2012	$	—		$	—	$	200,000		$	204,312
Notes, 4.45%, due 2020		125,000			141,771		125,000			128,673
Notes, 6.1%, due 2041		125,000			165,779		125,000			143,074
Notes, 3.875%, due 2022		250,000			277,950		—			—
8% Series, due 2026		75,000			111,501		75,000			96,340
Medium-term notes, 7.59% series, due 2017		25,000			30,710		25,000			30,199
Medium-term notes, 7.78% series, due 2022		25,000			34,637		25,000			31,932
Medium-term notes, 7.92% series, due 2027		25,000			36,953		25,000			31,648
Medium-term notes, 6.76% series, due 2027		7,500			10,058		7,500			8,510
Unamortized discount		(3,403	)				(2,087	)
		654,097					605,413
Revolving credit facility and commercial paper		111,000			111,000		109,000			109,000
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:
6.10% 1999 Series A, due 2038		—			—		12,410			12,410
5.95% 1999 Series C, due 2038		—			—		14,320			14,449
5.55% 1999 Series D, due 2038		8,270			8,375		8,270			8,253
5.45% 2003 Series C, due 2038 (rate resets in March 2013)		30,000			30,152		30,000			31,332
5.25% 2003 Series D, due 2038		20,000			20,571		20,000			19,583
5.80% 2003 Series E, due 2038 (rate resets in March 2013)		15,000			15,102		15,000			15,634
5.25% 2004 Series A, due 2034		65,000			66,955		65,000			64,291
5.00% 2004 Series B, due 2033		31,200			31,655		31,200			30,283
4.85% 2005 Series A, due 2035		100,000			101,184		100,000			94,836
4.75% 2006 Series A, due 2036		24,855			25,189		24,855			23,179
Unamortized discount		(3,195	)				(3,360	)
		491,130					517,695
NPL credit facility		41,562			41,562		16,566			16,566
NPL other debt obligations		20,721			20,991		4,802			4,814
		1,318,510					1,253,476
Less: current maturities		(50,137	)				(322,618	)
Long-term debt, less current maturities	$	1,268,373				$	930,858

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, 2012			December 31, 2011
2003 Series A		1.71	%		0.83	%
2008 Series A		1.59	%		1.62	%
2009 Series A		1.14	%		1.56	%
Tax-exempt Series A		1.25	%		2.22	%

Estimated Maturities of Long-Term Debt

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

2013	$	50,137
2014		5,249
2015		46,705
2016		4,143
2017		137,049

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Pension and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Cost of Retirement Plan

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

	2012		2011		2010
Employee Investment Plan cost	$	4,707	$	4,626	$	4,583

Schedule of Allocation of Plan Assets

The current 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, 2012			December 31, 2011
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.00	%
Asset return assumption		8.00	%		8.00	%

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.

	2012									2011
	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)	$	780,571		$	33,827		$	52,182		$	662,134		$	31,860		$	46,765
Service cost		20,319			274			977			17,725			217			858
Interest cost		38,266			1,629			2,547			37,276			1,766			2,631
Plan amendments		-			-			2,423			-			-			-
Actuarial loss (gain)		92,409			4,111			2,775			89,922			2,427			2,835
Benefits paid		(28,753	)		(2,468	)		(1,200	)		(26,486	)		(2,443	)		(907	)
Benefit obligation at end of year (PBO/PBO/APBO)		902,812			37,373			59,704			780,571			33,827			52,182
Change in plan assets
Market value of plan assets at beginning of year		521,829			-			29,944			475,931			-			29,640
Actual return on plan assets		68,174			-			4,454			2,384			-			(200	)
Employer contributions		48,500			2,468			1,256			70,000			2,443			904
Benefits paid		(28,753	)		(2,468	)		(404	)		(26,486	)		(2,443	)		(400	)
Market value of plan assets at end of year		609,750			-			35,250			521,829			-			29,944
Funded status at year end	$	(293,062	)	$	(37,373	)	$	(24,454	)	$	(258,742	)	$	(33,827	)	$	(22,238	)
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	%		2.75	%		3.00	%		3.00	%		3.00	%

Schedule of Accumulated Benefit Obligation

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

	December 31, 2012		December 31, 2011
Retirement plan	$	811,184	$	699,269
SERP		35,362		32,695

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):

	2013		2014		2015		2016		2017		2018-2022
Pension	$	33.2	$	34.9	$	36.7	$	38.5	$	40.6	$	234.4
PBOP		2.6		2.8		3.0		3.2		3.3		17.4
SERP		2.5		2.5		2.5		2.5		2.5		12.0

Schedule of Net Periodic Benefit Cost and Weighted Average Assumptions

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP						PBOP
	2012			2011			2010			2012		2011		2010		2012			2011			2010
(Thousands of dollars)
Service cost	$	20,319		$	17,725		$	16,932		$	274	$	217	$	372	$	977		$	858		$	856
Interest cost		38,266			37,276			35,614			1,629		1,766		2,045		2,547			2,631			2,491
Expected return on plan assets		(45,780	)		(40,114	)		(36,538	)		-		-		-		(2,404	)		(2,379	)		(2,093	)
Amortization of transition obligation		-			-			-			-		-		-		867			867			867
Amortization of net actuarial loss		23,883			14,348			10,478			683		631		1,155		1,031			590			489
Net periodic benefit cost	$	36,688		$	29,235		$	26,486		$	2,586	$	2,614	$	3,572	$	3,018		$	2,567		$	2,610
Weighted-average assumptions (net benefit cost)
Discount rate		5.00%			5.75%			6.00%			5.00%		5.75%		6.00%		5.00%			5.75%			6.00%
Expected return on plan assets		8.00%			8.00%			8.00%			8.00%		8.00%		8.00%		8.00%			8.00%			8.00%
Weighted-average rate of compensation increase		3.00%			3.25%			3.25%			3.00%		3.25%		3.25%		3.00%			3.25%			3.25%

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

	2012												2011												2010
	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)	$	74,853		$	70,016		$	4,111		$	726		$	135,492		$	127,651		$	2,427		$	5,414		$	9,058		$	10,994		$	(3,480	)	$	1,544
Amortization of transition obligation (b)		(867	)		-			-			(867	)		(867	)		-			-			(867	)		(867	)		-			-			(867	)
Amortization of net actuarial loss (b)		(25,597	)		(23,883	)		(683	)		(1,031	)		(15,569	)		(14,348	)		(631	)		(590	)		(12,122	)		(10,478	)		(1,155	)		(489	)
Prior service cost		2,423			-			-			2,423			-			-			-			-			-			-			-			-
Regulatory adjustment		(42,771	)		(41,520	)		-			(1,251	)		(105,931	)		(101,974	)		-			(3,957	)		(652	)		(464	)		-			(188	)
Recognized in other comprehensive (income) loss	$	8,041		$	4,613		$	3,428		$	-		$	13,125		$	11,329		$	1,796		$	-		$	(4,583	)	$	52		$	(4,635	)	$	-
Net periodic benefit costs recognized in net income		42,292			36,688			2,586			3,018			34,416			29,235			2,614			2,567			32,668			26,486			3,572			2,610
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,333		$	41,301		$	6,014		$	3,018		$	47,541		$	40,564		$	4,410		$	2,567		$	28,085		$	26,538		$	(1,063	)	$	2,610

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, 2012 and December 31, 2011. The SERP has no assets. There were no transfers between Levels 1 and 2.

	December 31, 2012						December 31, 2011
	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
Cash equivalents	$	—	$	—	$	—	$	20	$	1	$	21
Common stock
Capital equipment		3,510		106		3,616		4,332		133		4,465
Chemicals/materials		6,741		204		6,945		7,425		227		7,652
Consumer goods		49,247		1,492		50,739		40,806		1,249		42,055
Energy and mining		39,454		1,195		40,649		39,080		1,196		40,276
Finance/insurance		28,861		874		29,735		23,808		729		24,537
Healthcare		29,615		897		30,512		26,070		798		26,868
Information technology		30,534		925		31,459		29,052		889		29,941
Services		25,316		767		26,083		17,417		533		17,950
Telecommunications/utilities		24,355		738		25,093		16,257		498		16,755
Other		20,298		615		20,913		22,473		688		23,161
Real estate investment trusts		6,572		199		6,771		5,779		177		5,956
Mutual funds		67,749		17,802		85,551		57,512		14,154		71,666
Government fixed income securities		18,663		565		19,228		5,727		175		5,902
Futures contracts		—		—		—		4		—		4
Total Level 1 Assets (1)	$	350,915	$	26,379	$	377,294	$	295,762	$	21,447	$	317,209
Level 2—Significant other observable inputs
Commercial paper	$	635	$	19	$	654	$	—	$	—	$	—
Government fixed income and mortgage backed securities		42,997		1,302		44,299		42,361		1,297		43,658
Corporate fixed income securities
Asset-backed and mortgage-backed		16,637		504		17,141		16,969		519		17,488
Banking		17,966		544		18,510		16,192		496		16,688
Utilities		4,107		124		4,231		5,064		155		5,219
Other		28,925		876		29,801		25,769		789		26,558
Pooled funds and mutual funds		20,636		1,789		22,425		17,447		2,244		19,691
State and local obligations		1,273		39		1,312		936		29		965
Total Level 2 assets (2)	$	133,176	$	5,197	$	138,373	$	124,738	$	5,529	$	130,267
Level 3—Significant unobservable inputs
Commingled equity funds	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Level 3 assets (3)	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Plan assets at fair value	$	607,810	$	35,324	$	643,134	$	517,795	$	29,954	$	547,749
Insurance company general account contracts (4)		4,626		—		4,626		4,952		—		4,952
Total Plan assets (5)	$	612,436	$	35,324	$	647,760	$	522,747	$	29,954	$	552,701

(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 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:

• Investing in various industries with growth and reasonable valuations, avoiding highly cyclical industries

• Diversification by country, limiting exposure in any one country

• Emerging markets

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 an impact fee to be applied to redemptions and subscriptions of $5 million or greater.

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

(5) The assets in the above table exceed the market value of plan assets shown in the funded status table by $2,760,000 (qualified retirement plan – $2,685,000, PBOP – $75,000) and $928,000 (qualified retirement plan – $918,000, PBOP – $10,000) for 2012 and 2011, 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, 2010	$	97,469
Actual return on plan assets:
Relating to assets still held at the reporting date		(8,442	)
Relating to assets sold during the period		246
Purchases		12,000
Sales		(1,000	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2011	$	100,273
Actual return on plan assets:
Relating to assets still held at the reporting date		21,552
Relating to assets sold during the period		342
Purchases		6,800
Sales		(1,500	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2012	$	127,467

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CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Dividends declared Common, per share	$ 1.18	$ 1.06	$ 1
Shares registered and available for issuance	2,200,000
Common shares registered for issuance upon exercise of options	125,000	177,000	369,000

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Stock-Based Compensation Expense

Total stock-based compensation expense recognized in the consolidated statements of income is shown in the table below (in thousands):

	2012		2011		2010
Stock-based compensation expense, net of related tax benefits	$	7,396	$	7,262	$	5,874
Stock-based compensation related tax benefits		4,533		4,451		3,600

Schedule of Stock Options Activity

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

	2012					2011					2010
	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		177		$	27.28		369		$	28.04		651		$	27.49
Exercised during the year		(52	)		25.25		(192	)		28.75		(273	)		26.67
Forfeited or expired during the year		—			—		—			—		(9	)		29.51
Outstanding and exercisable at year end		125		$	28.13		177		$	27.28		369		$	28.04

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):

	2012		2011		2010
Outstanding and exercisable	$	1,788	$	2,697	$	3,186
Exercised		928		1,949		1,689

Summary of Market Prices of Common Stock

	December 31, 2012		December 31, 2011		December 31, 2010
Market value of Southwest Gas stock	$	42.41	$	42.49	$	36.67

Schedule of Stock Options Outstanding and Exercisable

The following table summarizes information about stock options outstanding at December 31, 2012 (thousands of options):

	Options Outstanding and Exercisable
Range of     Exercise Price	Number outstanding	Weighted-average remaining contractual life	Weighted-average exercise price
$20.49 to $23.40	30	1.2 Years	$22.54
$25.00 to $26.10	34	2.5 Years	$25.74
$29.08 to $33.07	61	3.5 Years	$32.21

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, 2012 (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		361		$	30.66		176		$	32.65
Granted		105			41.34		94			41.34
Dividends		10					5
Forfeited or expired		—			—		—			—
Vested and issued*		(128	)		25.68		(68	)		31.61
Nonvested/unissued at December 31, 2012		348		$	36.03		207		$	37.18

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

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Stock-Based Compensation - Summary of Market Prices of Common Stock (Detail) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock Based Compensation [Line Items]
Market value of Southwest Gas stock	$ 42.41	$ 42.49	$ 36.67

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Debt portion	$ 1,129	$ 718	$ 512
Equity portion	1,943	1,154	945
AFUDC capitalized as part of utility plant	$ 3,072	$ 1,872	$ 1,457

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Related Tax Effects Allocated To Each Component Of Other Comprehensive Income Loss [Line Items]
Net actuarial gain/(loss), Before-Tax Amount	$ (74,853)	$ (135,492)	$ (9,058)
Amortization of transition obligation, Before-Tax Amount	867	867	867
Amortization of net actuarial (gain)/loss, Before-Tax Amount	25,597	15,569	12,122
Prior service cost, Before-Tax Amount	(2,423)
Regulatory adjustment, Before-Tax Amount	42,771	105,931	652
Pension plans other comprehensive income (loss), Before-Tax Amount	(8,041)	(13,125)	4,583
Unrealized/realized gain/(loss), Before-Tax Amount	2,959	(17,958)	(18,446)
Amounts reclassified into net income, Before-Tax Amount	2,801	1,169	97
FSIRS other comprehensive income (loss), Before-Tax Amount	5,760	(16,789)	(18,349)
Total other comprehensive income (loss), Before-Tax Amount	(2,281)	(29,914)	(13,766)
Net actuarial gain, Tax (Expense) or Benefit	28,444	51,487	3,442
Amortization of transition obligation, Tax (Expense) or Benefit	(329)	(330)	(329)
Amortization of net actuarial (gain)/loss, Tax (Expense) or Benefit	(9,727)	(5,916)	(4,606)
Prior service cost, Tax (Expense) or Benefit	921
Regulatory adjustment, Tax (Expense) or Benefit	(16,253)	(40,254)	(248)
Pension plans other comprehensive income (loss), Tax (Expense) or Benefit	3,056	4,987	(1,741)
Unrealized/realized gain/(loss), Tax (expense) or Benefit	(1,125)	6,824	7,010
Amounts reclassified into net income, Tax (Expense) or Benefit	(1,064)	(444)	(37)
FSIRS other comprehensive income (loss), Tax (Expense) or Benefit	(2,189)	6,380	6,973
Total other comprehensive income (loss), Tax (Expense) or Benefit	867	11,367	5,232
Net actuarial gain/(loss), Net-of-Tax Amount	(46,409)	(84,005)	(5,616)
Amortization of transition obligation, Net-of-Tax Amount	538	537	538
Amortization of net actuarial (gain)/loss, Net-of-Tax Amount	15,870	9,653	7,516
Prior service cost, Net-of-Tax Amount	(1,502)
Regulatory adjustment, Net-of-Tax Amount	26,518	65,677	404
Pension plans other comprehensive income (loss), Net-of-Tax Amount	(4,985)	(8,138)	2,842
Unrealized/realized loss, Net-of-Tax Amount	1,834	(11,134)	(11,436)
Amounts reclassified into net income, Net-of-Tax Amount	1,737	725	60
FSIRS other comprehensive income (loss), Net-of-Tax Amount	3,571	(10,409)	(11,376)
Total other comprehensive income (loss), net of tax	$ (1,414)	$ (18,547)	$ (8,534)

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Pension and Other Postretirement Benefits - Schedule of Accumulated Benefit Obligation (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Qualified retirement plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 811,184	$ 699,269
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 35,362	$ 32,695

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Utility plant:
Gas plant	$ 5,019,500	$ 4,811,050
Less: accumulated depreciation	(1,750,795)	(1,638,091)
Acquisition adjustments, net	911	1,091
Construction work in progress	74,178	44,894
Net utility plant (Note 2)	3,343,794	3,218,944
Other property and investments	242,096	192,004
Restricted cash		12,785
Current assets:
Cash and cash equivalents	25,530	21,937
Accounts receivable, net of allowances (Note 3)	196,913	209,246
Accrued utility revenue	72,000	70,300
Income taxes receivable, net	2,945	7,793
Deferred income taxes (Note 12)	47,088	53,435
Deferred purchased gas costs (Note 4)	6,031	2,323
Prepaids and other current assets (Notes 1 and 4)	107,910	96,598
Total current assets	458,417	461,632
Deferred charges and other assets (Note 4 and 13)	443,750	390,642
Total assets	4,488,057	4,276,007
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 46,147,788 and 45,956,088 shares) (Note 11)	47,778	47,586
Additional paid-in capital	828,777	821,640
Accumulated other comprehensive income (loss), net (Note 5)	(50,745)	(49,331)
Retained earnings	484,369	406,125
Total Southwest Gas Corporation equity	1,310,179	1,226,020
Noncontrolling interest	(1,681)	(989)
Total equity	1,308,498	1,225,031
Long-term debt, less current maturities (Note 7)	1,268,373	930,858
Total capitalization	2,576,871	2,155,889
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)	50,137	322,618
Accounts payable	155,667	186,755
Customer deposits	77,858	83,839
Accrued general taxes	37,644	42,102
Accrued interest	16,080	16,699
Deferred purchased gas costs (Note 4)	98,957	72,426
Other current liabilities (Note 4 and 13)	98,786	123,129
Total current liabilities	535,129	847,568
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 12)	616,184	557,118
Taxes payable	551	828
Accumulated removal costs (Note 4)	256,000	233,000
Other deferred credits (Note 4 and 10)	503,322	481,604
Total deferred income taxes and other credits	1,376,057	1,272,550
Total capitalization and liabilities	$ 4,488,057	$ 4,276,007

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Utility Plant - Schedule of Rental Payments and Current Term Expiration Dates (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Operating Leased Assets [Line Items]
2013	$ 6,757
2014	4,304
2015	3,181
2016	2,510
2017	1,238
2018	61
Corporate headquarters (expires in 2017) [Member]
Operating Leased Assets [Line Items]
2013	2,140
2014	2,190
2015	2,270
2016	2,343
2017	1,194
2018
Phoenix administrative offices (expires in 2014) [Member]
Operating Leased Assets [Line Items]
2013	1,446
2014	243
2015
2016
2017
2018

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Derivatives and Fair Value Measurements - Amount of Gain or (Loss) Recognized in Income on Derivative (Detail) (Swaps Contracts [Member], Net cost of gas sold [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Swaps Contracts [Member] | Net cost of gas sold [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (loss) recognized in income on derivative	$ (4,854)	$ (18,201)	$ (27,690)
Amount of gain or (loss) recognized in income on derivative	4,854	18,201	27,690
Amount of gain or (loss) recognized in income on derivative, total

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$ 132,639	$ 111,763	$ 103,453
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	223,422	200,469	190,463
Deferred income taxes	66,280	56,467	50,111
Changes in current assets and liabilities:
Accounts receivable, net of allowances	12,333	(61,641)	10,117
Accrued utility revenue	(1,700)	(5,900)	7,300
Deferred purchased gas costs	22,823	(52,885)	33,013
Accounts payable	(25,998)	15,826	6,680
Accrued taxes	113	14,979	(15,240)
Other current assets and liabilities	(18,948)	(3,347)	12,895
Gains on sale	(8,040)	(3,307)	(1,547)
Changes in undistributed stock compensation	5,137	6,125	4,429
AFUDC and property-related changes	(1,943)	(1,154)	(945)
Changes in other assets and deferred charges	(15,367)	11,025	(12,262)
Changes in other liabilities and deferred credits	(4,427)	(36,378)	(17,474)
Net cash provided by operating activities	386,324	252,042	370,993
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions	(395,712)	(380,991)	(215,439)
Restricted cash	12,785	24,996	11,988
Changes in customer advances	(3,025)	(7,771)	(830)
Miscellaneous inflows	13,963	7,686	4,075
Miscellaneous outflows	(2,004)	(2,719)	(2,800)
Net cash used in investing activities	(373,993)	(358,799)	(203,006)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net	1,581	7,402	11,098
Dividends paid	(53,040)	(47,929)	(44,846)
Interest rate swap settlement	(21,754)		(11,691)
Issuance of long-term debt, net	489,518	274,598	123,960
Retirement of long-term debt	(427,043)	(330,473)	(3,327)
Redemption of subordinated debentures			(100,000)
Change in credit facility and commercial paper	2,000	109,000	(92,400)
Net cash provided by (used in) financing activities	(8,738)	12,598	(117,206)
Change in cash and cash equivalents	3,593	(94,159)	50,781
Cash and cash equivalents at beginning of period	21,937	116,096	65,315
Cash and cash equivalents at end of period	25,530	21,937	116,096
Supplemental information:
Interest paid, net of amounts capitalized	87,439	69,842	87,000
Income taxes paid (received)	$ 2,843	$ (13,635)	$ 19,200

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Derivatives and Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative [Line Items]
Natural gas portfolios, minimum % rate	25.00%
Natural gas portfolios, maximum % rate	35.00%
Retirement of long-term debt	$ 427,043,000	$ 330,473,000	$ 3,327,000
Minimum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	January 2013
Maximum [Member]
Derivative [Line Items]
Maturities of natural gas swaps	March 2015
February 2011 [Member]
Derivative [Line Items]
Debt maturing date	February 2011
Retirement of long-term debt	200,000,000
May 2012 [Member]
Derivative [Line Items]
Debt maturing date	May 2012
Retirement of long-term debt	200,000,000
Senior Notes, 4.45%, Due 2020 (Member)
Derivative [Line Items]
Notes payable	125,000,000
Debt instrument interest rate	4.45%
Issuance of fixed rate debt (in years)	10
Notional amount	100,000,000
Senior Notes, 3.875%, Due 2022 (Member)
Derivative [Line Items]
Notes payable	250,000,000
Debt instrument interest rate	3.875%
Issuance of fixed rate debt (in years)	10
Agreement settlement paid	$ 21,800,000

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Preferred Trust Securities and Subordinated Debentures - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Debt Instrument [Line Items]
Proceeds from issuance of trust preferred securities	$ 100
Preferred trust securities, interest rate	7.70%
Trust common securities	3.1
Principal amount of junior subordinated debentures	103.1
Subordinated debentures interest rate percentage	7.70%
Credit facility maximum borrowing capacity	$ 300

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative [Line Items]
Paid to counterparties	$ 14,843	$ 17,283	$ 16,574
Received from counterparties	$ 634		$ 831

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012		December 31, 2011
Accounts receivable for NPL services	$	8,179	$	6,205

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, 2012 is as follows (thousands of dollars):

2012	Gas Operations		Construction Services		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

2011	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,403,366	$	391,701	$	1,795,067
Intersegment sales		—		92,121		92,121
Total	$	1,403,366	$	483,822	$	1,887,188
Interest revenue	$	465	$	20	$	485
Interest expense	$	68,777	$	825	$	69,602
Depreciation and amortization	$	175,253	$	25,216	$	200,469
Income tax expense	$	49,576	$	13,727	$	63,303
Segment net income	$	91,420	$	20,867	$	112,287
Segment assets	$	4,048,613	$	227,394	$	4,276,007
Capital expenditures	$	305,542	$	75,449	$	380,991

2010	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,511,907	$	257,213	$	1,769,120
Intersegment sales		—		61,251		61,251
Total	$	1,511,907	$	318,464	$	1,830,371
Interest revenue	$	158	$	36	$	194
Interest expense	$	77,025	$	564	$	77,589
Depreciation and amortization	$	170,456	$	20,007	$	190,463
Income tax expense	$	47,073	$	7,852	$	54,925
Segment net income	$	91,382	$	12,495	$	103,877
Segment assets	$	3,845,111	$	139,082	$	3,984,193
Capital expenditures	$	188,379	$	27,060	$	215,439

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Short-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Short-term Debt [Line Items]
Short-term debt expiration date	May 01, 2012
Working capital purposes	$ 150,000,000
Current borrowing capacity	0
Maximum borrowing capacity	300,000,000
May 2012 [Member]
Short-term Debt [Line Items]
Maximum borrowing capacity	300,000,000
March 2017 [Member]
Short-term Debt [Line Items]
Short-term debt expiration date	Mar. 01, 2017
Short-term credit facility [Member]
Short-term Debt [Line Items]
Current borrowing capacity	0
Line of credit facility, due on may 2012 [Member] | March 2017 [Member]
Short-term Debt [Line Items]
Current borrowing capacity	$ 300,000,000

XML

Segment Information

12 Months Ended

Dec. 31, 2012

Segment Information

Note 14 - Segment Information

Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

The accounting policies of the reported segments are the same as those described within Note 1 – Summary of Significant Accounting Policies. NPL 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, 2012		December 31, 2011
Accounts receivable for NPL services	$	8,179	$	6,205

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, 2012 is as follows (thousands of dollars):

2012	Gas Operations		Construction Services		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

2011	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,403,366	$	391,701	$	1,795,067
Intersegment sales		—		92,121		92,121
Total	$	1,403,366	$	483,822	$	1,887,188
Interest revenue	$	465	$	20	$	485
Interest expense	$	68,777	$	825	$	69,602
Depreciation and amortization	$	175,253	$	25,216	$	200,469
Income tax expense	$	49,576	$	13,727	$	63,303
Segment net income	$	91,420	$	20,867	$	112,287
Segment assets	$	4,048,613	$	227,394	$	4,276,007
Capital expenditures	$	305,542	$	75,449	$	380,991

2010	Gas Operations		Construction Services		Total
Revenues from unaffiliated customers	$	1,511,907	$	257,213	$	1,769,120
Intersegment sales		—		61,251		61,251
Total	$	1,511,907	$	318,464	$	1,830,371
Interest revenue	$	158	$	36	$	194
Interest expense	$	77,025	$	564	$	77,589
Depreciation and amortization	$	170,456	$	20,007	$	190,463
Income tax expense	$	47,073	$	7,852	$	54,925
Segment net income	$	91,382	$	12,495	$	103,877
Segment assets	$	3,845,111	$	139,082	$	3,984,193
Capital expenditures	$	188,379	$	27,060	$	215,439

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Quarterly Financial Information

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,919		(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
2011
Operating revenues	$	628,440	$	388,505		$	352,592		$	517,651
Operating income		126,335		20,568			1,253			101,924
Net income (loss)		68,549		4,055			(15,641	)		55,324
Basic earnings (loss) per common share*		1.50		0.09			(0.34	)		1.20
Diluted earnings (loss) per common share*		1.48		0.09			(0.34	)		1.19
2010
Operating revenues	$	668,751	$	385,825		$	307,683		$	468,112
Operating income		121,732		24,031			184			86,170
Net income (loss)		64,648		(933	)		(4,823	)		44,985
Basic earnings (loss) per common share*		1.43		(0.02	)		(0.11	)		0.99
Diluted earnings (loss) per common share*		1.42		(0.02	)		(0.11	)		0.98

* 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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Derivatives and Fair Value Measurements - Fair Values of Swaps and FSIRS in Balance Sheet Location (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	$ 756
Liability derivatives not designated as hedging instruments	(3,145)	(11,743)
Net total not designated as hedging instruments	(2,389)	(11,743)
Swaps [Member] | Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	132
Liability derivatives not designated as hedging instruments	(126)
Net total not designated as hedging instruments	6
Swaps [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	391
Liability derivatives not designated as hedging instruments	(2,467)	(11,122)
Net total not designated as hedging instruments	(2,076)	(11,122)
Swaps [Member] | Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives not designated as hedging instruments	233
Liability derivatives not designated as hedging instruments	(552)	(621)
Net total not designated as hedging instruments	(319)	(621)
FSIRS [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives designated as hedging instrument
Liability Derivatives designated as hedging instrument		(24,713)
Net total designated as hedging instrument		$ (24,713)

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

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. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

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. 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. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities.

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):

	2012			2011
NPL property and equipment	$	287		$	237
Accumulated provision for depreciation and amortization		(136	)		(128	)
Net cash surrender value of COLI policies		80			74
Other property		11			9
Total	$	242		$	192

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 plant materials and operating supplies of $25 million in 2012 and $21 million in 2011.

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.

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. 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. During 2012, approximately $20 million of customer advances, upon contract expiration, were applied as contributions offsetting construction expenditures as a non-cash investing activity.

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, 2012		December 31, 2011
Accumulated removal costs	$	256,000	$	233,000

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 NPL contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two 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 the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps, that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.

In 2011, NPL recorded $5 million in estimated pretax profit associated with a large fixed-price contract. In connection with significant changes in estimated costs to complete the fixed-price contract, NPL results reflect pretax losses (with after-tax earnings per share impacts) of $15 million ($0.20 per share) for the year ended December 31, 2012, including $18 million ($0.24 per share) in the first half of 2012. The estimated cost changes that resulted in the losses recognized included reductions in projected productivity and higher costs of restoration work. Change orders approved during the fourth quarter of 2012 helped to reduce losses overall on the contract. On a contract-to-date basis the cumulative loss is $10 million. At December 31, 2012, work on this sizeable contract is over 95% complete.

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, and office-related fixed costs of NPL.

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.

	2012		2011		2010
(In thousands)
AFUDC:
Debt portion	$	1,129	$	718	$	512
Equity portion		1,943		1,154		945
AFUDC capitalized as part of utility plant	$	3,072	$	1,872	$	1,457

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):

	2012			2011			2010
Change in COLI policies	$	6,600		$	700		$	9,770
Interest income		924			485			194
Pipe replacement costs		(2,680	)		(4,761	)		(5,024	)
Miscellaneous income and (expense)		(433	)		(1,836	)		(1,090	)
Total other income (deductions)	$	4,411		$	(5,412	)	$	3,850

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, is 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 completed in 2012.

Earnings Per Share

Earnings Per Share.    Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of 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 shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.

	2012		2011		2010
(In thousands)
Average basic shares		46,115		45,858		45,405
Effect of dilutive securities:
Stock options		42		52		56
Performance shares		254		271		260
Restricted stock units		144		110		102
Average diluted shares		46,555		46,291		45,823

Recently Issued Accounting Standards Updates

Recently Issued Accounting Standards Updates.    In October 2012, the Financial Accounting Standards Board (“FASB”) issued the update “Technical Corrections and Improvements” which clarifies or corrects unintended application of accounting guidance. Many of these changes are not expected to have a significant effect on current accounting practice but some improvements are more substantive and are not technical corrections. Amendments included in the update without transition guidance were effective upon issuance. Amendments subject to transition guidance were effective for the Company on January 1, 2013 for interim and annual reporting periods. The adoption of the update is not expected to have a material impact on the Company’s disclosures, financial position, or results of operations.

In July 2012, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment,” which provides that an entity has the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that an indefinite-lived intangible asset is impaired. If, in electing the qualitative evaluation step, there is no indication of impairment, quantitative impairment testing would not be required to be performed. The update would provide consistency in evaluation for goodwill and indefinite-lived intangibles other than goodwill. The Company adopted this update, as required, on January 1, 2013. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.

In December 2011, the FASB issued the update “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entity’s financial statements to understand the effect of those arrangements on the entity’s financial position. In January 2013, the FASB issued the update “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“Clarification”) that clarifies the scope of the “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” update. The amendments included in the Clarification apply to entities that have derivatives, repurchase agreements and reverse repurchase agreements, and certain securities borrowing and securities lending transactions that are offset, or subject to a master netting or similar agreement. Entities with other types of financial assets and financial liabilities subject to a master netting or similar agreements would no longer be subject to the disclosure requirements in the initial update. All disclosures are required to be provided retrospectively for all periods presented. The Company adopted both updates, as required, on January 1, 2013 for interim and annual reporting periods. These updates are 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.

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Pension and Other Postretirement Benefits - Cost of Retirement Plan (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Employee Investment Plan cost	$ 4,707	$ 4,626	$ 4,583

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CONSOLIDATED STATEMENTS OF EQUITY (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]
Balance at Dec. 31, 2009	$ 1,102,086	$ 46,722		$ 792,339	$ (22,250)	$ 285,316	$ (41)
Balance, shares at Dec. 31, 2009		45,092,000
Common stock issuances Value	16,053	507		15,546
Common stock issuance, shares		507,000
Net income (loss)	103,453					103,877	(424)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)	2,842				2,842
FSIRS realized and unrealized gain (loss), net of tax (Notes 5 and 13)	(11,436)				(11,436)
Amounts reclassified to net income, net of tax (Notes 5 and 13)	60				60
Dividends declared Common	(46,062)					(46,062)
Balance at Dec. 31, 2010	1,166,996	47,229		807,885	(30,784)	343,131	(465)
Balance, shares at Dec. 31, 2010		45,599,000
Common stock issuances Value	14,112	357		13,755
Common stock issuance, shares		357,000
Net income (loss)	111,763					112,287	(524)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)	(8,138)				(8,138)
FSIRS realized and unrealized gain (loss), net of tax (Notes 5 and 13)	(11,134)				(11,134)
Amounts reclassified to net income, net of tax (Notes 5 and 13)	725				725
Dividends declared Common	(49,293)					(49,293)
Balance at Dec. 31, 2011	1,225,031	47,586		821,640	(49,331)	406,125	(989)
Balance, shares at Dec. 31, 2011	45,956,088	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 10)	(4,985)				(4,985)
FSIRS realized and unrealized gain (loss), net of tax (Notes 5 and 13)	1,834				1,834
Amounts reclassified to net income, net of tax (Notes 5 and 13)	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	46,147,788	46,148,000	[1]

[1] At December 31, 2012, 2.2 million common shares were registered and available for issuance under provisions of the Company's various stock issuance plans. In addition, approximately 125,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 11).

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Common stock, par	$ 1	$ 1
Common stock, authorized	60,000,000	60,000,000
Common stock, issued	46,147,788	45,956,088
Common stock, outstanding	46,147,788	45,956,088

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies

Note 9 — Commitments and Contingencies

The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is currently subject will have a material adverse impact on its financial position or results of operations.

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers are responsible for amounts up to the policy limits. The self-insured retention amount associated with general liability claims is $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million in the policy year.

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Segment Information - Schedule of Segment Reporting Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended												12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers													$ 1,844,404	$ 1,795,067	$ 1,769,120
Intersegment sales													83,374	92,121	61,251
Total operating revenues	488,566	371,799	409,768	657,645	517,651	352,592	388,505	628,440	468,112	307,683	385,825	668,751	1,927,778	1,887,188	1,830,371
Interest revenue													924	485	194
Interest expense													68,020	69,602	77,589
Depreciation and amortization													223,422	200,469	190,463
Income tax expense													75,276	63,303	54,925
Segment net income													133,331	112,287	103,877
Segment assets	4,488,057				4,276,007				3,984,193				4,488,057	4,276,007	3,984,193
Capital expenditures													395,712	380,991	215,439
Gas Operations [Member]
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers													1,321,728	1,403,366	1,511,907
Total operating revenues													1,321,728	1,403,366	1,511,907
Interest revenue													915	465	158
Interest expense													66,957	68,777	77,025
Depreciation and amortization													186,035	175,253	170,456
Income tax expense													64,973	49,576	47,073
Segment net income													116,619	91,420	91,382
Segment assets	4,204,948				4,048,613				3,845,111				4,204,948	4,048,613	3,845,111
Capital expenditures													308,951	305,542	188,379
Construction Services [Member]
Segment Reporting Information [Line Items]
Revenues from unaffiliated customers													522,676	391,701	257,213
Intersegment sales													83,374	92,121	61,251
Total operating revenues													606,050	483,822	318,464
Interest revenue													9	20	36
Interest expense													1,063	825	564
Depreciation and amortization													37,387	25,216	20,007
Income tax expense													10,303	13,727	7,852
Segment net income													16,712	20,867	12,495
Segment assets	283,109				227,394				139,082				283,109	227,394	139,082
Capital expenditures													$ 86,761	$ 75,449	$ 27,060

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Income Taxes [Line Items]
Federal net operating loss carryforward	$ 103,000,000
Federal general business credit carryforward	306,000
Federal net operating loss carryforward and general business credit carryforward, expiration year	2031
Net capital loss carryforward	320,000
Net capital loss and charitable contribution carryforward, expiration year	2016
Charitable contribution carryforwards	2016 and 2017
Percentage of bonus depreciation deduction through 2013	50.00%
2016 [Member]
Income Taxes [Line Items]
Charitable contribution carryforwards	892,000
2017 [Member]
Income Taxes [Line Items]
Charitable contribution carryforwards	$ 743,000

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Income Taxes - Consolidated Effective Income Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Federal statutory income tax rate	35.00%	35.00%	35.00%
Net state taxes	2.60%	2.70%	2.80%
Property-related items	0.20%	0.20%	0.20%
Effect of income tax settlements		(0.90%)	(0.30%)
Tax credits	(0.40%)	(0.60%)	(0.50%)
Company owned life insurance	(1.30%)	(0.10%)	(2.30%)
All other differences	0.10%	(0.10%)	(0.20%)
Consolidated effective income tax rate	36.20%	36.20%	34.70%

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Feb. 15, 2013	Jun. 30, 2012
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
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		46,294,796
Entity Public Float			$ 2,013,502,347

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Pension and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2012

Pension and Other Postretirement Benefits

Note 10 – Pension and Other Postretirement Benefits

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

	2012		2011		2010
Employee Investment Plan cost	$	4,707	$	4,626	$	4,583

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. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are 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. The current 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 the continuing low interest rate environment for high-quality fixed income investments, the Company lowered the discount rate in 2012 from 2011. 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) in 2012 from 2011 and the asset return assumption was unchanged between periods. The rates are presented in the table below:

	December 31, 2012			December 31, 2011
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.00	%
Asset return assumption		8.00	%		8.00	%

The significant reduction in the discount rate will increase the expense level for 2013. Pension expense for 2013 is estimated to increase by $6.4 million. 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.

	2012									2011
	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)	$	780,571		$	33,827		$	52,182		$	662,134		$	31,860		$	46,765
Service cost		20,319			274			977			17,725			217			858
Interest cost		38,266			1,629			2,547			37,276			1,766			2,631
Plan amendments		-			-			2,423			-			-			-
Actuarial loss (gain)		92,409			4,111			2,775			89,922			2,427			2,835
Benefits paid		(28,753	)		(2,468	)		(1,200	)		(26,486	)		(2,443	)		(907	)
Benefit obligation at end of year (PBO/PBO/APBO)		902,812			37,373			59,704			780,571			33,827			52,182
Change in plan assets
Market value of plan assets at beginning of year		521,829			-			29,944			475,931			-			29,640
Actual return on plan assets		68,174			-			4,454			2,384			-			(200	)
Employer contributions		48,500			2,468			1,256			70,000			2,443			904
Benefits paid		(28,753	)		(2,468	)		(404	)		(26,486	)		(2,443	)		(400	)
Market value of plan assets at end of year		609,750			-			35,250			521,829			-			29,944
Funded status at year end	$	(293,062	)	$	(37,373	)	$	(24,454	)	$	(258,742	)	$	(33,827	)	$	(22,238	)
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	%		2.75	%		3.00	%		3.00	%		3.00	%

Estimated funding for the plans above during calendar year 2013 is approximately $49 million of which $46 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, 2012		December 31, 2011
Retirement plan	$	811,184	$	699,269
SERP		35,362		32,695

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

	2013		2014		2015		2016		2017		2018-2022
Pension	$	33.2	$	34.9	$	36.7	$	38.5	$	40.6	$	234.4
PBOP		2.6		2.8		3.0		3.2		3.3		17.4
SERP		2.5		2.5		2.5		2.5		2.5		12.0

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 7.5% 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
	2012			2011			2010			2012		2011		2010		2012			2011			2010
(Thousands of dollars)
Service cost	$	20,319		$	17,725		$	16,932		$	274	$	217	$	372	$	977		$	858		$	856
Interest cost		38,266			37,276			35,614			1,629		1,766		2,045		2,547			2,631			2,491
Expected return on plan assets		(45,780	)		(40,114	)		(36,538	)		-		-		-		(2,404	)		(2,379	)		(2,093	)
Amortization of transition obligation		-			-			-			-		-		-		867			867			867
Amortization of net actuarial loss		23,883			14,348			10,478			683		631		1,155		1,031			590			489
Net periodic benefit cost	$	36,688		$	29,235		$	26,486		$	2,586	$	2,614	$	3,572	$	3,018		$	2,567		$	2,610
Weighted-average assumptions (net benefit cost)
Discount rate		5.00%			5.75%			6.00%			5.00%		5.75%		6.00%		5.00%			5.75%			6.00%
Expected return on plan assets		8.00%			8.00%			8.00%			8.00%		8.00%		8.00%		8.00%			8.00%			8.00%
Weighted-average rate of compensation increase		3.00%			3.25%			3.25%			3.00%		3.25%		3.25%		3.00%			3.25%			3.25%

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

	2012												2011												2010
	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)	$	74,853		$	70,016		$	4,111		$	726		$	135,492		$	127,651		$	2,427		$	5,414		$	9,058		$	10,994		$	(3,480	)	$	1,544
Amortization of transition obligation (b)		(867	)		-			-			(867	)		(867	)		-			-			(867	)		(867	)		-			-			(867	)
Amortization of net actuarial loss (b)		(25,597	)		(23,883	)		(683	)		(1,031	)		(15,569	)		(14,348	)		(631	)		(590	)		(12,122	)		(10,478	)		(1,155	)		(489	)
Prior service cost		2,423			-			-			2,423			-			-			-			-			-			-			-			-
Regulatory adjustment		(42,771	)		(41,520	)		-			(1,251	)		(105,931	)		(101,974	)		-			(3,957	)		(652	)		(464	)		-			(188	)
Recognized in other comprehensive (income) loss	$	8,041		$	4,613		$	3,428		$	-		$	13,125		$	11,329		$	1,796		$	-		$	(4,583	)	$	52		$	(4,635	)	$	-
Net periodic benefit costs recognized in net income		42,292			36,688			2,586			3,018			34,416			29,235			2,614			2,567			32,668			26,486			3,572			2,610
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	50,333		$	41,301		$	6,014		$	3,018		$	47,541		$	40,564		$	4,410		$	2,567		$	28,085		$	26,538		$	(1,063	)	$	2,610

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, 2012 and December 31, 2011. The SERP has no assets. There were no transfers between Levels 1 and 2.

	December 31, 2012						December 31, 2011
	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
Cash equivalents	$	—	$	—	$	—	$	20	$	1	$	21
Common stock
Capital equipment		3,510		106		3,616		4,332		133		4,465
Chemicals/materials		6,741		204		6,945		7,425		227		7,652
Consumer goods		49,247		1,492		50,739		40,806		1,249		42,055
Energy and mining		39,454		1,195		40,649		39,080		1,196		40,276
Finance/insurance		28,861		874		29,735		23,808		729		24,537
Healthcare		29,615		897		30,512		26,070		798		26,868
Information technology		30,534		925		31,459		29,052		889		29,941
Services		25,316		767		26,083		17,417		533		17,950
Telecommunications/utilities		24,355		738		25,093		16,257		498		16,755
Other		20,298		615		20,913		22,473		688		23,161
Real estate investment trusts		6,572		199		6,771		5,779		177		5,956
Mutual funds		67,749		17,802		85,551		57,512		14,154		71,666
Government fixed income securities		18,663		565		19,228		5,727		175		5,902
Futures contracts		—		—		—		4		—		4
Total Level 1 Assets (1)	$	350,915	$	26,379	$	377,294	$	295,762	$	21,447	$	317,209
Level 2—Significant other observable inputs
Commercial paper	$	635	$	19	$	654	$	—	$	—	$	—
Government fixed income and mortgage backed securities		42,997		1,302		44,299		42,361		1,297		43,658
Corporate fixed income securities
Asset-backed and mortgage-backed		16,637		504		17,141		16,969		519		17,488
Banking		17,966		544		18,510		16,192		496		16,688
Utilities		4,107		124		4,231		5,064		155		5,219
Other		28,925		876		29,801		25,769		789		26,558
Pooled funds and mutual funds		20,636		1,789		22,425		17,447		2,244		19,691
State and local obligations		1,273		39		1,312		936		29		965
Total Level 2 assets (2)	$	133,176	$	5,197	$	138,373	$	124,738	$	5,529	$	130,267
Level 3—Significant unobservable inputs
Commingled equity funds	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Level 3 assets (3)	$	123,719	$	3,748	$	127,467	$	97,295	$	2,978	$	100,273
Total Plan assets at fair value	$	607,810	$	35,324	$	643,134	$	517,795	$	29,954	$	547,749
Insurance company general account contracts (4)		4,626		—		4,626		4,952		—		4,952
Total Plan assets (5)	$	612,436	$	35,324	$	647,760	$	522,747	$	29,954	$	552,701

(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 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:

• Investing in various industries with growth and reasonable valuations, avoiding highly cyclical industries

• Diversification by country, limiting exposure in any one country

• Emerging markets

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 an impact fee to be applied to redemptions and subscriptions of $5 million or greater.

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

(5) The assets in the above table exceed the market value of plan assets shown in the funded status table by $2,760,000 (qualified retirement plan – $2,685,000, PBOP – $75,000) and $928,000 (qualified retirement plan – $918,000, PBOP – $10,000) for 2012 and 2011, 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, 2010	$	97,469
Actual return on plan assets:
Relating to assets still held at the reporting date		(8,442	)
Relating to assets sold during the period		246
Purchases		12,000
Sales		(1,000	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2011	$	100,273
Actual return on plan assets:
Relating to assets still held at the reporting date		21,552
Relating to assets sold during the period		342
Purchases		6,800
Sales		(1,500	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2012	$	127,467

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Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, maximum term, years	10 years
Weighted-average remaining contractual life of outstanding options, years	2 years 8 months 12 days
Cash received from exercise of stock options	$ 1,400,000
Tax benefit realized from exercise of stock options	363,000
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		$ 37.87	$ 29.04
Total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized	$ 3,800,000

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant Components Of Deferred Income Tax Expense [Line Items]
Total deferred federal and state	$ 68,097	$ 62,314	$ 47,147
Deferred ITC, net	(861)	(868)	(868)
Total deferred income tax expense	67,236	61,446	46,279
Property-related items [Member]
Significant Components Of Deferred Income Tax Expense [Line Items]
Total deferred federal and state	64,249	51,710	43,420
Purchased gas cost adjustments [Member]
Significant Components Of Deferred Income Tax Expense [Line Items]
Total deferred federal and state	1,755	(92)	(315)
Employee benefits [Member]
Significant Components Of Deferred Income Tax Expense [Line Items]
Total deferred federal and state	564	11,766	8,753
All other deferred [Member]
Significant Components Of Deferred Income Tax Expense [Line Items]
Total deferred federal and state	$ 1,529	$ (1,070)	$ (4,711)

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating revenues:
Gas operating revenues	$ 1,321,728	$ 1,403,366	$ 1,511,907
Construction revenues	606,050	483,822	318,464
Total operating revenues	1,927,778	1,887,188	1,830,371
Operating expenses:
Net cost of gas sold	479,602	613,489	736,175
Operations and maintenance	369,979	358,498	354,943
Depreciation and amortization	223,422	200,469	190,463
Taxes other than income taxes	41,728	40,949	38,869
Construction expenses	541,523	423,703	277,804
Total operating expenses	1,656,254	1,637,108	1,598,254
Operating income	271,524	250,080	232,117
Other income and (expenses):
Net interest deductions (Note 7 and 8)	(68,020)	(69,602)	(75,677)
Net interest deductions on subordinated debentures (Note 6)			(1,912)
Other income (deductions)	4,411	(5,412)	3,850
Total other income and (expenses)	(63,609)	(75,014)	(73,739)
Income before income taxes	207,915	175,066	158,378
Income tax expense (Note 12)	75,276	63,303	54,925
Net Income	132,639	111,763	103,453
Net income (loss) attributable to noncontrolling interest	(692)	(524)	(424)
Net income attributable to Southwest Gas Corporation	$ 133,331	$ 112,287	$ 103,877
Basic earnings per share (Note 15)	$ 2.89	$ 2.45	$ 2.29
Diluted earnings per share (Note 15)	$ 2.86	$ 2.43	$ 2.27
Average number of common shares outstanding	46,115	45,858	45,405
Average shares outstanding (assuming dilution)	46,555	46,291	45,823

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2012

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”). Southwest accounting policies 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,	2012			2011
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	373,615		$	330,844
Unrealized net loss on non-trading derivatives (Swaps) (2)		2,395			11,743
Deferred purchased gas costs (3)		6,031			2,323
Accrued purchased gas costs (4)		30,300			18,400
Unamortized premium on reacquired debt (5)		19,452			19,011
Other (6)		44,927			32,988
		476,720			415,309
Regulatory liabilities:
Deferred purchased gas costs (3)		(98,957	)		(72,426	)
Accumulated removal costs		(256,000	)		(233,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		(6	)		—
Deferred gain on southern Nevada division operations facility (7)		(392	)		(806	)
Unamortized gain on reacquired debt (8)		(11,934	)		(12,470	)
Other (9)		(6,951	)		(14,501	)
Net regulatory assets	$	102,480		$	82,106

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

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

Instrument	Balance Sheet Location	2012			2011
Swaps	Deferred charges and other assets	$	319		$	621
Swaps	Prepaids and other current assets		2,076			11,122
Swaps	Other deferred credits		(6	)		—

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

(4) Included in Prepaids and other current assets on the Consolidated Balance Sheets and recovered over one year or less.

(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 Decision, the amortization period was extended through 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, 2012

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 at December 31, 2012, and the percentage of customers in each of the three states.

Gas utility customer accounts receivable balance (in thousands) $ 94,695

	December 31, 2012
Percent of customers by state
Arizona		54	%
Nevada		36	%
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, 2009	$	3,953
Additions charged to expense		2,646
Accounts written off, less recoveries		(3,405	)
Balance, December 31, 2010		3,194
Additions charged to expense		2,678
Accounts written off, less recoveries		(2,690	)
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

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data

Note 15 – Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,919		(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
2011
Operating revenues	$	628,440	$	388,505		$	352,592		$	517,651
Operating income		126,335		20,568			1,253			101,924
Net income (loss)		68,549		4,055			(15,641	)		55,324
Basic earnings (loss) per common share*		1.50		0.09			(0.34	)		1.20
Diluted earnings (loss) per common share*		1.48		0.09			(0.34	)		1.19
2010
Operating revenues	$	668,751	$	385,825		$	307,683		$	468,112
Operating income		121,732		24,031			184			86,170
Net income (loss)		64,648		(933	)		(4,823	)		44,985
Basic earnings (loss) per common share*		1.43		(0.02	)		(0.11	)		0.99
Diluted earnings (loss) per common share*		1.42		(0.02	)		(0.11	)		0.98

* 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.

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2012

Stock-Based Compensation

Note 11 – Stock-Based Compensation

At December 31, 2012, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income is shown in the table below (in thousands):

	2012		2011		2010
Stock-based compensation expense, net of related tax benefits	$	7,396	$	7,262	$	5,874
Stock-based compensation related tax benefits		4,533		4,451		3,600

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):

	2012					2011					2010
	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		177		$	27.28		369		$	28.04		651		$	27.49
Exercised during the year		(52	)		25.25		(192	)		28.75		(273	)		26.67
Forfeited or expired during the year		—			—		—			—		(9	)		29.51
Outstanding and exercisable at year end		125		$	28.13		177		$	27.28		369		$	28.04

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):

	2012		2011		2010
Outstanding and exercisable	$	1,788	$	2,697	$	3,186
Exercised		928		1,949		1,689

	December 31, 2012		December 31, 2011		December 31, 2010
Market value of Southwest Gas stock	$	42.41	$	42.49	$	36.67

The weighted-average remaining contractual life for outstanding options was 2.7 years for 2012. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2012 (thousands of options):

	Options Outstanding and Exercisable
Range of     Exercise Price	Number outstanding	Weighted-average remaining contractual life	Weighted-average exercise price
$20.49 to $23.40	30	1.2 Years	$22.54
$25.00 to $26.10	34	2.5 Years	$25.74
$29.08 to $33.07	61	3.5 Years	$32.21

The Company received $1.4 million in cash from the exercise of options during 2012 and a corresponding tax benefit of $363,000 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 then issued as common stock. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants to directors followed the vesting schedule for employees; however, beginning with grants in 2012, the directors’ restricted stock/units vest 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, 2012 (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		361		$	30.66		176		$	32.65
Granted		105			41.34		94			41.34
Dividends		10					5
Forfeited or expired		—			—		—			—
Vested and issued*		(128	)		25.68		(68	)		31.61
Nonvested/unissued at December 31, 2012		348		$	36.03		207		$	37.18

*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 2011 and 2010 was $37.87 and $29.04, respectively.

As of December 31, 2012, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.8 million.

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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, 2012
$20.49 to $23.40 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Price, Lower limit	$ 20.49
Range of Exercise Price, Upper limit	$ 23.40
Weighted-average remaining contractual life, years	1 year 2 months 12 days
Number outstanding	30
Weighted-average exercise price	$ 22.54
$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
Weighted-average remaining contractual life, years	2 years 6 months
Number outstanding	34
Weighted-average exercise price	$ 25.74
$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
Weighted-average remaining contractual life, years	3 years 6 months
Number outstanding	61
Weighted-average exercise price	$ 32.21

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Long-Term Debt

12 Months Ended

Dec. 31, 2012

Long-Term Debt

Note 7 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2012 and December 31, 2011 are disclosed in the following table. The fair values of the revolving credit facility, the NPL revolving credit facility, and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, and are categorized as Level 1 (quoted prices for identical financial instruments) within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The market values of debentures (except the 4.45% Notes) and fixed-rate IDRBs are categorized as Level 2. The 4.45% Notes and NPL other debt obligations are categorized as Level 3 (based on significant unobservable inputs to their fair values). Fair values for the debentures, fixed-rate IDRBs, and NPL other debt obligations were determined through a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

December 31,	2012					2011
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 7.625%, due 2012	$	—		$	—	$	200,000		$	204,312
Notes, 4.45%, due 2020		125,000			141,771		125,000			128,673
Notes, 6.1%, due 2041		125,000			165,779		125,000			143,074
Notes, 3.875%, due 2022		250,000			277,950		—			—
8% Series, due 2026		75,000			111,501		75,000			96,340
Medium-term notes, 7.59% series, due 2017		25,000			30,710		25,000			30,199
Medium-term notes, 7.78% series, due 2022		25,000			34,637		25,000			31,932
Medium-term notes, 7.92% series, due 2027		25,000			36,953		25,000			31,648
Medium-term notes, 6.76% series, due 2027		7,500			10,058		7,500			8,510
Unamortized discount		(3,403	)				(2,087	)
		654,097					605,413
Revolving credit facility and commercial paper		111,000			111,000		109,000			109,000
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:
6.10% 1999 Series A, due 2038		—			—		12,410			12,410
5.95% 1999 Series C, due 2038		—			—		14,320			14,449
5.55% 1999 Series D, due 2038		8,270			8,375		8,270			8,253
5.45% 2003 Series C, due 2038 (rate resets in March 2013)		30,000			30,152		30,000			31,332
5.25% 2003 Series D, due 2038		20,000			20,571		20,000			19,583
5.80% 2003 Series E, due 2038 (rate resets in March 2013)		15,000			15,102		15,000			15,634
5.25% 2004 Series A, due 2034		65,000			66,955		65,000			64,291
5.00% 2004 Series B, due 2033		31,200			31,655		31,200			30,283
4.85% 2005 Series A, due 2035		100,000			101,184		100,000			94,836
4.75% 2006 Series A, due 2036		24,855			25,189		24,855			23,179
Unamortized discount		(3,195	)				(3,360	)
		491,130					517,695
NPL credit facility		41,562			41,562		16,566			16,566
NPL other debt obligations		20,721			20,991		4,802			4,814
		1,318,510					1,253,476
Less: current maturities		(50,137	)				(322,618	)
Long-term debt, less current maturities	$	1,268,373				$	930,858

In January 2012, the Company redeemed at par its $12.4 million 1999 6.1% Series A fixed-rate IDRBs (originally due in 2038). In August 2012, the Company redeemed at par its $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038).

In March 2012, the Company issued $250 million in 3.875% Senior Notes at a 0.034% discount. The notes will mature on April 1, 2022. Management used approximately $200 million of the net proceeds in connection with the repayment of the $200 million 7.625% Senior Notes that matured in May 2012. The remaining net proceeds were used for general corporate purposes.

In March 2012, the Company replaced the existing $300 million revolving credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (“LIBOR”) or the “alternate base rate,” plus, in each case, an applicable margin that is determined based on the Company’s senior unsecured debt rating. At the Company’s current unsecured debt rating, the applicable margin is 1.125% for loans bearing interest with reference to LIBOR and 0.125% for loans bearing interest with reference to the alternative base rate. Southwest has designated $150 million of the $300 million facility for long-term purposes and the remaining $150 million for working capital purposes. At December 31, 2012, $91 million was outstanding on the credit facility. Borrowings under the credit facility ranged from $0 during the second quarter of 2012 to a high of $130 million during November 2012. The effective interest rate on the long-term portion of the credit facility was 1.43% at December 31, 2012. There were no borrowings outstanding on the short-term portion of the credit facility at December 31, 2011 and 2012. (See Note 8 – Short-Term Debt).

The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the new program are calculated at the then current commercial paper rate. At December 31, 2012, $20 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.84% at December 31, 2012.

In February 2013, a notice of mandatory tender was sent to holders of the Clark County, Nevada 5.45% Series 2003C and 5.80% Series 2003E IDRBs. These IDRBs (totaling $45 million) are subject to mandatory tender on March 1, 2013 at a price of 100% plus accrued interest, and the Company intends to tender these IDRBs to the trustee for cancellation immediately following the mandatory tender, thereby extinguishing this debt. Therefore, these IDRBs are shown as current maturities in the Company’s consolidated balance sheet. The Company will facilitate the redemption primarily from borrowings under its $300 million credit facility.

In June 2012, NPL replaced its existing $30 million revolving credit facility that was to expire in June 2013 with a $75 million facility that is scheduled to expire in June 2015. The credit facility was amended in October 2012 to temporarily increase the facility from $75 million to $85 million until December 29, 2012 and then reverted back to $75 million. Interest rates for the credit facility were also amended in October 2012 and are now calculated at either LIBOR or a base rate, plus, in each case, 1.00% or 0.75% depending on NPL’s leverage ratio at the end of each quarter. At December 31, 2012, $41.6 million was outstanding on the NPL credit facility. The effective interest rate on NPL’s credit facility was 0.97% at December 31, 2012.

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

	December 31, 2012			December 31, 2011
2003 Series A		1.71	%		0.83	%
2008 Series A		1.59	%		1.62	%
2009 Series A		1.14	%		1.56	%
Tax-exempt Series A		1.25	%		2.22	%

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):

2013	$	50,137
2014		5,249
2015		46,705
2016		4,143
2017		137,049

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, 2012, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.7 billion in additional debt and meet the leverage ratio requirement. The Company has at least $700 million of cushion in equity relating to the minimum net worth requirement.

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Long-Term Debt - Schedule of Estimated Fair Values of Long-Term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Less: current maturities	$ (50,137)	$ (322,618)
Long-term debt, less current maturities	1,268,373	930,858
Carrying Amount [Member]
Debt Instrument [Line Items]
NPL credit facility	41,562	16,566
Unamortized discount	(3,195)	(3,360)
Long-term debt, gross	1,318,510	1,253,476
Less: current maturities	(50,137)	(322,618)
Long-term debt, less current maturities	1,268,373	930,858
Carrying Amount [Member] | Bonds [Member]
Debt Instrument [Line Items]
Unsecured debt	491,130	517,695
Carrying Amount [Member] | NPL other debt obligations [Member]
Debt Instrument [Line Items]
NPL other debt obligations	20,721	4,802
Carrying Amount [Member] | Debentures [Member]
Debt Instrument [Line Items]
Unamortized discount	(3,403)	(2,087)
Carrying Amount [Member] | Debentures [Member] | Notes, 7.625%, due 2012 [Member]
Debt Instrument [Line Items]
Notes payable		200,000
Carrying Amount [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Notes payable	125,000	125,000
Carrying Amount [Member] | Debentures [Member] | Notes, 6.1%, due 2041[Member]
Debt Instrument [Line Items]
Notes payable	125,000	125,000
Carrying Amount [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	250,000
Carrying Amount [Member] | Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Notes payable	75,000	75,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.59% Series, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable	25,000	25,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.78% Series, Due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	25,000	25,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.92% Series, Due 2027 [Member]
Debt Instrument [Line Items]
Notes payable	25,000	25,000
Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 6.76% Series, Due 2027 [Member]
Debt Instrument [Line Items]
Notes payable	7,500	7,500
Carrying Amount [Member] | Debentures [Member] | Notes Payable [Member]
Debt Instrument [Line Items]
Notes payable	654,097	605,413
Carrying Amount [Member] | Debentures [Member] | Revolving credit facility and commercial paper [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	111,000	109,000
Carrying Amount [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, Due 2028 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000	50,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000	50,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000	50,000
Carrying Amount [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Unsecured debt	50,000	50,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 6.10% 1999 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt		12,410
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.95% 1999 Series C, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt		14,320
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.55% 1999 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	8,270	8,270
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Debt Instrument [Line Items]
Unsecured debt	30,000	30,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured debt	20,000	20,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Debt Instrument [Line Items]
Unsecured debt	15,000	15,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Unsecured debt	65,000	65,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Unsecured debt	31,200	31,200
Carrying Amount [Member] | Fixed-rate bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Unsecured debt	100,000	100,000
Carrying Amount [Member] | Fixed-rate bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Unsecured debt	24,855	24,855
Market Value [Member] | NPL other debt obligations [Member]
Debt Instrument [Line Items]
IDRBs to be redeemed	20,991	4,814
Market Value [Member] | NPL credit facility [Member]
Debt Instrument [Line Items]
NPL credit facility	41,562	16,566
Market Value [Member] | Debentures [Member] | Notes, 7.625%, due 2012 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure		204,312
Market Value [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	141,771	128,673
Market Value [Member] | Debentures [Member] | Notes, 6.1%, due 2041[Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	165,779	143,074
Market Value [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	277,950
Market Value [Member] | Debentures [Member] | 8% Series, due 2026 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	111,501	96,340
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.59% Series, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	30,710	30,199
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.78% Series, Due 2022 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	34,637	31,932
Market Value [Member] | Debentures [Member] | Medium-term notes, 7.92% Series, Due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	36,953	31,648
Market Value [Member] | Debentures [Member] | Medium-term notes, 6.76% Series, Due 2027 [Member]
Debt Instrument [Line Items]
Notes payable, fair value disclosure	10,058	8,510
Market Value [Member] | Debentures [Member] | Revolving credit facility and commercial paper [Member]
Debt Instrument [Line Items]
Line of credit facility, fair value	111,000	109,000
Market Value [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, Due 2028 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	50,000	50,000
Market Value [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	50,000	50,000
Market Value [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	50,000	50,000
Market Value [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	50,000	50,000
Market Value [Member] | Fixed-rate bonds [Member] | 6.10% 1999 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value		12,410
Market Value [Member] | Fixed-rate bonds [Member] | 5.95% 1999 Series C, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value		14,449
Market Value [Member] | Fixed-rate bonds [Member] | 5.55% 1999 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	8,375	8,253
Market Value [Member] | Fixed-rate bonds [Member] | 5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	30,152	31,332
Market Value [Member] | Fixed-rate bonds [Member] | 5.25% 2003 Series D, due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	20,571	19,583
Market Value [Member] | Fixed-rate bonds [Member] | 5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	15,102	15,634
Market Value [Member] | Fixed-rate bonds [Member] | 5.25% 2004 Series A, due 2034 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	66,955	64,291
Market Value [Member] | Fixed-rate bonds [Member] | 5.00% 2004 Series B, due 2033 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	31,655	30,283
Market Value [Member] | Fixed-rate bonds [Member] | 4.85% 2005 Series A, due 2035 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	101,184	94,836
Market Value [Member] | Fixed-rate bonds [Member] | 4.75% 2006 Series A, due 2036 [Member]
Debt Instrument [Line Items]
Unsecured Debt Fair Value	$ 25,189	$ 23,179

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

12 Months Ended

Dec. 31, 2012

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.

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

	2012									2011									2010
	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)	$	(74,853	)	$	28,444		$	(46,409	)	$	(135,492	)	$	51,487		$	(84,005	)	$	(9,058	)	$	3,442		$	(5,616	)
Amortization of transition obligation		867			(329	)		538			867			(330	)		537			867			(329	)		538
Amortization of net actuarial (gain)/loss		25,597			(9,727	)		15,870			15,569			(5,916	)		9,653			12,122			(4,606	)		7,516
Prior service cost		(2,423	)		921			(1,502	)		—			—			—			—			—			—
Regulatory adjustment		42,771			(16,253	)		26,518			105,931			(40,254	)		65,677			652			(248	)		404
Pension plans other comprehensive income (loss)		(8,041	)		3,056			(4,985	)		(13,125	)		4,987			(8,138	)		4,583			(1,741	)		2,842
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		2,959			(1,125	)		1,834			(17,958	)		6,824			(11,134	)		(18,446	)		7,010			(11,436	)
Amounts reclassified into net income		2,801			(1,064	)		1,737			1,169			(444	)		725			97			(37	)		60
FSIRS other comprehensive income (loss)		5,760			(2,189	)		3,571			(16,789	)		6,380			(10,409	)		(18,349	)		6,973			(11,376	)
Total other comprehensive income (loss)	$	(2,281	)	$	867		$	(1,414	)	$	(29,914	)	$	11,367		$	(18,547	)	$	(13,766	)	$	5,232		$	(8,534	)

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

Approximately $2.1 million of realized losses (net of tax) related to the forward-starting interest rate swaps (“FSIRS”), reported in AOCI at December 31, 2012, will be reclassified into expense within the next twelve months as the related interest payments on long-term debt occur.

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	$	32,400
SERP net actuarial loss		1,000
PBOP net actuarial loss		1,000
PBOP prior service cost		400

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

AOCI – Rollforward

(Thousands of dollars)

	Defined Benefit Plans (Note 10)								FSIRS (Note 13)
	Before- Tax			Tax (Expense) Benefit		After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			AOCI
Beginning Balance AOCI December 31, 2011	$	(44,429	)	$	16,883	$	(27,546	)	$	(35,138	)	$	13,353		$	(21,785	)	$	(49,331	)
Current period other comprehensive income (loss)		(8,041	)		3,056		(4,985	)		5,760			(2,189	)		3,571			(1,414	)
Ending Balance AOCI December 31, 2012	$	(52,470	)	$	19,939	$	(32,531	)	$	(29,378	)	$	11,164		$	(18,214	)	$	(50,745	)

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, 2012 and 2011:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

	2012			2011
Net actuarial (loss) gain	$	(423,662	)	$	(374,406	)
Prior service cost		(2,423	)		—
Net transition obligation		—			(867	)
Less: amount recognized in regulatory assets		373,615			330,844
Recognized in AOCI	$	(52,470	)	$	(44,429	)

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

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Preferred Trust Securities and Subordinated Debentures

12 Months Ended

Dec. 31, 2012

Preferred Trust Securities and Subordinated Debentures

Note 6 – Preferred Trust Securities and Subordinated Debentures

In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures (“Subordinated Debentures”) to Trust II. The Subordinated Debentures became redeemable at the option of the Company in August 2008.

In February 2010, the Company notified holders of the Subordinated Debentures that all of these debentures (and the associated preferred and common securities) would be redeemed (at par) by the Company in March 2010. All of the outstanding Subordinated Debentures were redeemed in March 2010. The Company accomplished the redemption using existing cash and borrowings under the previous $300 million credit facility.

Interest payments and amortizations associated with the Subordinated Debentures are classified on the 2010 consolidated statement of income as Net interest deductions on subordinated debentures.

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Short-Term Debt

12 Months Ended

Dec. 31, 2012

Short-Term Debt

Note 8 — Short-Term Debt

As discussed in Note 7, Southwest replaced the existing $300 million credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Of the $300 million available under the facility, $150 million was designated by management for working capital purposes. The Company had no short-term borrowings outstanding at December 31 in either 2011 or 2012.

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Long-Term Debt - Estimated Maturities of Long-Term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Debt Instrument [Line Items]
2013	$ 50,137
2014	5,249
2015	46,705
2016	4,143
2017	$ 137,049

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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, 2012
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested/unissued, Number of Units, at beginning of year	361
Nonvested, Number of Units, Granted	105
Nonvested, Number of Units, Dividends	10
Nonvested, Number of Units, Forfeited or expired
Nonvested, Number of Units, Vested and issued	(128)
Nonvested/unissued, Number of Units, Ending balance	348
Weighted-average grant date fair value, Beginning balance	$ 30.66
Weighted-average grant date fair value, Granted	$ 41.34
Weighted-average grant date fair value, Dividends
Weighted-average grant date fair value, Forfeited or expired
Weighted-average grant date fair value, Vested and issued	$ 25.68
Weighted-average grant date fair value, Ending balance	$ 36.03
Restricted Stock/Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested/unissued, Number of Units, at beginning of year	176
Nonvested, Number of Units, Granted	94
Nonvested, Number of Units, Dividends	5
Nonvested, Number of Units, Forfeited or expired
Nonvested, Number of Units, Vested and issued	(68)
Nonvested/unissued, Number of Units, Ending balance	207
Weighted-average grant date fair value, Beginning balance	$ 32.65
Weighted-average grant date fair value, Granted	$ 41.34
Weighted-average grant date fair value, Dividends
Weighted-average grant date fair value, Forfeited or expired
Weighted-average grant date fair value, Vested and issued	$ 31.61
Weighted-average grant date fair value, Ending balance	$ 37.18

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Self-insured retention amount associated with general liability claims	$ 1
Additional self-insured retention amount of general liability	$ 5

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Segment Information - Accounts Receivable for Services (Detail) (NPL services [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
NPL services [Member]
Accounts receivable for NPL services	$ 8,179	$ 6,205

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Long-Term Debt - Summary of Effective Interest Rates on Variable-Rate IDRBs (Detail)	Dec. 31, 2012	Dec. 31, 2011
2003 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	1.71%	0.83%
2008 Series A, due 2038 [Member]
Debt Instrument [Line Items]
Effective interest rates	1.59%	1.62%
2009 Series A, due 2039 [Member]
Debt Instrument [Line Items]
Effective interest rates	1.14%	1.56%
Tax-exempt Series A, Due 2028 [Member]
Debt Instrument [Line Items]
Effective interest rates	1.25%	2.22%

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Income Taxes - Deferred Tax Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]
Deferred income taxes for future amortization of ITC	$ 3,211	$ 3,743
Employee benefits	27,097	24,605
Alternative minimum tax credit	18,467	17,411
Net operating losses and credits	36,206	59,096
Interest rate swap	11,164	13,352
Other	17,866	15,099
Valuation allowance	(141)	(142)
Deferred tax assets, total	113,870	133,164
Property-related items, including accelerated depreciation	652,380	611,022
Regulatory balancing accounts	2,498	743
Property-related items previously flowed through	1,729	2,797
Unamortized ITC	5,131	5,992
Debt-related costs	4,602	4,379
Other	16,626	11,914
Deferred tax liabilities, total	682,966	636,847
Net deferred tax liabilities	569,096	503,683
Current	(47,088)	(53,435)
Noncurrent	616,184	557,118
Net deferred tax liabilities	$ 569,096	$ 503,683

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Derivatives and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

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, 2012		December 31, 2011
Contract notional amounts		14,579		10,827

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, 2012, 2011, and 2010 and their location in the income statements (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	2012			2011			2010
Swaps	Net cost of gas sold	$	(4,854	)	$	(18,201	)	$	(27,690	)
Swaps	Net cost of gas sold		4,854	*		18,201	*		27,690	*
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, 2012		Year Ended December 31, 2011
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	2,959	$	(17,958	)

Fair Values of Swaps and FSIRS in Balance Sheet Location

The following table sets forth the fair values of the Company’s Swaps and FSIRS and their location in the balance sheets (thousands of dollars):

Fair values of derivatives not designated as hedging instruments:

December 31, 2012 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	132	$	(126	)	$	6
Swaps	Other current liabilities		391		(2,467	)		(2,076	)
Swaps	Other deferred credits		233		(552	)		(319	)
Total		$	756	$	(3,145	)	$	(2,389	)

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(11,122	)	$	(11,122	)
Swaps	Other deferred credits		—		(621	)		(621	)
Total		$	—	$	(11,743	)	$	(11,743	)

Fair values of derivatives designated as hedging instruments:

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other current liabilities	$	—	$	(24,713	)	$	(24,713	)

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, 2012		Year ended December 31, 2011		Year ended December 31, 2010
(Thousands of dollars)
Paid to counterparties	$	14,843	$	17,283	$	16,574
Received from counterparties	$	634	$	—	$	831

Regulatory Assets/Liabilities Offsetting the Derivatives at Fair Value in the Balance Sheet

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

December 31, 2012
Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(6	)
Swaps	Prepaids and other current assets		2,076
Swaps	Deferred charges and other assets		319

December 31, 2011
Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	11,122
Swaps	Deferred charges and other assets		621

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:

Level 2 - Significant other observable inputs

	December 31, 2012			December 31, 2011
(Thousands of dollars)
Assets at fair value:
Deferred charges and other assets - Swaps	$	6		$	—
Liabilities at fair value:
Other current liabilities - Swaps		(2,076	)		(11,122	)
Other deferred credits - Swaps		(319	)		(621	)
Other current liabilities - FSIRS		—			(24,713	)
Net Assets (Liabilities)	$	(2,389	)	$	(36,456	)

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	$ 476,720	$ 415,309
Net regulatory assets	102,480	82,106
Accrued pension and other postretirement benefit costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	373,615	330,844
Unrealized net loss on non-trading derivatives (Swaps) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	2,395	11,743
Deferred purchased gas costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	6,031	2,323
Regulatory liabilities, total	(98,957)	(72,426)
Accrued purchased gas costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	30,300	18,400
Unamortized premium on reacquired debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	19,452	19,011
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, total	44,927	32,988
Accumulated removal costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(256,000)	(233,000)
Unrealized net gain on non-trading derivatives (Swaps) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(6)
Deferred gain on southern Nevada division operations facility [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(392)	(806)
Unamortized gain on reacquired debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	(11,934)	(12,470)
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, total	$ (6,951)	$ (14,501)

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Derivatives and Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Derivatives and Fair Value Measurements

Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2013 through March 2015. 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, 2012		December 31, 2011
Contract notional amounts		14,579		10,827

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, 2012, 2011, and 2010 and their location in the income statements (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	2012			2011			2010
Swaps	Net cost of gas sold	$	(4,854	)	$	(18,201	)	$	(27,690	)
Swaps	Net cost of gas sold		4,854	*		18,201	*		27,690	*
Total		$	—		$	—		$	—

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

In January 2010, Southwest entered into two FSIRS to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt that matured in February 2011 and $200 million that matured in May 2012. The counterparties to each agreement were four major banking institutions. The first FSIRS was a designated cash flow hedge and terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. The second FSIRS was also a designated cash flow hedge and had a notional amount of $100 million. It terminated in March 2012 concurrent with the related issuance of $250 million 3.875% 10-year Senior Notes. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss was recognized in income (ineffective portion) for either FSIRS during any period, including the periods presented in the following table.

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

	Year Ended December 31, 2012		Year Ended December 31, 2011
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	2,959	$	(17,958	)

The following table sets forth the fair values of the Company’s Swaps and FSIRS and their location in the balance sheets (thousands of dollars):

Fair values of derivatives not designated as hedging instruments:

December 31, 2012 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	132	$	(126	)	$	6
Swaps	Other current liabilities		391		(2,467	)		(2,076	)
Swaps	Other deferred credits		233		(552	)		(319	)
Total		$	756	$	(3,145	)	$	(2,389	)

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(11,122	)	$	(11,122	)
Swaps	Other deferred credits		—		(621	)		(621	)
Total		$	—	$	(11,743	)	$	(11,743	)

Fair values of derivatives designated as hedging instruments:

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other current liabilities	$	—	$	(24,713	)	$	(24,713	)

As noted above, the FSIRS that remained at December 31, 2011 terminated in March 2012.

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.

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, 2012		Year ended December 31, 2011		Year ended December 31, 2010
(Thousands of dollars)
Paid to counterparties	$	14,843	$	17,283	$	16,574
Received from counterparties	$	634	$	—	$	831

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

December 31, 2012
Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(6	)
Swaps	Prepaids and other current assets		2,076
Swaps	Deferred charges and other assets		319

December 31, 2011
Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	11,122
Swaps	Deferred charges and other assets		621

Fair Value Measurements.    The estimated fair values of Southwest’s Swaps were determined at December 31, 2012 and 2011 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 estimated fair value of Southwest’s FSIRS at December 31, 2011 was determined using a discounted cash flow model that utilized forward interest rate curves. The inputs to the model were the terms of the FSIRS. These Level 2 inputs were observable in the marketplace throughout the full term of the FSIRS, but were credit-risk adjusted with no significant impact to the overall fair value measure. See Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income (“AOCI”) for more information on the FSIRS.

See Note 10 – Pension and Other Postretirement Benefits for definitions of the levels of the fair value hierarchy. 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:

Level 2 - Significant other observable inputs

	December 31, 2012			December 31, 2011
(Thousands of dollars)
Assets at fair value:
Deferred charges and other assets - Swaps	$	6		$	—
Liabilities at fair value:
Other current liabilities - Swaps		(2,076	)		(11,122	)
Other deferred credits - Swaps		(319	)		(621	)
Other current liabilities - FSIRS		—			(24,713	)
Net Assets (Liabilities)	$	(2,389	)	$	(36,456	)

No financial assets or liabilities accounted for at fair value fell within Level 1 or Level 3 of the fair value hierarchy.

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Utility Plant (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Net Utility Plant

Net utility plant as of December 31, 2012 and 2011 was as follows (thousands of dollars):

December 31,	2012			2011
Gas plant:
Storage	$	20,503		$	20,496
Transmission		301,505			295,103
Distribution		4,224,560			4,048,078
General		310,936			291,639
Other		161,996			155,734
		5,019,500			4,811,050
Less: accumulated depreciation		(1,750,795	)		(1,638,091	)
Acquisition adjustments, net		911			1,091
Construction work in progress		74,178			44,894
Net utility plant	$	3,343,794		$	3,218,944

Schedule of Depreciation and Amortization Expense

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

	2012		2011		2010
Depreciation and amortization expense	$	182,612	$	172,712	$	167,050

Schedule of Rental Payments and Current Term Expiration Dates

The table below presents the rental payments and the current term expiration dates, although both leases have optional renewal terms available.

	2013		2014		2015		2016		2017
(In thousands)
Corporate headquarters (expires in 2017)	$	2,140	$	2,190	$	2,270	$	2,343	$	1,194
Phoenix administrative offices (expires in 2014)		1,446		243		—		—		—

Schedule of Rental Payments for Operating Leases

The table below presents Southwest rental payments and NPL lease payments that are included in operating expenses for all operating leases (in thousands):

	2012		2011		2010
Southwest Gas	$	7,762	$	7,812	$	7,585
NPL		24,054		19,017		11,780
Consolidated rental payments/lease expense	$	31,816	$	26,829	$	19,365

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, 2012 (thousands of dollars):

Year Ending December 31,
2013	$	6,757
2014		4,304
2015		3,181
2016		2,510
2017		1,238
Thereafter		61
Total minimum lease payments	$	18,051

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Derivatives and Fair Value Measurements - Notional Amounts Under Swaps Contracts (Detail)	Dec. 31, 2012 MMBTU	Dec. 31, 2011 MMBTU
Derivative [Line Items]
Contract notional amounts	14,579,000	10,827,000

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Receivables and Related Allowances - Schedule of Percent of Customers by State (Detail)	12 Months Ended
	Dec. 31, 2012
Arizona [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	54.00%
Nevada [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	36.00%
California [Member]
Receivables And Related Allowances [Line Items]
Percent of customers by state	10.00%

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Summary of Significant Accounting Policies - Other Income (Deductions) (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in COLI policies	$ 6,600	$ 700	$ 9,770
Interest income	924	485	194
Pipe replacement costs	(2,680)	(4,761)	(5,024)
Miscellaneous income and (expense)	(433)	(1,836)	(1,090)
Total other income (deductions)	$ 4,411	$ (5,412)	$ 3,850

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 132,639	$ 111,763	$ 103,453
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)	(46,409)	(84,005)	(5,616)
Amortization of transition obligation	538	537	538
Amortization of net actuarial loss	15,870	9,653	7,516
Prior service cost	(1,502)
Regulatory adjustment	26,518	65,677	404
Net defined benefit pension plans	(4,985)	(8,138)	2,842
Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 13)	1,834	(11,134)	(11,436)
Amounts reclassified into net income (Notes 5 and 13)	1,737	725	60
Net forward-starting interest rate swaps	3,571	(10,409)	(11,376)
Total other comprehensive income (loss), net of tax	(1,414)	(18,547)	(8,534)
Comprehensive income	131,225	93,216	94,919
Comprehensive income (loss) attributable to noncontrolling interest	(692)	(524)	(424)
Comprehensive income attributable to Southwest Gas Corporation	$ 131,917	$ 93,740	$ 95,343

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Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Income Taxes [Line Items]
Unrecognized tax benefits at beginning of year	$ 1,445
Gross increases - tax positions in prior period
Gross decreases - tax positions in prior period
Gross increases - current period tax positions
Gross decreases - current period tax positions
Settlements
Lapse of statute of limitations	(1,445)
Unrecognized tax benefits at end of year

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Utility Plant

12 Months Ended

Dec. 31, 2012

Utility Plant

Note 2 – Utility Plant

Net utility plant as of December 31, 2012 and 2011 was as follows (thousands of dollars):

December 31,	2012			2011
Gas plant:
Storage	$	20,503		$	20,496
Transmission		301,505			295,103
Distribution		4,224,560			4,048,078
General		310,936			291,639
Other		161,996			155,734
		5,019,500			4,811,050
Less: accumulated depreciation		(1,750,795	)		(1,638,091	)
Acquisition adjustments, net		911			1,091
Construction work in progress		74,178			44,894
Net utility plant	$	3,343,794		$	3,218,944

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

	2012		2011		2010
Depreciation and amortization expense	$	182,612	$	172,712	$	167,050

Operating Leases and Rentals.    Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The table below presents the rental payments and the current term expiration dates, although both leases have optional renewal terms available.

	2013		2014		2015		2016		2017
(In thousands)
Corporate headquarters (expires in 2017)	$	2,140	$	2,190	$	2,270	$	2,343	$	1,194
Phoenix administrative offices (expires in 2014)		1,446		243		—		—		—

In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases and, for the gas segment, are also treated as such for regulatory purposes. NPL has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest rental payments and NPL lease payments that are included in operating expenses for all operating leases (in thousands):

	2012		2011		2010
Southwest Gas	$	7,762	$	7,812	$	7,585
NPL		24,054		19,017		11,780
Consolidated rental payments/lease expense	$	31,816	$	26,829	$	19,365

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, 2012 (thousands of dollars):

Year Ending December 31,
2013	$	6,757
2014		4,304
2015		3,181
2016		2,510
2017		1,238
Thereafter		61
Total minimum lease payments	$	18,051

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Net actuarial (loss) gain	$ 74,853	$ 135,492	$ 9,058
Prior service cost	2,423
Less: amount recognized in regulatory assets	476,720	415,309
Recognized in AOCI	52,470	44,429
Defined Benefit Plans [Member]
Net actuarial (loss) gain	(423,662)	(374,406)
Prior service cost	(2,423)
Net transition obligation		(867)
Less: amount recognized in regulatory assets	373,615	330,844
Recognized in AOCI	$ (52,470)	$ (44,429)

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding and exercisable	$ 1,788	$ 2,697	$ 3,186
Exercised	$ 928	$ 1,949	$ 1,689

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Pension and Other Postretirement Benefits - Schedule of Allocation of Plan Assets (Detail)	12 Months Ended
	Dec. 31, 2012
Equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Investment percentage range, minimum	59.00%
Investment percentage range, maximum	71.00%
Debt securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Investment percentage range, minimum	31.00%
Investment percentage range, maximum	37.00%
Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Investment percentage range, maximum	5.00%

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Receivables and Related Allowances (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Accounts Receivable

The table below contains information about the gas utility customer accounts receivable balance at December 31, 2012

Gas utility customer accounts receivable balance (in thousands) $ 94,695

Schedule of Percent of Customers by State

The table below contains information about the the percentage of customers in each of the three states at December 31, 2012.

	December 31, 2012
Percent of customers by state
Arizona		54	%
Nevada		36	%
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, 2009	$	3,953
Additions charged to expense		2,646
Accounts written off, less recoveries		(3,405	)
Balance, December 31, 2010		3,194
Additions charged to expense		2,678
Accounts written off, less recoveries		(2,690	)
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

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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, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%	5.00%
Expected return on plan assets	8.00%	8.00%
Weighted-average rate of compensation increase	2.75%	3.00%
Qualified retirement plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 20,319	$ 17,725	$ 16,932
Interest cost	38,266	37,276	35,614
Expected return on plan assets	(45,780)	(40,114)	(36,538)
Amortization of net actuarial loss	23,883	14,348	10,478
Net periodic benefit cost	36,688	29,235	26,486
Qualified retirement plan [Member] | Net benefit cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	5.75%	6.00%
Expected return on plan assets	8.00%	8.00%	8.00%
Weighted-average rate of compensation increase	3.00%	3.25%	3.25%
SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	274	217	372
Interest cost	1,629	1,766	2,045
Amortization of net actuarial loss	683	631	1,155
Net periodic benefit cost	2,586	2,614	3,572
SERP [Member] | Net benefit cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	5.75%	6.00%
Expected return on plan assets	8.00%	8.00%	8.00%
Weighted-average rate of compensation increase	3.00%	3.25%	3.25%
PBOP [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	977	858	856
Interest cost	2,547	2,631	2,491
Expected return on plan assets	(2,404)	(2,379)	(2,093)
Amortization of transition obligation	867	867	867
Amortization of net actuarial loss	1,031	590	489
Net periodic benefit cost	$ 3,018	$ 2,567	$ 2,610
PBOP [Member] | Net benefit cost [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	5.75%	6.00%
Expected return on plan assets	8.00%	8.00%	8.00%
Weighted-average rate of compensation increase	3.00%	3.25%	3.25%

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Summary of Significant Accounting Policies - Schedule of Other Property and Investments (Detail) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Net cash surrender value of COLI policies	$ 80,000,000	$ 74,000,000
Other property	11,000,000	9,000,000
Total	242,096,000	192,004,000
NPL Construction Co [Member]
NPL property and equipment	287,000,000	237,000,000
Accumulated provision for depreciation and amortization	$ (136,000,000)	$ (128,000,000)

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes

Note 12 – Income Taxes

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is subject to examinations by the Internal Revenue Service for years after 2008, and is subject to examination by the various state taxing authorities for years after 2007.

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):

	2012		2011		2010
Tax-related interest income	$	24	$	100	$	500

Tax-related interest receivable and payable included in the consolidated balance sheets are shown in the table below (in thousands):

	2012		2011
Tax-related interest receivable (payable)	$	—	$	6

The Company had no uncertain tax liabilities at December 31, 2012, or at any time during 2012. The Company expects no change in unrecognized tax benefits in the next twelve months.

A reconciliation of the beginning and ending amount of unrecognized tax benefits in 2011 is as follows (thousands of dollars):

	2011
Unrecognized tax benefits at beginning of year	$	1,445
Gross increases – tax positions in prior period		—
Gross decreases – tax positions in prior period		—
Gross increases – current period tax positions		—
Gross decreases – current period tax positions		—
Settlements		—
Lapse of statute of limitations		(1,445	)
Unrecognized tax benefits at end of year	$	—

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

Year Ended December 31,	2012		2011			2010
Current:
Federal	$	2,296	$	(265	)	$	4,204
State		5,744		2,122			4,442
		8,040		1,857			8,646
Deferred:
Federal		65,551		58,584			44,778
State		1,685		2,862			1,501
		67,236		61,446			46,279
Total income tax expense	$	75,276	$	63,303		$	54,925

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

Year Ended December 31,	2012			2011			2010
Deferred federal and state:
Property-related items	$	64,249		$	51,710		$	43,420
Purchased gas cost adjustments		1,755			(92	)		(315	)
Employee benefits		564			11,766			8,753
All other deferred		1,529			(1,070	)		(4,711	)
Total deferred federal and state		68,097			62,314			47,147
Deferred ITC, net		(861	)		(868	)		(868	)
Total deferred income tax expense	$	67,236		$	61,446		$	46,279

The consolidated effective income tax rate for the period ended December 31, 2012 and the two prior periods differ from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:

Year Ended December 31,	2012			2011			2010
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.6			2.7			2.8
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		—			(0.9	)		(0.3	)
Tax credits		(0.4	)		(0.6	)		(0.5	)
Company owned life insurance		(1.3	)		(0.1	)		(2.3	)
All other differences		0.1			(0.1	)		(0.2	)
Consolidated effective income tax rate		36.2	%		36.2	%		34.7	%

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

December 31,	2012			2011
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	3,211		$	3,743
Employee benefits		27,097			24,605
Alternative minimum tax credit		18,467			17,411
Net operating losses and credits		36,206			59,096
Interest rate swap		11,164			13,352
Other		17,866			15,099
Valuation allowance		(141	)		(142	)
		113,870			133,164
Deferred tax liabilities:
Property-related items, including accelerated depreciation		652,380			611,022
Regulatory balancing accounts		2,498			743
Property-related items previously flowed through		1,729			2,797
Unamortized ITC		5,131			5,992
Debt-related costs		4,602			4,379
Other		16,626			11,914
		682,966			636,847
Net deferred tax liabilities	$	569,096		$	503,683
Current	$	(47,088	)	$	(53,435	)
Noncurrent		616,184			557,118
Net deferred tax liabilities	$	569,096		$	503,683

At December 31, 2012, the Company has a federal net operating loss carryforward of $103 million and a federal general business credit carryforward of $306,000, both of which expire in 2031. The Company also has a net capital loss carryforward of $320,000, which expires in 2016. The Company also has charitable contribution carryforwards of $892,000 and $743,000, which expire in 2016 and 2017, respectively. On January 2, 2013, the American Taxpayer Relief Act of 2012 (“Taxpayer Relief Act”) was signed into law. The Taxpayer Relief Act extended the availability of the 50% bonus depreciation deduction through 2013. As a result, the Company will not utilize any of the current alternative minimum tax credit in 2013.

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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, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Net Assets (Liabilities)	$ (2,389)	$ (36,456)
Swaps [Member] | Deferred charges and other assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets	6
Swaps [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	(2,076)	(11,122)
Swaps [Member] | Other deferred credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities	(319)	(621)
FSIRS [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities		$ (24,713)