SEC Filing | Southwest Gas Holdings

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Form 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, 2011

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:

$1,771,400,314 as of June 30, 2011

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 46,093,472 shares as of February 15, 2012

DOCUMENTS INCORPORATED BY REFERENCE

Description

Part Into Which Incorporated

Annual Report to Shareholders for the Year Ended December 31, 2011

2012 Proxy Statement

Parts I, II, and IV

Part III

TABLE OF CONTENTS

PART I


		PAGE

Item 1.	BUSINESS	1

	Natural Gas Operations	1

	General Description	1

	Rates and Regulation	2

	Demand for Natural Gas	3

	Natural Gas Supply	4

	Competition	5

	Environmental Matters	5

	Employees	6

	Construction Services	6

Item 1A.	RISK FACTORS	7

Item 1B.	UNRESOLVED STAFF COMMENTS	10

Item 2.	PROPERTIES	10

Item 3.	LEGAL PROCEEDINGS	10

Item 4.	MINE SAFETY DISCLOSURES	11

Item 4A.	EXECUTIVE OFFICERS OF THE REGISTRANT	11

	PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	11

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	13

	PART III

Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	14

Item 11.	EXECUTIVE COMPENSATION	15

Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	15

Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	17

Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	17

	PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	17

	List of Exhibits	18

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 in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

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 2011 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, 2011, Southwest purchased and distributed or transported natural gas to 1,859,000 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 13,000 first-time meter sets over the last twelve months. These meter sets led to 22,000 net additional active customers during 2011, an increase of 1%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Given the current housing and economic environment, management expects customer growth associated with new meter sets will be 1% or less in the near term. Management cannot predict the timing of when currently idle and vacant homes will return to service, but is encouraged by the progress in 2011.

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, 2011	86%	4%	10%
December 31, 2010	86%	4%	10%
December 31, 2009	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 44% of total system throughput in 2011. Customers who utilized this service transported 94 million dekatherms in 2011, 100 million dekatherms in 2010, and 104 million dekatherms in 2009. 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 a 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 Lake Tahoe and North Lake Tahoe, 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.

In California, CPUC regulations allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption. In Nevada, a decoupled rate structure applies to most customer classes, providing stability in annual operating margin. In Arizona, Southwest filed a general rate case in November 2010 and requested a rate structure to decouple recovery of the Company’s fixed costs from fluctuations in usage, and enable the Company to aggressively advocate for increased energy efficiency by its customers, which was approved in December 2011 effective January 2012.

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 2011 Annual Report to Shareholders.

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


Ratemaking Area	Type of Filing	Month Filed	Month Final Rates Effective
Arizona:	General rate case	November 2010	January 2012
California:
Northern and Southern	Annual attrition	October 2011	January 2012
Northern and Southern	General rate case	December 2007	January 2009
Nevada:
Northern and Southern	General rate case	April 2009	November 2009
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 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.

While weather-related curtailments are rare, Southwest did experience customer outages during two days in February 2011 in the Tucson and Sierra Vista areas of southern Arizona. These outages were the culmination of multiple factors. The delivery of natural gas to Southwest’s distribution system was severely limited due to extreme weather conditions and rolling power outages in Texas, which impacted production capabilities where Southwest procures its natural gas supplies for Arizona. In addition, the interstate pipelines transporting natural gas to Arizona experienced significant supply loss and the extremely cold weather also led to peak natural gas demand. These factors caused pressure and deliverability issues across the southern portion of the western interstate pipeline systems in Arizona, Texas, and New Mexico. The outage impacted approximately 20,000 customers and service was restored quickly.

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 gas acquisition objective is to ensure that adequate supplies of natural gas are available at the best cost. Gas is acquired from a wide variety of sources and a mix of purchase provisions, including spot market purchases and firm supplies with a variety of terms. During 2011, Southwest acquired natural gas from 39 suppliers. Southwest regularly monitors the number of suppliers, their quality, 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 for customer supplies.

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

To mitigate customer exposure to short-term market price volatility, Southwest seeks to fix the price on a portion (currently ranging from 25% to 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. For the 2011/2012 heating season, fixed-price contracts ranged in price from approximately $4 to $7 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 or day of purchase.

The firm gas supply arrangements are structured such that a stated volume of 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.

Southwest’s price volatility mitigation program includes the use of financial derivatives for the Arizona and Nevada jurisdictional areas. The combination of fixed-price contracts and these financial derivatives is designed to increase flexibility for Southwest and increase supplier diversification. The cost of such financial derivatives is recovered from customers through PGA mechanisms in each jurisdictional area.

Storage availability can influence the average annual price of gas, as storage allows a company to purchase natural gas in larger 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. A contract with Southern California Gas Company is intended for delivery only within Southwest’s southern California rate jurisdiction. In addition, a contract with Paiute for its LNG facility allows for peaking capability only in northern Nevada and northern California. Gas is purchased for injection during the off-peak period for use in the high demand months, but is limited in its 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. As such, this storage provides limited operational flexibility to adjust daily flowing supplies to meet demand, as permitted by conditions on NWPL’s system, and has limited impact on the overall price of gas supplies.

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 gas from Rocky Mountain producing areas and from Canada.

The landscape for national gas supply has changed dramatically during the last two years. Advanced drilling techniques have provided access to new, abundant, and sustainable 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 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 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 and also has interruptible contracts in place that allow the transportation of additional gas supplies.

Southwest believes that the current levels of contracted firm interstate capacity are sufficient to serve each of its service territories under normal circumstances. As the need arises to acquire additional capacity on one of the interstate pipeline transmission systems, primarily due to customer growth, Southwest will continue to consider available options to obtain that capacity, either through the use of firm contracts with a pipeline company or by purchasing capacity on the open market.

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 finds, 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; 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 EPA requires annual reporting from large facilities with combustion emissions exceeding 25,000 tons per year. The Company completed GHG inventories for all Southwest and Paiute facilities, based on California emission reporting protocols. These inventories and direct measurement required by the EPA’s GHG Mandatory Reporting Regulations showed that Southwest and Paiute do not operate, control, or own any facilities which have the potential to exceed the 25,000 tons per year threshold.

In 2010, the Company began reporting to the EPA under the Mandatory Reporting Rule (“MRR”) the volumes of natural gas received for distribution to LDC customers. While some parts of the MRR do not apply to Southwest, other

required information is already being reported to the Department of Transportation or is available in existing Company databases. A recent addition to the MRR will require the Company to implement new methods for inventorying pipeline components and creating or modifying an existing data management system. The Company is in the process of identifying the most feasible procedures for collecting the information required by this new regulation, but does not expect to incur any material expenditures for compliance with any MRR requirements. The Company is also monitoring other climate legislation which may trigger additional reporting requirements or have financial implications.

Employees

At December 31, 2011, the natural gas operations segment had 2,298 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 energy services contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for 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 business operations is main and service replacement as well as new business installations. 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. Effective February 2010, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration issued an Integrity Management Program for Gas Distribution Pipelines. This program, known as DIMP, 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. Finally, funding for planned replacement projects increased due to the 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 multi-year, and the amount of work completed by NPL will vary from year to year.

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 2011, approximately 88% of revenue was earned under unit-price contracts. As of December 31, 2011, no significant backlog existed with respect to outstanding 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 competitors in what has been a largely fragmented industry. Several 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 2011, NPL served 64 major customers, with Southwest accounting for approximately 19% of NPL revenues. Additionally, one customer accounted for approximately 11% of total revenue, while six other customers individually accounted for 5% or more of NPL revenues. NPL’s largest customers are long-term customers.

Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2011, NPL had 3,456 regular full-time equivalent employees. Employment peaked in November 2011 when there were 3,489 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 19 field locations with corporate headquarters located in Phoenix, Arizona. Buildings are normally leased from third parties. The lease terms are typically five years or less. Field location facilities consist of a small building for repairs and land to store equipment.

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 (“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.

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 current economic slowdown in the United States, and particularly in our service areas, has resulted in a marked decline in the new housing market and increases in the inventory of idle/vacant homes. Commercial entities (including restaurants and other service establishments) are also being impacted, resulting in reductions in operations or closures. In addition, a prolonged economic downturn could result in customers voluntarily reducing consumption. If these trends continue, 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, 2011 of approximately $227 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 $74 million at December 31, 2011 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 2011, Southwest recognized $700,000 in Other income (deductions) due to net death benefits recognized, which offset net decreases in the cash surrender values of its company-owned life insurance policies (compared to an increase of $9.8 million, including net death benefits, in 2010). 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 2012, 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 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.

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, 2011 was $4.9 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.

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

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

Southwest operates two primary pipeline transmission systems:

•

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

•

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

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

Information on properties of NPL can be found on page 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, 2012, there were 16,668 holders of record of common stock, and the market price of the common stock was $41.86. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2011 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

In February 2012, the Board of Directors (“Board”) increased the quarterly dividend payout to 29.5 cents per share, effective with the June 2012 payment. This marks the sixth consecutive year in which the dividend was increased. In reviewing dividend policy, the Board considers the adequacy and sustainability of the 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 23.75 cents per share throughout 2009, 25 cents per share throughout 2010, and 26.5 cents per share throughout 2011.

Item 6.

SELECTED FINANCIAL DATA

Information required by this item is included in the 2011 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 2011 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 volatility is expected to continue into 2012 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 purchase 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. As of January 2012, 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, the ACC recently approved a fully decoupled rate structure with a monthly weather normalization provision effective January 2012.

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 $100 million of variable-rate Industrial Development Revenue Bonds (“IDRBs”) are tracked and recovered from ratepayers through an interest balancing account, which mitigates risk to earnings and cash flows from interest rate fluctuations on these IDRBs between general rate cases. As of December 31, 2011 and 2010, Southwest had $209 million and $100 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.

The Company is also exposed to interest rate risk associated with new debt financing needed to fund maturities of long-term debt. Southwest has $200 million of long-term debt maturing in May 2012 and plans to fund that obligation by issuing at least $200 million of debentures by the maturity date. In connection with the planned debt issuance, the Company, in January 2010, entered into a forward-starting interest rate swap (“FSIRS”) agreement to hedge the risk of interest rate variability during the period leading up to the planned issuance. The counterparties to the agreement comprise four major banking institutions. The FSIRS has a notional amount of $100 million (with Southwest as the fixed-rate payer at a rate of 4.78%) and has a mandatory termination date on or before March 20, 2012. Southwest designated the FSIRS agreement as a cash flow hedge of forecasted future interest payments.

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

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements of Southwest Gas Corporation and Notes thereto, together with the report of PricewaterhouseCoopers LLP, are included in the 2011 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, 2011, 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 2011 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 75.

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 2011 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 76.

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

On February 24, 2012, the Board of Directors (the “Board”) of the Company approved a Change in Control Agreement (the “Change in Control Agreement”) with Jeffrey W. Shaw, the Company’s Chief Executive Officer. The Change in Control Agreement will be effective June 1, 2012, following the expiration of Mr. Shaw’s existing employment agreement (the “Expiring Agreement”).

The Change in Control Agreement is in substantially the same form as the change in control agreements between the Company and its other executive officers, has a term of three years with no automatic extension and does not provide any benefits if Mr. Shaw is terminated for cause or if he is terminated without cause in the absence of a change in control. The Change in Control Agreement has a so-called “double trigger” which provides severance benefits if within 24 months after a change in control, Mr. Shaw terminates his employment with the Company for good reason or the Company terminates his employment other than for death, disability or cause (each, a “Termination Event”); provided that Mr. Shaw signs a release of claims against the Company. The lump-sum severance payment is equal to the sum of 36 months base salary, an award opportunity at 100% of target for incentive plans, and an amount equal to the full cost of medical and dental COBRA insurance and replacement disability and life insurance. The severance benefits also include the acceleration of vesting of outstanding equity awards, the payment of benefits under the Company’s Supplemental Executive Retirement Plan (the “SERP”) plus 6 vesting points toward age and/or service requirements under the SERP, and the reimbursement of up to $30,000 for outplacement services. The Change in Control Agreement provides for a modified golden parachute cutback provision, meaning that if the golden parachute excise tax would be assessed on payments or other benefits received in connection with a change in control, Mr. Shaw would be entitled to receive: (i) the full aggregate amount of payments and other benefits to which he is entitled or (ii) an amount equal to one dollar less than three times Mr. Shaw’s “base amount,” whichever results in Mr. Shaw’s receipt of the largest aggregate amount, taking into account all applicable federal, state, and local taxes. The Change in Control Agreement does not contain a tax gross-up for excise tax.

The Company and Mr. Shaw also entered into a letter agreement, which will also be effective June 1, 2012 (the “Letter Agreement”), to provide Mr. Shaw with post-termination benefits upon the occurrence of a Termination Event in the absence of a change in control. If such a Termination Event occurs, Mr. Shaw would receive a lump-sum payment equal to 12 months of base salary, plus incentive compensation for the period during the applicable plan year preceding the date of termination and for a period of 12 months following the date of such termination. The severance benefits also include the acceleration of vesting of outstanding equity awards and up to an additional 2 years toward the age assumption for eligibility, vesting and calculation of benefits under the SERP. The Letter Agreement does not provide any special welfare or fringe benefits. The Letter Agreement will terminate on Mr. Shaw’s 55th birthday (November 9, 2013).

The Change in Control Agreement and the Letter Agreement, collectively, provide for the following reductions in benefits as compared to the Expiring Agreement:

•

Replacement of the tax gross-up for excise tax with a modified cutback provision;

•

Reduction in SERP vesting points (reduced from 15 to 6 following a change in control and from 15 to 2 in the absence of a change in control); and

•

Reduction of fringe benefits included in severance payments (which previously included a payment of 20% of base salary for the severance period and covered certain anticipated expenses for relocation, office space and secretarial services).

The foregoing descriptions of the Change in Control Agreement and Letter Agreement are qualified in their entirety by references to the terms of the Change in Control Agreement and Letter Agreement, copies of which are attached to this Form 10-K as Exhibits 10.23 and 10.24, respectively, and incorporated herein by reference.

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 2012 Proxy Statement, which by this reference is incorporated herein.

(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, 2011 are as follows:


Jeffrey W. Shaw	53	Chief Executive Officer	2007-Present
James P. Kane	65	President	2007-Present
Roy R. Centrella	54	Senior Vice President/Chief Financial Officer	2010-Present
		Vice President/Controller and Chief Accounting Officer	2007-2010
Eric DeBonis	44	Senior Vice President/Staff Operations & Technology	2011-Present
		Vice President/Special Projects	2010-2011
		Vice President/Central Arizona Division	2008-2010
		General Manager/East Region/Central Arizona Division	2007-2008
		Director/Gas Operations/Central Arizona Division	2007
John P. Hester	49	Senior Vice President/Regulatory Affairs & Energy Resources	2007-Present
Edward A. Janov	57	Senior Vice President/Corporate Development	2010-Present
		Senior Vice President/Finance	2007-2010
Karen S. Haller	48	Vice President/General Counsel, Compliance Officer,
		and Corporate Secretary	2010-Present
		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	2007-2008
Kenneth J. Kenny	49	Vice President/Finance/Treasurer	2010-Present
		Vice President/Treasurer	2007-2010
Laura Lopez Hobbs	52	Vice President/Administration	2010-Present
		Vice President/Human Resources	2008-2010
		Director/Human Resources	2007-2008
Gregory J. Peterson	52	Vice President/Controller and Chief Accounting Officer	2010-Present
		Assistant Controller	2007-2010

(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 2012 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 2012 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 2012 Proxy Statement, which by this reference is incorporated herein.

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

Section 16(a) Beneficial Ownership Reporting Compliance. The Company has adopted procedures to assist its directors and executive officers in complying with Section 16(a) of the Exchange Act which includes assisting in the preparation of forms for filing. Based upon a review of filings with the SEC and written representations that no other reports were required, the Company believes that all of its directors and executive officers complied during 2011 with the reporting requirements of Section 16(a) of the Exchange Act, except for the following Form 4s:

The purchase of Company common stock by director Thomas A. Thomas of 300 shares on June 20, 2011 was reported on June 30, 2011 and his purchase of 500 shares on August 11, 2011 was reported on August 30, 2011.

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 2012 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 2012 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 2012 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 2012 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 2012 Proxy Statement, which by this reference is incorporated herein.

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

At December 31, 2011, the Company had three stock-based compensation plans. With respect to the first plan, the Company previously granted options to purchase shares of common stock to key employees and outside directors. The option grants in 2006 consumed the remaining options that could be issued under the option plan and no future grants are anticipated.


Equity Compensation Plan Information
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance (excluding securities reflected in column a)
	(a)		(b)		(c)
(Thousands of shares)
Equity compensation plans approved by security holders		177	$	27.28		-
Equity compensation plans not approved by security holders		-		-		-

Total		177	$	27.28		-

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		361	$	30.66		322
Equity compensation plans not approved by security holders		-		-		-

Total		361	$	30.66		322

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		176	$	32.65		66
Equity compensation plans not approved by security holders		-		-		-

Total		176	$	32.65		66

Additional information regarding the three equity compensation plans is included in Note 11 of the Notes to Consolidated Financial Statements in the 2011 Annual Report to Shareholders.

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information with respect to certain relationships and related transactions, and director independence is set forth under the heading “Governance of the Company” in the definitive 2012 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 2012 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 2011 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			45
Management’s Report on Internal Control Over Financial Reporting			75
Report of Independent Registered Public Accounting Firm			76

(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.

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 November 15, 2011, 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.

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.

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		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.

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.

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 *		Southwest Gas Corporation 2006 Restricted Stock/Unit Plan, amended and restated January 17, 2012.

10.23 *		Change in Control Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation.

10.24 *		Letter Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation, with respect to post-termination benefits.

12.01		Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.



13.01		Portions of 2011 Annual Report to Shareholders incorporated by reference to the Form 10-K.

21.01		List of subsidiaries of Southwest Gas Corporation.

23.01		Consent of PricewaterhouseCoopers LLP, an independent registered public accounting firm.

31.01		Section 302 Certifications.

32.01		Section 906 Certifications.

101.01		The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, 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

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 28, 2012				By /s/ JEFFREY W. SHAW
				Jeffrey W. Shaw
				Chief Executive Officer

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 28, 2012

/s/ JOSE A. CARDENAS (Jose A. Cardenas)	Director	February 28, 2012

/s/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	February 28, 2012

/s/ STEPHEN C. COMER (Stephen C. Comer)	Director	February 28, 2012

/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	February 28, 2012

/s/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director	February 28, 2012

/s/ ANNE L. MARIUCCI (Anne L. Mariucci)	Director	February 28, 2012

/s/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Chairman of the Board of Directors	February 28, 2012

/s/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director and Chief Executive Officer	February 28, 2012

/s/ A. RANDALL THOMAN (A. Randall Thoman)	Director	February 28, 2012

/s/ THOMAS A. THOMAS (Thomas A. Thomas)	Director	February 28, 2012

/s/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	February 28, 2012

/s/ ROY R. CENTRELLA (Roy R. Centrella)	Senior Vice President/ Chief Financial Officer	February 28, 2012

/s/ GREGORY J. PETERSON (Gregory J. Peterson)	Vice President, Controller, and Chief Accounting Officer	February 28, 2012

EXHIBIT INDEX


Exhibit Number		Description of Document

10.22		Southwest Gas Corporation 2006 Restricted Stock/Unit Plan, amended and restated January 17, 2012.

10.23		Change in Control Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation.

10.24		Letter Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation, with respect to post-termination benefits.

12.01		Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.

13.01		Portions of 2011 Annual Report to Shareholders incorporated by reference to Form 10-K.

21.01		List of Subsidiaries of Southwest Gas Corporation.

23.01		Consent of PricewaterhouseCoopers LLP, an independent registered public accounting firm.

31.01		Section 302 Certifications.

32.01		Section 906 Certifications.

101.01		The following materials from the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, 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.

Southwest Gas Corp. 2006 Restricted Stock/Unit Plan

SOUTHWEST GAS CORPORATION

2006 RESTRICTED STOCK/UNIT PLAN

Effective September 19, 2006

Amended and Restated May 7, 2008

Amended and Restated July 27, 2010

Amended and Restated January 17, 2012

SOUTHWEST GAS CORPORATION

2006 RESTRICTED STOCK/UNIT PLAN

1.	Purposes of the Plan

The purpose of this Plan is to promote the success of the Company by providing an additional means through the grant of Awards to attract, motivate, retain, and reward key Employees, including Officers of the Company, 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.

2.	Definitions

The following definitions shall apply as used herein and in the Award Agreements and Notices except as defined otherwise in an Award Agreement or Notices. In the event a term is separately defined in an Award Agreement, such definition shall supersede the definition contained in this Section 2.

(a)

“Administrator” means the compensation committee of the Board or such other Committee appointed to administer the Plan, consisting of independent members of the Board.

(b)

“Applicable Laws” means the legal requirements relating to the Plan and the Awards under applicable provisions of federal securities laws, state corporate and securities laws, the Code, the rules of any applicable stock exchange or national market system, and the rules of any non-U.S. jurisdiction applicable to Awards granted to residents therein.

(c)

“Award” means the grant of Restricted Stock or Restricted Stock Units under the Plan.

(d)

“Award Agreement” means a written agreement specifying the terms and conditions of Awards and Restricted Stock Units granted under this Plan executed by the Company and the Grantee, including any amendments thereto.

(e)

“Board” means the Board of Directors of the Company.

(f)

“Cause” means (i) a material act of theft, misappropriation, or conversion of corporate funds committed by the Grantee, or (ii) the Grantee’s demonstrably willful, deliberate, and continued failure to follow reasonable directives of the Board or the Chief Executive Officer of the Company which are within the Grantee’s ability to perform. Notwithstanding the foregoing, for the 24-month period following a Change in Control Event, the Grantee shall not be deemed

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to have been terminated for Cause unless and until: (1) there shall have been delivered to the Grantee a copy of a resolution duly adopted by the Board in good faith at a meeting of the Board called and held for such purpose (after reasonable notice to the Grantee and an opportunity for the Grantee, together with his or her counsel, to be heard before the Board), finding that the Grantee was guilty of conduct set forth above and specifying the particulars thereof in reasonable detail; and (2) if the Grantee contests such finding (or a conclusion that he or she has failed to timely cure the performance in response thereto), the arbitrator, by final determination in an arbitration proceeding pursuant to Section 17 hereof, has concluded that the Grantee’s conduct met the standard for termination for Cause above and that the Board’s conduct met the standards of good faith and satisfied the procedural and substantive conditions of this Section 2(f) (collectively, the “Necessary Findings”). The Grantee’s costs of the arbitration shall be advanced by the Company and shall be repaid to the Company if the arbitrator makes the Necessary Findings.

(g)

“Change in Control Event” means the consummation of any of the following:

(i)

The dissolution or liquidation of the Company, other than in the context of a transaction that does not constitute a Change in Control Event under clause (ii) below.

(ii)

A merger, consolidation, or other reorganization, with or into, or the sale of all or substantially all of the Company’s business and/or assets as an entirety to, one or more entities that are not Subsidiaries or other affiliates (a “Business Combination”), unless (A) as a result of the Business Combination at least 50% of the outstanding securities voting generally in the election of directors of the surviving or resulting entity or a Parent thereof (the “Successor Entity”) immediately after the reorganization are, or will be, owned, directly or indirectly, by shareholders of the Company immediately before the Business Combination; and (B) at least 50% of the members of the board of directors of the entity resulting from the Business Combination were members of the Board at the time of the execution of the initial agreement or of the action of the Board approving the Business Combination. The shareholders before and after the Business Combination shall be determined on the presumptions that (x) there is no change in the record ownership of the Company’s securities from the record date for such approval until the consummation of the Business Combination; and (y) record owners of securities of the Company hold no securities of the other parties to such reorganization.

(iii)

Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than an Excluded Person, becomes the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing more than 20% of

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the combined voting power of the Company’s then outstanding securities entitled to then vote generally in the election of Directors of the Company, other than as a result of (A) an acquisition directly from the Company, (B) an acquisition by the Company, (C) an acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or a Successor Entity, or an acquisition by any entity pursuant to a transaction which is expressly excluded under clause (ii) above.

(iv)

During any period not longer than twelve consecutive months, individuals who at the beginning of such period constituted the Board cease to constitute at least a majority thereof, unless the election, or the nomination for election by the Company’s shareholders, of each new Board member was approved by a vote of at least three-quarters of the Board members then still in office who were Board members at the beginning of such period (including for these purposes, new members whose election or nomination was so approved), but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Board.

(v)

Notwithstanding the foregoing, prior to the occurrence of any of the events described in clause (ii) through (iv) above, the Board may determine that such an event shall not constitute a Change in Control Event for purposes of the Plan and Awards granted under it.

(h)

“Code” means the Internal Revenue Code of 1986, as amended.

(i)

“Committee” means the Compensation Committee of the Board or such other committee composed of independent members of the Board.

(j)

“Common Stock” means the common stock of the Company.

(k)

“Company” means Southwest Gas Corporation, a California corporation, or any successor entity that adopts the Plan in connection with a Change in Control Event.

(l)

“Continuous Service” means that the provision of services to the Company or a Related Entity in any capacity of Employee, Director, or consultant is not interrupted or terminated. In jurisdictions requiring notice in advance of an effective termination as an Employee, Director, or consultant, Continuous Service shall be deemed terminated upon the actual cessation of providing services to the Company or a Related Entity notwithstanding any required notice period that must be fulfilled before a termination as an Employee, Director, or consultant can be effective under Applicable Laws. A Grantee’s Continuous Service shall be deemed to have terminated either upon an actual termination of Continuous Service or upon the entity for which the Grantee

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provides services ceasing to be a Related Entity. Continuous Service shall not be considered interrupted in the case of (i) any approved leave of absence, (ii) transfers among the Company, any Related Entity, or any successor, in any capacity of Employee, Director or consultant, or (iii) any change in status as long as the individual remains in the service of the Company or a Related Entity in any capacity of Employee, Director or consultant (except as otherwise provided in the Award Agreement). An approved leave of absence shall include sick leave, military leave, or any other authorized personal leave.

(m)

“Covered Employee” means an Employee who is a “covered employee” under Section 162(m)(3) of the Code.

(n)

“Director” means a non-Employee member of the Board or the board of directors of any Related Entity.

(o)

“Disability” means as defined under the long-term disability policy of the Company or the Related Entity to which the Grantee provides services regardless of whether the Grantee is covered by such policy. If the Company or the Related Entity to which the Grantee provides service does not have a long-term disability plan in place, “Disability” means that a Grantee is unable to carry out the responsibilities and functions of the position held by the Grantee by reason of any medically determinable physical or mental impairment for a period of not less than one hundred and eighty (180) consecutive days. A Grantee will not be considered to have incurred a Disability unless he or she furnishes proof of such impairment sufficient to satisfy the Administrator in its discretion.

(p)

“Employee” means any person, including an Officer or Director, who is in the employ of the Company or any Related Entity, subject to the control and direction of the Company or any Related Entity as to both the work to be performed and the manner and method of performance. The payment of a director’s fee by the Company or a Related Entity shall not be sufficient to constitute “employment” by the Company.

(q)

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

(r)

“Excluded Person” means (i) any person described in and satisfying the conditions of Rule 13d-1(b)(1) under the Exchange Act, (ii) the Company, or (iii) an employee benefit plan (or related trust) sponsored or maintained by the Company or the Successor Entity.

(s)

“Grantee” means an Employee or Director who receives an Award under the Plan.

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(t)

“Notice” means the written notice memorializing the grant of each Award hereunder and specifying, among other things, the date, number of Restricted Stock Units granted and vesting schedule applicable to each such Award.

(u)

“Officer” means a person who is an officer of the Company or a Related Entity within the meaning of Section 16 of the Exchange Act and the rules and regulations promulgated thereunder.

(v)

“Parent” means a “parent corporation,” whether now or hereafter existing, as defined in Section 424(e) of the Code.

(w)

“Performance-Based Compensation” means compensation qualifying as “performance-based compensation” under Section 162(m) of the Code.

(x)

“Plan” means this 2006 Restricted Stock/Unit Plan.

(y)

“Related Entity” means any Parent or Subsidiary of the Company.

(z)

“Restricted Stock” means Shares issued under the Plan to the Grantee for such consideration, if any, and subject to such restrictions on transfer, rights of first refusal, repurchase provisions, forfeiture provisions, and other terms and conditions as established by the Administrator.

(aa)

“Restricted Stock Units” or “Units” means an Award which may be earned in whole or in part upon the passage of time or the attainment of performance criteria established by the Administrator and which may be settled for Shares or other securities or a combination of Shares or other securities as established by the Administrator.

(bb)

“Retirement” means:

(i)

with respect to Employees, a termination of an Employee’s employment with the Company or a Related Entity on or after the Employee has attained his or her early retirement date or normal retirement date as defined in the Retirement Plan for Employees of Southwest Gas Corporation, as amended and in effect from time to time.

(ii)

with respect to non-Employee Directors, a termination of a Director’s service to the Company or a Related Entity as a Director on or after his or her “normal retirement date” which is the earlier of the first day of the month following the month in which the non-Employee Director (A) reaches age seventy-two (72), or (B) has completed at least ten (10) years of service (in the aggregate) to the Company or a Related Entity as a Director.

(cc)

“Rule 16b-3” means Rule 16b-3 promulgated under the Exchange Act or any successor thereto.

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(dd)

“Share” means a share of the Common Stock.

(ee)

“Subsidiary” means a “subsidiary corporation,” whether now or hereafter existing, as defined in Section 424(f) of the Code.

3.	Stock Subject to the Plan

(a)

Subject to the provisions of Section 9 below, the maximum aggregate number of Shares which may be issued pursuant to all Awards is 400,000 Shares. The Shares to be issued pursuant to Awards may be authorized, but unissued, or reacquired Common Stock.

(b)

Any Shares covered by an Award (or portion of an Award) which is forfeited, canceled or expired (whether voluntarily or involuntarily) shall be deemed not to have been issued for purposes of determining the maximum aggregate number of Shares which may be issued under the Plan. Shares that actually have been issued under the Plan pursuant to an Award shall not be returned to the Plan and shall not become available for future issuance under the Plan, except that if unvested Shares are forfeited such Shares shall become available for future grant under the Plan. During the ten (10) year period following approval of the Plan by the Company’s shareholders and to the extent not prohibited by the listing requirements of the New York Stock Exchange (or other established stock exchange or national market system on which the Common Stock is traded) and Applicable Law, any Shares covered by an Award, which are surrendered in satisfaction of tax withholding obligations incident to the vesting of an Award, shall be deemed not to have been issued for purposes of determining the maximum number of Shares which may be issued pursuant to all Awards under the Plan, unless otherwise determined by the Administrator.

4.	Administration of the Plan

(a)

Plan Administrator.

(i)

Administration with Respect to Covered Employees, Directors, and Officers. With respect to grants of Awards to Covered Employees, Directors, and Employees who are also Officers or Directors of the Company, the Plan shall be administered by a Committee designated by the Board, which Committee (A) shall be comprised solely of two or more Directors eligible to serve on a committee making Awards qualifying as Performance-Based Compensation and (B) shall be constituted in such a manner as to satisfy the Applicable Laws and to permit such grants and related transactions under the Plan to be exempt from Section 16(b) of the Exchange Act in accordance with Rule 16b-3. Once appointed, such Committee shall continue to serve in its designated capacity until otherwise directed by the Board.

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(ii)

Administration Errors. In the event an Award is granted in a manner inconsistent with the provisions of this subsection (a), such Award shall be presumptively valid as of its grant date to the extent permitted by the Applicable Laws.

(b)

Powers of the Administrator. Subject to Applicable Laws and the provisions of the Plan (including any other powers given to the Administrator hereunder), and except as otherwise provided by the Board, the Administrator shall have the authority, in its discretion:

(i)

to select the Employees and Directors to whom Awards may be granted from time to time hereunder;

(ii)

to determine whether and to what extent Awards are granted hereunder;

(iii)

to determine the number of Shares or Restricted Stock Units to be covered by each Award granted hereunder;

(iv)

to approve forms of Award Agreements for use under the Plan;

(v)

to determine the terms and conditions of any Award granted hereunder;

(vi)

to amend the terms of any outstanding Award granted under the Plan, provided that any amendment that would adversely affect the Grantee’s rights under an outstanding Award shall not be made without the Grantee’s written consent;

(vii)

to construe and interpret the terms of the Plan and Awards, including without limitation, any notice of Award or Award Agreement, granted pursuant to the Plan; and

(viii)

to take such other action, not inconsistent with the terms of the Plan, as the Administrator deems appropriate.

The express grant in the Plan of any specific power to the Administrator shall not be construed as limiting any power or authority of the Administrator; provided that the Administrator may not exercise any right or power reserved to the Board. Any decision made, or action taken, by the Administrator or in connection with the administration of this Plan shall be final, conclusive, and binding on all persons having an interest in the Plan.

(c)

Indemnification. In addition to such other rights of indemnification as they may have as members of the Board or as Officers or Employees of the Company or a Related Entity, members of the Board and any Officers or Employees of the Company or a Related Entity to whom authority to act for the Board, the Administrator or the Company is delegated shall be defended and indemnified by the Company to the extent permitted by law on an after-tax basis against

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all reasonable expenses, including attorneys’ fees, actually and necessarily incurred in connection with the defense of any claim, investigation, action, suit or proceeding, or in connection with any appeal therein, to which they or any of them may be a party by reason of any action taken or failure to act under or in connection with the Plan, or any Award granted hereunder, and against all amounts paid by them in settlement thereof (provided such settlement is approved by the Company) or paid by them in satisfaction of a judgment in any such claim, investigation, action, suit or proceeding, except in relation to matters as to which it shall be adjudged in such claim, investigation, action, suit or proceeding that such person is liable for gross negligence, bad faith, or intentional misconduct; provided, however, that within thirty (30) days after the institution of such claim, investigation, action, suit or proceeding, such person shall offer to the Company, in writing, the opportunity at the Company’s expense to defend the same.

5.	Eligibility

Awards may be granted to Employees and Directors. An Employee or Director who has been granted an Award may, if otherwise eligible, be granted additional Awards.

6.	Terms and Conditions of Awards

(a)

Designation of Award. Each Award shall be designated in a Notice and shall be subject to the terms and conditions of an Award Agreement.

(b)

Conditions of Award. Subject to the terms of the Plan, the Administrator shall determine the provisions, terms, and conditions of each Award including, but not limited to, the Award vesting schedule (if any), resale restrictions applicable to the Shares issued pursuant to Awards, forfeiture provisions, and satisfaction of any performance criteria. The performance criteria established by the Administrator may be based on any one of, or combination of, the following: (i) increase in share price, (ii) earnings per share, (iii) total shareholder return, (iv) operating margin, (v) operating costs, (vi) gross margin, (vii) return on equity, (viii) return on assets, (ix) return on investment, (x) operating income, (xi) net operating income, (xii) pre-tax profit, (xiii) cash flow, (xiv) revenue, (xv) expenses, (xvi) earnings before interest, taxes and depreciation, (xvii) economic value added, (xviii) market share, (xix) gas segment return on equity, (xx) customer to employee ratio, (xxi) customer service satisfaction, (xxii) performance of the Company relative to a peer group of companies and/or indexes. The performance criteria may be applicable to the Company and/or any of its individual business units and may differ from Participant to Participant. In addition and to the extent appropriate, the performance criteria will be calculated in accordance with generally accepted accounting principles, but excluding the effect (whether positive or negative) of any change in accounting standards and any extraordinary, unusual, or nonrecurring item, as determined by the Committee, occurring

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after the establishment of the performance criteria applicable to the Awards intended to be performance-based compensation. Each such adjustment, if any, shall be made solely for the purpose of providing a consistent basis from period to period for the calculation of performance criteria in order to prevent the dilution or enlargement of the Participant’s rights with respect to an Award intended to be performance-based compensation; provided however, that certain categories or types of such adjustments can be specifically included (rather than excluded) at the time the performance criteria are established if so determined by the Committee. Certain provisions, terms and conditions applicable to Awards have been set forth in Appendix A and Appendix B hereto.

(c)

Acquisitions and Other Transactions. The Administrator may issue Awards under the Plan in settlement, assumption, or substitution for, outstanding Awards or obligations to grant future Awards in connection with the Company or a Related Entity acquiring another entity, an interest in another entity or an additional interest in a Related Entity whether by merger, stock purchase, asset purchase, or other form of transaction.

(d)

Separate Programs. The Administrator may establish one or more separate programs under the Plan for the purpose of issuing particular forms of Awards to one or more classes of Grantees on such terms and conditions as determined by the Administrator from time to time.

(e)

Individual Limit for Restricted Stock and Restricted Stock Units. For Awards of Restricted Stock and Restricted Stock Units that are intended to be Performance-Based Compensation, the maximum number of Shares with respect to which such Awards may be granted to any Grantee in any calendar year shall be 20,000 Shares. The foregoing limitation shall be adjusted proportionately in connection with any change in the Company’s capitalization pursuant to Section 9 below.

(f)

Transferability of Awards. Awards shall be transferable (i) by will and by the laws of descent and distribution and (ii) during the lifetime of the Grantee, to the extent and in the manner authorized by the Administrator. Notwithstanding the foregoing, the Grantee may designate one or more beneficiaries of the Grantee’s Award in the event of the Grantee’s death on a beneficiary designation form provided by the Administrator.

(g)

Time of Granting Awards. The date of grant of an Award shall for all purposes be the date on which the Administrator makes the determination to grant such Award.

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Taxes

No Shares shall be delivered under the Plan to any Grantee or other person until such Grantee or other person has made arrangements acceptable to the Administrator for the satisfaction of any federal, state, local, or non-U.S. income and employment tax withholding obligations, including, without limitation, obligations incident to the receipt of Shares. Upon the issuance of Shares, the Company shall withhold or collect from Grantee an amount sufficient to satisfy such tax obligations, including, but not limited to, by surrender of Shares covered by the Award sufficient to satisfy the minimum applicable tax withholding obligations incident to the vesting of an Award.

8.	Conditions Upon Issuance of Shares

(a)

If at any time the Administrator determines that the delivery of Shares pursuant to an Award is or may be unlawful under Applicable Laws, the vesting or right to exercise an Award or to otherwise receive Shares pursuant to the terms of an Award shall be suspended until the Administrator determines that such delivery is lawful and shall be further subject to the approval of counsel for the Company with respect to such compliance. The Company shall have no obligation to effect any registration or qualification of the Shares under federal or state laws.

(b)

As a condition to the exercise or issuance of an Award, the Company may require the person exercising or receiving such Award to represent and warrant at the time of any such exercise or issuance that the Shares are being purchased only for investment and without any present intention to sell or distribute such Shares if, in the opinion of counsel for the Company, such a representation is required by any Applicable Laws.

9.	Adjustments Upon Changes in Capitalization

Subject to any required action by the shareholders of the Company, the number of Shares covered by each outstanding Award, and the number of Shares which have been authorized for issuance under the Plan but as to which no Awards have yet been granted or which have been returned to the Plan, the maximum number of Shares with respect to which Awards may be granted to any Grantee in any calendar year, as well as any other terms that the Administrator determines require adjustment shall be proportionately adjusted for (i) any increase or decrease in the number of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination, or reclassification of the Shares, or similar transaction affecting the Shares, (ii) any other increase or decrease in the number of issued Shares effected without receipt of consideration by the Company, or (iii) any other transaction with respect to Common Stock including a corporate merger, consolidation, acquisition of property or stock, separation (including a spin-off or other distribution of stock or property), reorganization, liquidation (whether partial or complete), or any similar transaction; provided, however, that conversion of any

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convertible securities of the Company shall not be deemed to have been “effected without receipt of consideration.” Except as the Administrator determines, no issuance by the Company of shares of any class, or securities convertible into shares of any class, shall affect, and no adjustment by reason hereof shall be made with respect to, the number of Shares subject to an Award.

10.

Change in Control Event

Except as provided otherwise in an Award Agreement or a Notice, in the event of a Change in Control Event, each Award which is at the time outstanding under the Plan automatically shall (i) become fully vested and be released from any repurchase, forfeiture, or transfer restrictions and (ii) with respect to Restricted Stock Units, be converted in full to Shares, immediately prior to the specified effective date of the consummation of such Change in Control Event, for all of the Shares or Units at the time represented by such Award.

11.

Effective Date and Term of Plan

The Plan shall become effective upon its adoption by the Board. It shall continue in effect for a term of ten (10) years unless sooner terminated. Continuance of the Plan shall be subject to approval by the shareholders of the Company. Such shareholder approval shall be obtained in the degree and manner required under Applicable Laws. Awards may be granted under the Plan upon its becoming effective, but any Award granted before shareholder approval is obtained shall be rescinded if shareholders fail to approve the Plan at the next shareholder meeting that occurs after the Plan is adopted by the Board.

12.

Amendment, Suspension, or Termination of the Plan

(a)

The Board may at any time amend, suspend, or terminate the Plan; provided, however, that no such amendment shall be made without the approval of the Company’s shareholders to the extent such approval is required by Applicable Laws.

(b)

No Award may be granted during any suspension of the Plan or after termination of the Plan.

(c)

No suspension or termination of the Plan shall adversely affect any rights under Awards already granted to a Grantee.

13.

Reservation of Shares

(a)

The Company, during the term of the Plan, will at all times reserve and keep available such number of Shares as shall be sufficient to satisfy the requirements of the Plan.

(b)

The inability of the Company to obtain authority from any regulatory body having jurisdiction, which authority is deemed by the Company’s counsel to

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be necessary to the lawful issuance and sale of any Shares hereunder, shall relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority shall not have been obtained.

14.

No Effect on Terms of Employment/Consulting Relationship

The Plan shall not confer upon any Grantee any right with respect to the Grantee’s Continuous Service, nor shall it interfere in any way with his or her right or the right of the Company or any Related Entity to terminate the Grantee’s Continuous Service at any time, with or without Cause, and with or without notice. The ability of the Company or any Related Entity to terminate the employment of a Grantee who is employed “at will” is in no way affected by its determination that the Grantee’s Continuous Service has been terminated for Cause for the purposes of this Plan.

15.

No Effect on Retirement and Other Benefit Plan

Except as specifically provided in a retirement or other benefit plan of the Company or a Related Entity, Awards shall not be deemed compensation for purposes of computing benefits or contributions under any retirement plan of the Company or a Related Entity, and shall not affect any benefits under any other benefit plan of any kind or any benefit plan subsequently instituted under which the availability or amount of benefits is related to level of compensation. The Plan is not a “Retirement Plan” or “Welfare Plan” under the Employee Retirement Income Security Act of 1974, as amended.

16.

Construction

Captions and titles contained herein are for convenience only and shall not affect the meaning or interpretation of any provision of the Plan. Except when otherwise indicated by the context, the singular shall include the plural and the plural shall include the singular. Use of the term “or” is not intended to be exclusive, unless the context clearly requires otherwise.

17.

Arbitration and Litigation

(a)

Any dispute, controversy, or claim arising out of or in respect to this Plan (or its validity, interpretation, or enforcement) or the subject matter hereof must be submitted to and settled by arbitration conducted before a single arbitrator (chosen from a list of arbitrators provided by the American Arbitration Association with each party hereto taking alternate strikes and the remaining arbitrator hearing the dispute). The arbitration will be conducted in Clark County, Nevada, in accordance with the then current rules of the American Arbitration Association or its successor. The arbitration of such issues, including the determination of any amount of damages suffered, will be final and binding upon the parties to the maximum extent permitted by law. The arbitrator in such action will not be authorized to change or modify any

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provision of the Plan. Judgment upon the award rendered by the arbitrator may be entered by any court having jurisdiction thereof. The arbitrator will award reasonable legal fees and expenses (including arbitration costs) to the prevailing party upon application therefor. The parties consent to the jurisdiction of the Supreme Court of the State of Nevada and of the U.S. District Court for the District of Nevada for all purposes in connection with arbitration, including the entry of judgment of any award.

(b)

Except as may be necessary to enter judgment upon the award or to the extent required by applicable law, all claims, defenses, and proceedings (including, without limiting the generality of the foregoing, the existence of the controversy and the fact that there is an arbitration proceeding) shall be treated in a confidential manner by the arbitrator, the parties and their counsel, and each of their agents and employees, and all others acting on behalf or in concert with them. Without limiting the generality of the foregoing, no one shall divulge to any third party or person not directly involved in the arbitration, the contents of the pleadings, papers, orders, hearings, trials, or awards in the arbitration, except as may be necessary to enter judgment upon an award as required by applicable law. Any court proceedings relating to the arbitration hereunder, including, without limiting the generality of the foregoing, to prevent or compel arbitration to perform, correct, vacate, or otherwise enforce an arbitration award, shall be filed under seal with the court, to the extent permitted by law.

[Signature page follows.]

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IN WITNESS WHEREOF, the Company has executed this Amended and Restated Plan Document effective the 17^th day of January 2012.


SOUTHWEST GAS CORPORATION

By:		/s/ JEFFREY W. SHAW
		Jeffrey W. Shaw, C.E.O.

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APPENDIX A TO THE 2006 RESTRICTED STOCK/UNIT PLAN

TARGET AWARD OPPORTUNITY FOR EACH GRANTEE


Position	% of Year-End Base Salary	Range of Award Grant*

Chief Executive Officer	45	22.5 to 67.5
President	30	15.0 to 45.0
Executive Vice President	25	12.5 to 37.5
Senior Vice President	20	10.0 to 30.0
Vice President	15	7.5 to 22.5
Other Participants	10	5.0 to 15.0
Non-Employee Directors		800 Restricted Stock or Stock Units

* Awards granted pursuant to the Plan will range from 50 percent to 150 percent of the target Award opportunity for each participant, other than non-Employee Directors, established for the initial Award. The actual Award will be determined based on the three-year average Management Incentive Plan payout percentage (the “MIP Payout Percentage”) for the three years immediately preceding the Award determination date. The threshold to earn an Award will be a MIP Payout Percentage of 90. The Award will increase by five percent for each one percentage point increase in the MIP Payout Percentage until such percentage equals 100, then the increase will be reduced to two and one-half percent for each percentage point increase through 120.

* Awards granted pursuant to the Plan to Directors will be set at 800 Restricted Stock or Stock Units per year.

* Once the Awards are established, they will be converted into Restricted Stock or Stock Units, based on the average of the closing prices of the Common Stock on the New York Stock Exchange for the first five trading days of the month in which the award is granted.

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1.	Vesting Schedule of Awards

(a)

Awards to Employees.

(i)

With respect to Awards to Employees, unless otherwise set forth in an Award Agreement, a Notice or in an amendment to this Appendix A, the Shares or Units subject to an Award shall vest and be paid out in Common Stock over a three (3) year period as follows: forty percent (40%) of the Shares or Units subject to the Award shall vest on the 4^th of January following the Award (the “Vesting Commencement Date”) and thirty percent (30%) of the Shares or Units subject to the Award shall vest on each of the second and third anniversaries of the Vesting Commencement Date.

(ii)

During any authorized leave of absence, the vesting of the Shares or Units awarded to Employees only as provided above shall be suspended after the leave of absence exceeds a period of three (3) months. Vesting of the Shares or Units shall resume upon the Employee’s termination of the leave of absence and return to service to the Company or a Related Entity. The Vesting Schedule of the Shares or Units shall be extended by the length of the suspension.

(iii)

Notwithstanding the foregoing, in the event the Employee’s Continuous Service terminates as the result of Death, Retirement, or Disability, the Employee will be entitled to receive the Award for the current Plan year determined on a pro rata basis according to the number of months actually worked during the current year while participating in the Plan. This Section 1(a)(iii) of Appendix A is effective January 17, 2012 with retroactive and prospective effect.

(iv)

With respect to Restricted Stock Units, Awards shall be credited with notional dividends at the same time, in the same form, and in equivalent amounts as dividends that are payable from time to time on the Common Stock. Any such notional dividends shall be valued as of the date on which they are credited to the Employee and reallocated to acquire additional Units. Such additional Units shall vest in accordance with the vesting schedule set forth in the applicable Notice or Award Agreement as if such Units had been issued on the date of such Award (if any).

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(v)

Notwithstanding the foregoing, in the event the Employee’s Continuous Service terminates as the result of Death, Retirement, or Disability, 100% of the Shares or Units shall become fully vested and no longer subject to forfeiture to the Company. In the event of a Change in Control Event, each Award which is at the time outstanding under the Plan automatically shall (i) become fully vested and be released from any repurchase, forfeiture, or transfer restrictions and (ii) with respect to Restricted Stock Units, be converted in full to Shares, immediately prior to the specified effective date of the consummation of such Change in Control Event, for all of the Shares or Units at the time represented by such Award.

(b)

Awards to Directors. Subject to the Director’s Continuous Service, Awards shall vest in accordance with either of the following schedules:

(i)

Forty percent (40%) of the Shares or Units subject to an Award shall vest on the 4^th of January following the award (Vesting Commencement Date), and thirty percent (30%) on each of the second and third anniversaries of the Vesting Commencement Date. Vesting of the Shares or Units shall accelerate so that one hundred percent (100%) of the Shares or Units subject to the Award shall vest (i) in the event of a Change in Control Event and, with respect to Units, be converted in full to Shares, immediately prior to the specified effective date of the consummation of such Change in Control Event or (ii) upon termination of the Director’s Continuous Service as a result of death, Disability, or Retirement. Notwithstanding the foregoing, Shares or Units subject to an Award granted on or after January 17, 2012, shall vest on the Award Date. With respect to Restricted Stock Units, the conversion of the Units into Shares, however, will not occur until the Director’s Continuous Service terminates, or immediately prior to a Change in Control Event.

(ii)

With respect to Restricted Stock Units, Awards shall be credited with notional dividends at the same time, in the same form, and in equivalent amounts as dividends that are payable from time to time on the Common Stock. Any such notional dividends shall be valued as of the date on which they are credited to the Director and reallocated to acquire additional Units. Such additional Units shall vest in accordance with the vesting schedule set forth in the applicable Award Agreement as if such Units had been issued on the date of such Award (if any).

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APPENDIX B TO THE 2006 RESTRICTED STOCK/UNIT PLAN

2008 GRANT TO NON-EMPLOYEE DIRECTORS

Commencing January 2009, non-Employee Directors will be entitled to receive annual grants of Restricted Stock Units tied to the performance of the Company. Each non-Employee Director will receive a target Award opportunity of 1,000 Units.

The Award granted will range from 50 to 150 percent of the target Award opportunity for each non-Employee Director. The Awards granted annually will be determined based on the three-year average Management Incentive Plan payout percentage (the “MIP Payout Percentage”) for the three years immediately preceding the Awards determination date. The threshold to earn Awards will be a MIP Payout Percentage of 90. The Awards will increase by five percent for each one percentage point increase in the MIP Payout Percentage until such percentage equals 100, then the increase will be reduced to two and one-half percent for each percentage point increase through 120.

Vesting Schedule of Awards

Subject to the Director’s Continuous Service, Awards shall vest in accordance with either of the following schedules:

(a)

Forty percent (40%) of the Units subject to each annual Award shall vest on the 4^th of January following the award (the “Vesting Commencement Date”), and thirty percent (30%) on each of the second and third anniversaries of the Vesting Commencement Date. Vesting of the Units shall accelerate so that one hundred percent (100%) of the Units subject to the Award shall vest (i) in the event of a Change in Control Event and, with respect to Units, be converted in full to Shares, immediately prior to the specified effective date of the consummation of such Change in Control Event or (ii) upon termination of the Director’s Continuous Service as a result of death, Disability, or Retirement. Notwithstanding the foregoing, Shares or Units subject to an Award granted on or after January 17, 2012, shall vest on the Award Date. Conversion of the vested Units into Shares, however, will not occur until the Director’s Continuous Service terminates, or immediately prior to a Change in Control Event.

(b)

With respect to the Awards, notional dividends shall be credited at the same time, in the same form, and in equivalent amounts as dividends that are payable from time to time on the Common Stock. Any such notional dividends shall be valued as of the date on which they are credited and reallocated to acquire additional Units. Such additional Units shall vest in accordance with the vesting schedule set forth above, as if such Units had been issued on the date of such Awards.

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Change in Control Agreement

CHANGE IN CONTROL AGREEMENT

THIS CHANGE IN CONTROL AGREEMENT (this “Agreement”) entered into this February 24, 2012 and effective as of the 1st day of June, 2012 between SOUTHWEST GAS CORPORATION, a California corporation (together with its successors, the “Company”), and Jeffrey W. Shaw (the “Executive”).

WHEREAS, the Board of Directors of the Company (the “Board”) recognizes that the continuing possibility of a change in control of the Company is unsettling to the Executive and other officers of the Company;

WHEREAS, the Board wishes to assure a continuing dedication by the Executive to his duties to the Company, notwithstanding the occurrence or potential occurrence of a change in control of the Company;

WHEREAS, the Board believes it is important, should the Company receive proposals from third parties with respect to its future, to enable the Executive, without being influenced by the uncertainties of his own situation, to assess and advise the Board whether such proposals would be in the best interests of the Company and its shareholders and to take such other action regarding such proposals as the Board might determine to be appropriate; and

WHEREAS, the Board wishes to demonstrate to officers of the Company that the Company is concerned with the welfare of its officers and intends to see that loyal officers are treated fairly.

NOW, THEREFORE, the Company and the Executive agree as follows:

TERM

The term of this Agreement shall commence on the date first set forth above and shall end on the third (3rd) anniversary thereof. Notwithstanding the foregoing, this Agreement shall not terminate during the Protection Period or the Severance Period, in each case as defined below.

2.	DEFINITIONS

As used in this Agreement:

(a) “Cause” means (i) a material act of theft, misappropriation, or conversion of corporate funds committed by the Executive or (ii) the Executive’s demonstrably willful, deliberate and continued failure to follow reasonable directives of the Board which are within the Executive’s ability to perform. The Executive shall not be deemed to have been terminated for Cause unless and until: (x) there shall have been delivered to the Executive a copy of a resolution duly adopted by the independent members of the

Board in good faith at a meeting of such Board members called and held for such purpose (after reasonable notice to the Executive and an opportunity for the Executive, together with his counsel, to be heard before the Board) finding that the Executive was guilty of conduct set forth above and specifying the particulars thereof in reasonable detail; and (y) if the Executive contests such finding (or a conclusion that he has failed to timely cure the performance in response thereto), the arbitrator, by final determination in an arbitration proceeding pursuant to Section 5 hereof, has concluded that the Executive’s conduct met the standard for termination for Cause above and that the Board’s conduct met the standards of good faith and satisfied the procedural and substantive conditions of this Section 2(a) (collectively, the “Necessary Findings”). The Executive’s costs of the arbitration shall be advanced by the Company and shall be repaid to the Company if the arbitrator makes the Necessary Findings.

If within sixty (60) days after receipt by the Executive of the resolution referred to in the preceding paragraph, the Executive notifies the Company that a dispute exists concerning the termination, the termination date of the Executive shall be the date as finally determined by mutual written agreement of the parties or by a final and binding arbitration award. During the period until the dispute is finally resolved, the Company will, in accordance with its regular payroll procedures, continue to pay the Executive his full compensation in effect when the notice giving rise to the dispute was given (including, but not limited to, base salary) and continue the Executive as a participant in all compensation, employee benefit, health and welfare and insurance plans, programs, arrangements and perquisites in which the Executive was participating or to which he was entitled when the notice giving rise to the dispute was given, until the dispute is finally resolved. Amounts paid under this Section 2(a) shall be repaid to the Company or be offset against or reduce any other amounts due the Executive under this Agreement, if appropriate, only upon the final resolution of the dispute. Notwithstanding the foregoing, if the Executive is a “specified employee” within the meaning of Section 409A of the Code and the related Treasury Regulations and guidance thereunder (“Section 409A”) on the date of termination of the Executive’s employment with the Company, during the six- (6-) month period following the Executive’s termination of employment with the Company, payments to the Executive under this Section 2(a) (other than reimbursements and in-kind amounts described in Treasury Regulation Section 1.409A-1(b)(9)(v), or any successor provision thereto) that constitute “non-qualified deferred compensation” under Section 409A shall be delayed and paid to the Executive on the first regularly scheduled Company executive pay date that occurs in the seventh (7th) calendar month following the calendar month in which the Executive’s termination of employment occurs; thereafter, any additional payments owed to the Executive under this Section 2(a) shall be paid to the Executive ratably on the following regularly scheduled Company executive pay dates.

(b) “Change in Control” means any of the following:

(i) Approval by the shareholders of the Company of the dissolution or liquidation of the Company;

(ii) Consummation of a merger or consolidation, or other reorganization, with or into one (1) or more entities that are not Subsidiaries, as a result of which less than 50% of the outstanding voting securities of the surviving or resulting entity immediately after such reorganization are, or shall be, owned, directly or indirectly, by shareholders of the Company immediately before such reorganization (assuming for purposes of such determination that there is no change in the record ownership of the Company’s securities from the record date for such approval until such reorganization and that such record owners hold no securities of the other parties to such reorganization, but including in such determination any securities of the other parties to such reorganization held by affiliates of the Company);

(iii) Consummation of the sale of substantially all of the Company’s business and/or assets to a person or entity which is not a Subsidiary;

(iv) Any “person” (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), but excluding any person described in and satisfying the conditions of Rule 13d-1(b)(1) thereunder), becomes the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing more than 20% of the combined voting power of the Company’s then outstanding securities entitled to then vote generally in the election of directors of the Company; or

(v) During any period not longer than two (2) consecutive years, individuals who at the beginning of such period constituted the Board cease to constitute at least a majority thereof, unless the election, or the nomination for election by the Company’s shareholders, of each new Board member was approved by a vote of at least three-fourths (3/4) of the Board members then still in office who were Board members at the beginning of such period (including for these purposes, new members whose election was so approved).

(d) “Code” means the Internal Revenue Code of 1986, as amended.

(e) “Disability” means that because of physical or mental illness or disability, the Executive shall have been continuously unable to perform the essential functions of his job with or without reasonable accommodation for a consecutive period of at least six (6) months.

(f) “Good Reason” means, following a Change in Control:

(i) without the Executive’s express written consent, the assignment to him of any duties materially inconsistent with his positions, duties, authority,

responsibilities or status with the Company immediately prior to such Change in Control;

(ii) a material demotion or a material change in the Executive’s titles or offices as in effect immediately prior to such Change in Control;

(iii) any removal of the Executive from or any failure to re-elect him to any of such positions; except in connection with the termination of the Executive’s employment for Cause, Disability or retirement or as a result of his death or by him other than for Good Reason;

(iv) without the Executive’s express written consent, a material reduction by the Company in the Executive’s base salary as in effect on the date of such Change in Control or, if greater, such greater base salary as may be in effect from time to time subsequent to such Change in Control, provided, in each case, that a reduction by the Company in the Executive’s base salary of ten (10) percent or more shall be sufficient but not necessary to constitute a material reduction by the Company in the Executive’s base salary;

(v) the failure by the Company to continue at levels materially not less than those in existence immediately prior to such Change in Control the Executive’s participation in any thrift, incentive or compensation plan, or any pension plan, in which the Executive participated immediately prior to such Change in Control, provided that the Company may provide for participation in substantially similar plans that provide benefits at levels materially not less than those in existence immediately prior to such Change in Control;

(vi) the failure by the Company to provide for the Executive’s participation in any welfare, life insurance, health and accident or disability plan on the same basis as those provided to executives of the Company who are similarly situated to the Executive;

(vii) the taking of any action by the Company which would materially adversely affect the Executive’s participation in or materially reduce his benefits under any single such plan or all such plans, when taken together, or deprive him of any material fringe benefit enjoyed by him at the time of such Change in Control (except for the acceleration of the termination dates of stock options, restricted stock units, performance shares and other awards and rights, if applicable, as contemplated by this Agreement), provided that the taking of any action by the Company that reduces the economic value attributable to such participation, benefits or fringe benefit by ten (10) percent or more shall be sufficient but not necessary to constitute a materially adverse effect, material reduction or deprivation, as applicable;

(viii) the assignment to the Executive without his consent to a new work location which would require an increase in the round-trip commute to work from

the Executive’s residence immediately prior to such Change in Control of more than 40 miles per day; or

(ix) any material breach of any material provision of this Agreement.

Notwithstanding the foregoing, the Executive shall not be entitled to terminate his employment with the Company for Good Reason unless the following process is followed with respect to such termination. Within ninety (90) days following the initial occurrence of an event that purportedly constitutes Good Reason, the Executive shall give the Company written notice of the occurrence of such event, setting forth the exact nature of such event and the conduct required to cure such event. The Company shall have thirty (30) days from the receipt of such notice within which to cure such event (such period, the “Cure Period”). If, during the Cure Period, such event is cured, then the Executive shall not be permitted to terminate his employment with the Company for Good Reason as a result of such event. If, at the end of the Cure Period, such event is not cured, the Executive shall be entitled to terminate his employment with the Company for Good Reason as a result of such event during the sixty (60) day period following the end of the Cure Period. If the Executive does not terminate his employment with the Company for Good Reason during such sixty (60) day period, the Executive shall not be permitted to terminate his employment with the Company for Good Reason as a result of such event.

(g) “Subsidiary” means any corporation, partnership, joint venture or other entity in which the Company has a 50% or greater equity interest.

3.	LIMITED RIGHT TO A SEVERANCE BENEFIT

The Executive shall be entitled to the severance benefits provided in this Section 3 if, within twenty-four (24) months after a Change in Control (the “Protection Period”): (i) the Executive terminates his employment with the Company for Good Reason or (ii) the Executive’s employment is terminated by the Company for any reason other than (x) the Executive’s death, (y) the Executive’s Disability or (z) Cause, in each case, for clauses (i) and (ii) immediately preceding, provided that the Executive executes and delivers to the Company within 45 days of the date of such termination, and lets become effective and irrevocable, a Release in the form attached hereto as Attachment A (“Release”):

(a) Any restricted stock awards, restricted stock units, stock options, stock appreciation rights or performance shares to purchase or relating to the common stock of the Company held by the Executive on the date of such termination, which are not then currently vested or exercisable, shall on such date automatically become vested or exercisable and shall remain exercisable for 90 days thereafter (subject to any fixed term of such award, unit, option, right or share set forth in the document evidencing such award, unit, option, right or share).

(b) A lump-sum severance payment equal to the sum of:

(i) thirty-six (36) months of the Executive’s yearly base salary in effect as of the date of such termination or, if greater, as of the date of such Change in Control, and

(ii) an amount equal to any incentive compensation that would be payable to the Executive under any short or long-term incentive compensation plan of the Company (including the Company’s Management Incentive Plan or any successor plan thereto and the Company’s Restricted Stock Unit Plan or any successor plan thereto), calculated at the designated award opportunity for the Executive at the date of termination or, if greater, as of the date of such Change in Control, and at 100% of the target performance measures, with any such amounts otherwise payable in securities of the Company to be payable in cash, for the period during the applicable plan year preceding the date of such termination and for the severance period of thirty-six (36) months following the date of such termination (such post-termination period, the “Severance Period”), and

(iii) an amount equal to the full cost of health and dental coverage for the Executive (and his eligible dependents) for the Severance Period, which amount shall be calculated based on the full cost of continued health and dental coverage for the Executive (and his eligible dependents) under COBRA as of the date of termination or, if greater, as of the date of such Change in Control, and

(iv) an amount equal to the full cost of replacement disability and life insurance coverage for the Executive (other than travel/accident) for the Severance Period, which cost shall be calculated as of the date of termination or, if greater, as of the date of such Change in Control.

Subject to the limits in Section 3(e) below, payment of the foregoing lump-sum severance payment shall be made in accordance with the Company’s regular payroll procedures and be made to the Executive on the first regularly scheduled Company executive pay date that occurs sixty (60) days after the termination of the Executive’s employment, provided that the Release has become effective and irrevocable.

(c) The Company shall pay the Executive any benefits under the Company’s benefit plans, including the Company’s Executive Deferred Compensation Plan and the Company’s Supplemental Executive Retirement Plan (the “SERP”), which are fully vested on the date of such termination, in accordance with their terms, including with respect to applicable payment schedules and any applicable elections; provided, however, that, if the Executive shall have reached the age of fifty (50) by the date of such termination, the Executive shall receive additional benefits under the SERP such that the Executive shall be permitted to add to the formula for purposes of eligibility for benefits, vesting and calculation of benefits, six (6) points which, at the election of the Executive, may be applied either to an age assumption or continuous length of service assumption or a combination thereof.

(d) The Executive shall be entitled to reimbursement of reasonable expenses actually incurred by the Executive directly related to outplacement services, which reimbursement shall not exceed Thirty Thousand Dollars ($30,000). Such reimbursement shall only be made for outplacement services directly related to such termination. Such expenses must be incurred not later than the end of the second calendar year following the calendar year of such termination. Such expense must be submitted by the Executive to the Company as promptly as practicable, and in no event later than required by the Company in order for the Company to make such reimbursement no later the last day of the third calendar year following the calendar year in which such termination occurs. In no event shall the Company make any such reimbursement later than the last day of the third calendar year following the calendar year in which such termination occurs.

(e) Notwithstanding anything to the contrary in this Section 3, if the Executive is a “specified employee” within the meaning of Section 409A, during the six- (6-) month period following the Executive’s termination of employment with the Company, payments to the Executive under this Section 3 (other than reimbursements and in-kind amounts described in Treasury Regulation Section 1.409A-1(b)(9)(v) or any successor provision thereto) that constitute “non-qualified deferred compensation” under Section 409A shall be delayed and paid to the Executive on the first regularly scheduled Company executive pay date that occurs in the seventh (7th) calendar month following the calendar month in which the Executive’s termination of employment occurs; thereafter, any additional payments owed to the Executive under this Section 3 shall be paid to the Executive in the manner otherwise specified in this Section 3. With respect to any payment delayed pursuant to this Section 3(e), the Company shall pay the Executive, on the day on which such delayed payment is made to the Executive, interest on such delayed payment for the period of such delay at the applicable federal rate provided for in Section 1274(d) of the Code for the month in which such delayed payment otherwise would have been made.

(f) For purposes of this Agreement, the Executive will be deemed to not have terminated employment with the Company unless the Executive has incurred a Separation from Service. “Separation from Service” means the termination of the Executive’s employment by the Company if the Executive dies, retires or otherwise has a termination of employment with the Company; provided that the Executive’s employment relationship is treated as continuing intact while on military leave, sick leave or other bona fide leave of absence if the period of such leave does not exceed six (6) months or longer, if the Executive’s right to reemployment is provided either by statute or by contract. A leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Executive will return to perform services for the Company. If the period of leave exceeds six (6) months and the Executive does not retain a right to reemployment under an applicable statute or by contract, the employment relationship is deemed to terminate on the first date immediately following such six- (6-) month period. Notwithstanding the foregoing, where a leave of absence is due to any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than six (6) months, where such impairment causes the employee to be unable to perform the duties of his or

her position of employment, or any substantially similar position of employment, a twenty-nine (29-) month period of absence may be substituted for such six- (6-) month period. For purposes of this paragraph, the term “Company” includes all other organizations that together with the Company are part of a control group of organizations under Section 414(b) and Section 414(c) of the Code. Whether an Executive has incurred a Separation from Service shall be determined based in accordance with Section 409A. Additionally, if the Executive ceases to work as an Executive, but is retained to provide services as an independent contractor of the Company, the determination of whether the Executive has incurred a Separation from Service shall be determined based in accordance with Section 409A.

4.	CERTAIN REDUCTION OF PAYMENTS BY THE COMPANY

In the event that it is determined that any payment or distribution by the Company to the Executive or for the Executive’s benefit, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or pursuant to or by reason of any other agreement, policy, plan, program or arrangement, including without limitation any stock option or restricted stock or similar right, or the lapse or termination of any restriction on or the vesting or exercisability of any of the foregoing (a “Payment”), would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision thereto), by reason of being considered “contingent on a change in the ownership or effective control” of the Company, within the meaning of Section 280G of the Code (or any successor provision thereto) or to any similar tax imposed by state or local law, or any interest or penalties with respect to such tax (such tax or taxes, together with any such interest and penalties, being hereafter collectively referred to as the “Excise Tax”), then the Payment shall be reduced by the Company in a manner determined by the Company to be $1.00 less than three (3) times the Executive’s base amount (as defined in Section 280G of the Code) so that no portion of the Payment shall be subject to the Excise Tax, provided that the Company shall make such reduction only if such reduction would effect, on an after-tax basis, a Payment that is greater than the Payment that would be made if no such reduction were effected. The Executive shall be permitted to provide the Company with written notice specifying which of the Payments will be subject to reduction or elimination; provided, however, that to the extent that the Executive’s ability to exercise such authority would cause any Payment to become subject to any taxes or penalties pursuant to Section 409A, or if the Executive does not provide the Company with any such written notice, the Company shall reduce or eliminate the Payments by first reducing or eliminating the portion of the Payments that are payable in cash and then by reducing or eliminating the non-cash portion of the Payments, in each case in reverse order beginning with payments or benefits which are to be paid the farthest in time. Except as set forth in the preceding sentence, any notice given by the Executive pursuant to the preceding sentence shall take precedence over the provisions of any other plan, arrangement or agreement governing the Executive’s rights and entitlements to any benefits or compensation.

5.	ARBITRATION AND LITIGATION

Any dispute, controversy or claim arising out of or in respect to this Agreement (or its validity, interpretation or enforcement) or the subject matter hereof must be submitted to and settled by arbitration conducted before a single arbitrator or, at the election of the Company or the Executive, a panel of arbitrators (chosen from a list of arbitrators provided by the American Arbitration Association with each party hereto taking alternate strikes and the remaining arbitrator or arbitrators, as applicable, hearing the dispute).

By agreeing to arbitrate all disputes related to this Agreement, the Company and the Executive acknowledge, among other things, that they are waiving the right to have the dispute heard by a court of law or equity and the right to a jury trial.

The arbitration will be conducted in Clark County, Nevada, in accordance with the then current rules of the American Arbitration Association or its successor. The arbitration of such issues, including the determination of any amount of damages suffered, will be final and binding upon the parties to the maximum extent permitted by law. The decision of the arbitrator or the panel, as applicable, shall be in writing and signed by the arbitrator. A copy of the arbitrator’s or the panel’s decision, as applicable, will be provided to each party. The arbitrator or panel, as applicable, in such action will not be authorized to change or modify any provision of this Agreement. Judgment upon the award rendered by the arbitrator or the panel, as applicable, may be entered by any court having jurisdiction thereof. The parties consent to the jurisdiction of the Supreme Court of the State of Nevada and of the U.S. District Court for the District of Nevada for all purposes in connection with arbitration, including the entry of judgment of any award.

The Company shall advance the arbitrator’s or the panel’s fees, as applicable, subject to the provisions of Section 2(a), however, the arbitrator or the panel, as applicable, will award reasonable legal fees and expenses (including arbitration costs) to the prevailing party upon application therefor. The non-prevailing party may thus incur greater expenses under arbitration than under traditional court litigation.

Except as may be necessary to enter judgment upon the award or to the extent required by applicable law, all claims, defenses and proceedings (including, without limiting the generality of the foregoing, the existence of the controversy and the fact that there is an arbitration proceeding) shall be treated in a confidential manner by the arbitrator or the panel, as applicable, the parties and their counsel, and each of their agents and employees, and all others acting on behalf or in concert with them. Without limiting the generality of the foregoing, no one shall divulge to any third party or person not directly involved in the arbitration, the contents of the pleadings, papers, orders, hearings, trials, or awards in the arbitration, except as may be necessary to enter judgment upon an award as required by applicable law. Any court proceedings relating to the arbitration hereunder, including, without limiting the generality of the foregoing, to prevent or compel arbitration to perform, correct, vacate or otherwise enforce an arbitration award, shall be filed under seal with the court, to the extent permitted by law.

6.	BENEFITS AND BINDING EFFECT

This Agreement shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation, person or other entity which may acquire all or substantially all of the assets and business of the Company or any corporation with or into which the Company may be consolidated or merged, and the Executive, his heirs, executors, administrators and legal representatives, provided that the obligations of the Executive hereunder may not be delegated.

7.	OTHER AGREEMENTS

The Executive represents that the execution and performance of this Agreement will not result in a breach of any of the terms and conditions of any employment or other agreement between the Executive and any third party.

Provided that the Company duly performs all of its obligations (if any) arising by virtue of a termination of employment of the Executive, the Executive will not publicly disparage the Company or its officers, directors, employees or agents and will refrain from any action which could reasonably be expected to cause material adverse public relations or embarrassment to the Company or to any of such persons. Similarly, the Company (including its officers, directors, employees and agents) will not disparage the Executive and will refrain from any action which could reasonably be expected to result in embarrassment to the Executive or to materially and adversely affect his opportunities for employment. The preceding two (2) sentences shall not apply to disclosures required by applicable law, regulation or order of a court or governmental agency.

The Company may withhold from any amounts payable under this Agreement all federal, state, local and foreign taxes as may be required to be withheld pursuant to any applicable law or regulation.

NOTICES

All notices or other communications relating to this Agreement shall be in writing and delivered personally or sent by registered or certified mail, postage prepaid and return receipt requested, to the party concerned at the address set forth below:


If to the Company, to:		Southwest Gas Corporation 5241 Spring Mountain Road Las Vegas, Nevada 89150 Attn: General Counsel

If to the Executive, to:		Jeffrey W. Shaw 2404 Juniper Canyon Court Las Vegas, Nevada 89134

Either party may change the address to which notices are to be sent to it by giving ten (10) days written notice of such change of address to the other party in the manner provided above for giving notice. Notices will be considered delivered on the date of personal delivery or on the date of deposit in the United States mail in the manner provided for giving notice by mail.

9.	EXECUTIVE ACKNOWLEDGMENT AND SECTION 409A

The Executive acknowledges and agrees that he has consulted with and relied exclusively on his own counsel regarding the tax effects of this Agreement and that the Company shall have no liability or obligation with respect to any tax imposed by Section 409A, or other Code section, on the Executive as a result of the transactions and payments contemplated by this Agreement.

The parties agree that this Agreement shall be construed and interpreted to the maximum extent possible to comply with Section 409A.

10.	ENTIRE AGREEMENT

The entire understanding and agreement between the parties has been incorporated into this Agreement, and this Agreement supersedes all other agreements, negotiations, and understandings between the Executive and the Company with respect to the subject matter hereof (including any prior change in control agreements between the Executive and the Company). This Agreement may not be amended orally, but only by an agreement in writing signed by both parties.

11.	GOVERNING LAW

This Agreement shall be governed by and interpreted in accordance with the laws of the State of Nevada. It is intended by the parties that this Agreement be interpreted in accordance with its fair and simple meaning, not for or against either party, and neither party shall be deemed to be the drafter of this Agreement.

12.	CAPTIONS; COUNTERPARTS

The section headings and captions included herein are for convenience and shall not constitute a part of this Agreement.

This Agreement may be executed simultaneously in two (2) or more counterparts, each of which shall be deemed an original, but all of which shall together constitute one (1) and the same Agreement.

13.	SEVERABILITY

If any portion or provision of this Agreement is determined by arbitration or by a court of competent jurisdiction to be invalid, illegal or unenforceable, the remaining portions or provisions hereof shall not be affected.

[Signature page follows.]

IN WITNESS WHEREOF, this Change in Control Agreement has been executed by the parties hereto as of the date first written above.


		SOUTHWEST GAS CORPORATION

		By: /s/ MICHAEL J. MELARKY
		Michael J. Melarkey
		Chairman of the Board


		EXECUTIVE:

		/s/ JEFFREY W. SHAW
		Jeffrey W. Shaw

Letter Agreement - Jeffrey W. Shaw

Exhibit 10.24

LOGO

February 24, 2012

Jeffrey W. Shaw

Chief Executive Officer

Southwest Gas Corporation

2404 Juniper Canyon Court

Las Vegas, Nevada 89134

Re: Expiration of Existing Employment Agreement

Dear Mr. Shaw:

Reference is hereby made to that certain Employment Agreement (the “Existing Agreement”), entered into and effective as of September 21, 2004, and amended as of November 14, 2008, between you and Southwest Gas Corporation, a California corporation (the “Company”), and to that certain Change In Control Agreement (the “CIC Agreement”), entered into and effective as of February 24, 2012, between you and the Company. All capitalized terms used herein and not defined herein shall have the meaning assigned to such terms in the CIC Agreement.

You have agreed to continue as the Chief Executive Officer of the Company as an “at will” employee after the termination of the Existing Agreement. In recognition of your years of service, the exemplary performance of the Company during your tenure as Chief Executive Officer and as an inducement to your continued service to the Company, the Company wishes to extend certain incentives to you which would apply after the termination of the Existing Agreement. In consideration of the premises and the covenants and agreements contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, you hereby agree with the Company that from and after June 1, 2012 and prior to a Change in Control, any termination of your employment with the Company by you for Good Reason (as defined herein) or by the Company for any reason other than (i) death, (ii) Disability, (iii) Cause (as defined herein), or (iv) following the termination of this letter agreement as provided below (each, a “Termination Event”), shall have the following effect:

(a) The Company shall pay you a lump-sum severance payment (the “Severance Payment”) equal to: (1) the sum of (A) twelve (12) months of your yearly base salary in effect as of the date hereof or, if greater, such greater base salary as may be in effect from time to time prior to the date of such termination (“Base Salary”), and (B) an amount equal to any incentive compensation that would be payable to you under any short or long-term incentive compensation plan of the Company (including the Company’s Management Incentive Plan or any successor plan thereto (the “MIP”) and the Company’s Restricted

5241 Spring Mountain Road / Las Vegas, Nevada 89150-0002

P.O. Box 98510 / Las Vegas, Nevada 89193-8510 / (702) 876-7011

www.swgas.com

Jeffrey W. Shaw

February 24, 2012

Page 2

Stock/Unit Plan or any successor plan thereto (the “RSUP”)), calculated at the designated award opportunity for you at the date of termination and at 100% of the target performance measures, with any such amounts otherwise payable in securities of the Company to be payable in cash, for the period during the applicable plan year preceding the date of such termination and for the period of twelve (12) months following the date of such termination; or (2) such greater amount to which you and the Company may agree;

(b) Any restricted stock awards, restricted stock units, stock options, stock appreciation rights or performance shares to purchase or relating to the common stock of the Company (the “Incentive Equity”) held by you on the date of such termination (including any Incentive Equity under the MIP or the RSUP), which are not then currently vested or exercisable, shall on such date automatically become vested or exercisable and shall remain exercisable for 90 days thereafter, subject to any fixed term of such Incentive Equity set forth in the document evidencing such Incentive Equity (i.e., any unvested Incentive Equity held by you under the MIP or the RSUP would vest fully under such plans as in the event of you taking early retirement at age 55); and

(c) The Company shall pay you any benefits under the Company’s benefits plans, including the Company’s Executive Deferred Compensation Plan and the Company’s Supplemental Executive Retirement Plan (the “SERP”), which are fully vested on the date of such termination, in accordance with applicable payment schedules and any applicable elections; provided, however, that you shall receive additional benefits under the SERP such that up to 2 years shall be added to the age assumption in order to deem you to be age 55 under the SERP for purposes of eligibility for benefits, vesting and calculation of benefits, (e.g., if you are 53 at the time of termination, for purposes of eligibility, vesting and calculation of benefits, you will be deemed to be age 55 under the SERP).

You agree that you will work as an “at will” employee of the Company in the capacity of Chief Executive Officer beginning on the June 1, 2012. Nothing within this letter alters our employment-at-will relationship. Either of us may terminate our relationship at any time, with or without cause and, except as otherwise agreed, without liability.

You shall have “Good Reason” to terminate employment if, without your implicit or explicit consent, the Company independently and unilaterally acts in a manner that causes one of the following consequences: (i) without your express written consent, (A) the assignment to you of any duties inconsistent with your positions, duties, authority, responsibilities and status with the Company as of the date hereof, (B) a material demotion or a change in your titles or offices or (C) any removal of you from or any failure to re-elect you to any of such positions; except, in connection with the termination of your employment for Cause, Disability or retirement or as a result of your death or by you other than for Good Reason; (ii) without your express written consent, a material reduction by the Company in your Base Salary, provided that a reduction by the Company in your Base Salary of ten (10)

Jeffrey W. Shaw

February 24, 2012

Page 3

percent or more shall be sufficient but not necessary to constitute a material reduction by the Company in your Base Salary; (iii) (A) the failure by the Company to continue at levels in effect as of the date hereof any thrift, incentive or compensation plan, or any pension, life insurance, health and accident or disability plan in which you participate, provided that the Company may adopt substantially similar plans that provide benefits at levels no less than those in existence or (B) the taking of any action by the Company which would adversely affect your participation in or materially reduce your aggregate benefits under all of such plans, when taken together, or deprive you of any material fringe benefit currently enjoyed by you; or (iv) your assignment to a new work location which would require a round-trip commute to work from your residence of more than 40 miles per day. You must notify the Company of the existence of the Good Reason condition or conditions set forth above within 90 days of such condition’s or conditions’ initial occurrence and provide the Company with 30 days to remedy such condition or conditions. If the Company remedies such condition or conditions within such 30 day period, and you incur a termination of employment due to the initial existence of such condition or conditions, the termination will not be for Good Reason. If the Company fails to remedy such condition or conditions within such 30 day period, and you incur a termination of employment within 120 days after the expiration of such period, the termination will be for Good Reason.

For purposes of this letter agreement “Cause” shall mean (i) a material act of theft, misappropriation, or conversion of corporate funds committed by you, or (ii) your demonstrably willful, deliberate and continued failure to follow reasonable directives of the Board which are within your ability to perform. You shall not be deemed to have been terminated for Cause unless and until: (x) there shall have been delivered to you a copy of a resolution duly adopted by the independent members of the Board in good faith at a meeting of such Board members called and held for such purpose (after reasonable notice to you and an opportunity for you, together with your counsel, to be heard before the Board) finding that you were guilty of conduct set forth above and specifying the particulars thereof in reasonable detail; and (y) if you contest such finding (or a conclusion that you have failed to timely cure the performance in response thereto), the arbitrator makes the Necessary Findings. Your costs of the arbitration shall be advanced by the Company and shall be repaid to the Company if the arbitrator makes the Necessary Findings. If within sixty (60) days after receipt by you of the resolution referred to above, you notify the Company that a dispute exists concerning the termination, your termination date shall be the date as finally determined by mutual written agreement of the parties or by a final and binding arbitration award. During the period until the dispute is finally resolved, the Company will, in accordance with its regular payroll procedures, continue to pay you your full compensation in effect when the notice giving rise to the dispute was given (including, but not limited to, Base Salary) and continue you as a participant in all compensation, employee benefit, health and welfare and insurance plans, programs, arrangements and perquisites in which you were participating or to which you were entitled when the notice giving rise to the dispute was

Jeffrey W. Shaw

February 24, 2012

Page 4

given, until the dispute is finally resolved. Amounts paid shall be repaid to the Company or be offset against or reduce any other amounts due to you under this letter agreement, if appropriate, only upon the final resolution of the dispute.

Subject to the limits set forth below, payment of the foregoing Severance Payment and any other payments or benefits provided for hereunder shall be made in accordance with the Company’s regular payroll procedures and be made to you on the first regularly scheduled Company executive pay date that occurs sixty (60) days after the termination of your employment. Notwithstanding anything to the contrary in this letter agreement, if you are a “specified employee” within the meaning of Section 409A, during the six- (6-) month period following your termination of employment with the Company, payments to you under this letter agreement (other than reimbursements and in-kind amounts described in Treasury Regulation Section 1.409A-1(b)(9)(v) or any successor provision thereto) that constitute “non-qualified deferred compensation” under Section 409A shall be delayed and paid to you on the first regularly scheduled Company executive pay date that occurs in the seventh (7th) calendar month following the calendar month in which your termination of employment occurs; thereafter, any additional payments owed to you under this letter agreement shall be paid to you in the manner otherwise specified in this letter agreement. With respect to any payment delayed pursuant to this paragraph, the Company shall pay you, on the day on which such delayed payment is made to you, interest on such delayed payment for the period of such delay at the applicable federal rate provided for in Section 1274(d) of the Code for the month in which such delayed payment otherwise would have been made.

For purposes of this letter, you will be deemed to not have terminated employment with the Company unless you have incurred a Separation from Service. For purposes of this paragraph, the term “Company” includes all other organizations that together with the Company are part of a control group of organizations under Section 414(b) and Section 414(c) of the Code. Whether you have incurred a Separation from Service shall be determined based in accordance with Section 409A. Additionally, if you cease to work as an executive, but are retained to provide services as an independent contractor of the Company, the determination of whether you have incurred a Separation from Service shall be determined based in accordance with Section 409A.

You acknowledge and agree that you have consulted with and relied exclusively on your own counsel regarding the tax effects of this letter agreement and that the Company shall have no liability or obligation with respect to any tax imposed by Section 409A, or other Code section, on you as a result of the transactions and payments contemplated by this letter agreement. The parties agree that this letter agreement shall be construed and interpreted to the maximum extent possible to comply with Section 409A.

This letter agreement constitutes the entire agreement between the parties with respect to the subject matter hereof and supersedes all prior agreements and understandings,

Jeffrey W. Shaw

February 24, 2012

Page 5

both written and oral, between the parties with respect to the subject matter hereof and is not intended to confer upon any other person any rights or remedies hereunder. This letter agreement may not be modified or changed except by an instrument in writing signed by each of the parties hereto.

Provided that the Company duly performs all of its obligations (if any) arising by virtue of a termination of your employment, you will not publicly disparage the Company or its officers, directors, employees or agents and will refrain from any action which could reasonably be expected to cause material adverse public relations or embarrassment to the Company or to any of such persons. Similarly, the Company (including its officers, directors, employees and agents) will not disparage you and will refrain from any action which could reasonably be expected to result in embarrassment to you or to materially and adversely affect your opportunities for employment. The preceding two sentences shall not apply to disclosures required by applicable law, regulation or order of a court or governmental agency.

The Company may withhold from any amounts payable under this letter agreement all federal, state, local and foreign taxes as may be required to be withheld pursuant to any applicable law or regulation.

You hereby expressly covenant and agree that from the date of this letter agreement until the later of the termination of this letter agreement or one (1) year following a Termination Event (the “Restricted Period”), you shall not, directly or indirectly, do any of the following acts: (i) assist, plan, organize, own, manage, operate, join, control, provide service to, or participate in (in any capacity whatsoever) any business, individual, partnership, firm or corporation or any other business organization, which is at the time engaged wholly or partly, in the businesses of the Company and its affiliates (hereinafter, the “Business”) in any geographic location in which the Company or any of its affiliates (either directly or indirectly) is currently, or has been within the three years prior to the date of this letter agreement, conducting the Business (herein referred to as the “Territory”); (ii) solicit, employ, hire or cause to be solicited, employed or hired any officer, stockholder, employee, consultant or agent employed or retained by the Company or its affiliates, without the prior written consent of the Company; (iii) divert or attempt to divert from the Company or its affiliates to any competitor of the Company any existing customer or supplier, or (based on work or research done or contacts made by the Company) any prospective customer or supplier of the Company within the Territory serviced, without the prior written consent of the Company; or (iv) intentionally disrupt or intentionally attempt to disrupt any business relationship between any third party and the Company or its affiliates in connection with the Business. We acknowledge that neither direct nor indirect ownership by you of one percent (1%) or less of the outstanding common shares of any publicly traded corporation, partnership or trust shall constitute a breach of this paragraph.

Jeffrey W. Shaw

February 24, 2012

Page 6

You hereby acknowledge and agree that the Company or its affiliates may provide you with data and information (including without limitation specifications, drawings, sketches, models, samples, tools, technical information, methods, processes, techniques, shop practices, formulas, compounds, compositions, research data, marketing and sales information, customer lists, plans, know-how, data, written, oral or otherwise), which is privileged, confidential and proprietary to the Company (“Confidential Information”), in order to enable you to successfully perform your obligations hereunder. You agree that all such data and information, which may be acquired by you, intentionally or unintentionally, directly or indirectly, during the term your employment, shall be and remain the sole and exclusive property of the Company, and shall be returned to the Company, as applicable, in a complete and unaltered form, upon expiration or termination of your employment. Furthermore, you agree that no part or portion of any of such information or data shall be used by you, reproduced, published or disseminated in any manner whatsoever except as is necessary in the ordinary course of performance of your employment, or upon express written permission granted by the Company. Without limiting the generality of the foregoing, you agree to keep secret and confidential all data and information concerning trade secrets, research, new or planned products or services, customers, supply sources, proprietary rights, finances, strategies, business and activities of the Company, its affiliates and its potential or actual customers. “Confidential Information” shall not include (i) information published or available to the public not due to your fault; (ii) information received by you from parties not connected with the Company without the breach of any obligation of confidentiality or (iii) information of a general nature not pertaining to either party.

This letter agreement shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation, person or other entity which may acquire all or substantially all of the assets and business of the Company or any corporation with or into which the Company may be consolidated or merged, and you, your heirs, executors, administrators and legal representatives, provided that your obligations hereunder may not be delegated.

The parties hereto agree that the arbitration and litigation provisions of Section 5 of the CIC Agreement shall apply to this letter agreement. ANY DISPUTE, CONTROVERSY OR CLAIM ARISING OUT OF OR IN RESPECT TO THIS LETTER AGREEMENT (OR ITS VALIDITY, INTERPRETATION OR ENFORCEMENT), THE EMPLOYMENT RELATIONSHIP, OR THE SUBJECT MATTER HEREOF MUST BE SUBMITTED TO AND SETTLED BY ARBITRATION CONDUCTED BEFORE A SINGLE ARBITRATOR (CHOSEN FROM A LIST OF ARBITRATORS PROVIDED BY THE AMERICAN ARBITRATION ASSOCIATION WITH EACH PARTY HERETO TAKING ALTERNATE STRIKES AND THE REMAINING ARBITRATOR HEARING THE DISPUTE). By agreeing to arbitrate all disputes related to this letter agreement, you acknowledge, among other things, that you are waiving the right to have the dispute heard by a court of law or equity and the right to a jury trial.

Jeffrey W. Shaw

February 24, 2012

Page 7

If any portion or provision of this letter agreement is determined by arbitration or by a court of competent jurisdiction to be invalid, illegal or unenforceable, the remaining portions or provisions hereof shall not be affected.

This letter agreement may be executed in any number of counterparts, all of which together make and shall constitute one and the same instrument and any of the parties hereto may execute this letter agreement by signing any such counterpart.

This letter agreement will be governed by the laws of the State of Nevada without regard to conflicts of laws principles.

This letter agreement shall terminate on November 9, 2013, the 55^th anniversary of your date of birth. You shall have no rights under the terms of this letter agreement with respect to any termination of employment arising after a Change in Control, at which point the CIC Agreement shall be controlling.

Please acknowledge your agreement to the foregoing by executing a duplicate copy of this letter agreement in the space provided below and returning it to the undersigned.

[Signature page follows.]

Jeffrey W. Shaw

February 24, 2012

Page 8

SOUTHWEST GAS CORPORATION

By: /s/ MICHAEL J. MELARKY

Name: Michael J. Melarkey

Title: Chairman of the Board

Acknowledged , Accepted and Agreed this

24th day of February, 2012.

/s/ JEFFREY W. SHAW

Jeffrey W. Shaw

Conputation of Ratios of Earnings to Fixed Charges

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)



	December 31,
	2011		2010		2009		2008		2007
1. Fixed charges:
A) Interest expense	$	68,183	$	75,481	$	81,861	$	90,403	$	94,035
B) Amortization		2,137		2,620		2,097		2,880		2,783
C) Interest portion of rentals		8,943		6,455		6,644		7,802		7,952

Total fixed charges	$	79,263	$	84,556	$	90,602	$	101,085	$	104,770


2. Earnings (as defined):
D) Pretax income from continuing operations	$	175,066	$	158,378	$	132,035	$	101,808	$	131,024
Fixed Charges (1. above)		79,263		84,556		90,602		101,085		104,770

Total earnings as defined	$	254,329	$	242,934	$	222,637	$	202,893	$	235,794

		3.21		2.87		2.46		2.01		2.25

Portions of 2011 Annual Report to Shareholders


Southwest Gas Corporation		19

Exhibit 13.01

Consolidated Selected Financial Statistics


Year Ended December 31,	2011			2010			2009			2008			2007
(Thousands of dollars, except per share amounts)
Operating revenues	$	1,887,188		$	1,830,371		$	1,893,824		$	2,144,743		$	2,152,088
Operating expenses		1,637,108			1,598,254			1,685,433			1,936,881			1,929,788

Operating income	$	250,080		$	232,117		$	208,391		$	207,862		$	222,300

Net income	$	112,287		$	103,877		$	87,482		$	60,973		$	83,246

Total assets at year end	$	4,276,007		$	3,984,193		$	3,906,292		$	3,820,384		$	3,670,188

Capitalization at year end
Total equity	$	1,225,031		$	1,166,996		$	1,102,086		$	1,037,841		$	983,673
Subordinated debentures		—			—			100,000			100,000			100,000
Long-term debt, excluding current maturities		930,858			1,124,681			1,169,357			1,185,474			1,266,067

	$	2,155,889		$	2,291,677		$	2,371,443		$	2,323,315		$	2,349,740

Current maturities of long-term debt	$	322,618		$	75,080		$	1,327		$	7,833		$	38,079
Common stock data
Common equity percentage of capitalization		56.8	%		50.9	%		46.5	%		44.7	%		41.9	%
Return on average common equity		9.3	%		9.1	%		8.1	%		6.0	%		8.8	%
Basic earnings per share	$	2.45		$	2.29		$	1.95		$	1.40		$	1.97
Diluted earnings per share	$	2.43		$	2.27		$	1.94		$	1.39		$	1.95
Dividends declared per share	$	1.06		$	1.00		$	0.95		$	0.90		$	0.86
Payout ratio		43	%		44	%		49	%		64	%		44	%
Book value per share at year end	$	26.68		$	25.60		$	24.44		$	23.48		$	22.98
Market value per share at year end	$	42.49		$	36.67		$	28.53		$	25.22		$	29.77
Market value per share to book value per share		159	%		143	%		117	%		107	%		130	%
Common shares outstanding at year end (000)		45,956			45,599			45,092			44,192			42,806
Number of common shareholders at year end		16,834			17,821			20,489			22,244			22,664
Ratio of earnings to fixed charges		3.21			2.87			2.46			2.01			2.25


Southwest Gas Corporation		20

Natural Gas Operations


Year Ended December 31,	2011			2010			2009			2008			2007
(Thousands of dollars)
Sales	$	1,329,512		$	1,438,809		$	1,547,081		$	1,728,924		$	1,754,913
Transportation		73,854			73,098			67,762			62,471			59,853

Operating revenue		1,403,366			1,511,907			1,614,843			1,791,395			1,814,766
Net cost of gas sold		613,489			736,175			866,630			1,055,977			1,086,194

Operating margin		789,877			775,732			748,213			735,418			728,572
Expenses
Operations and maintenance		358,498			354,943			348,942			338,660			331,208
Depreciation and amortization		175,253			170,456			166,850			166,337			157,090
Taxes other than income taxes		40,949			38,869			37,318			36,780			37,553

Operating income	$	215,177		$	211,464		$	195,103		$	193,641		$	202,721

Contribution to consolidated net income	$	91,420		$	91,382		$	79,420		$	53,747		$	72,494

Total assets at year end	$	4,048,613		$	3,845,111		$	3,782,913		$	3,680,327		$	3,518,304

Net gas plant at year end	$	3,218,944		$	3,072,436		$	3,034,503		$	2,983,307		$	2,845,300

Construction expenditures and property additions	$	305,542		$	188,379		$	212,919		$	279,254		$	312,412

Cash flow, net
From operating activities	$	216,745		$	342,522		$	371,416		$	261,322		$	320,594
From (used in) investing activities		(289,234	)		(178,685	)		(265,850	)		(237,093	)		(306,396	)
From (used in) financing activities		(2,327	)		(107,779	)		(81,744	)		(34,704	)		(5,347	)

Net change in cash	$	(74,816	)	$	56,058		$	23,822		$	(10,475	)	$	8,851

Total throughput (thousands of therms)
Residential		718,765			704,693			669,736			704,986			698,063
Small commercial		303,923			300,940			294,225			314,555			310,666
Large commercial		112,256			111,833			117,241			125,121			127,561
Industrial/Other		50,208			58,922			72,623			97,702			103,525
Transportation		941,544			998,600			1,043,894			1,164,190			1,128,422

Total throughput		2,126,696			2,174,988			2,197,719			2,406,554			2,368,237

Weighted average cost of gas purchased ($/therm)	$	0.58		$	0.62		$	0.71		$	0.84		$	0.81
Customers at year end		1,859,000			1,837,000			1,824,000			1,819,000			1,813,000
Employees at year end		2,298			2,349			2,423			2,447			2,538
Customer to employee ratio		809			782			753			743			714
Degree days – actual		2,002			1,998			1,824			1,902			1,850
Degree days – ten-year average		1,888			1,876			1,882			1,893			1,936


Southwest Gas Corporation		21

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 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 in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

As of December 31, 2011, Southwest had 1,859,000 residential, commercial, industrial, and other natural gas customers, of which 1,001,000 customers were located in Arizona, 674,000 in Nevada, and 184,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2011, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 86% of operating margin from residential and small commercial customers, 4% from other sales customers, and 10% 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 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 now 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 iniatives.

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. NPL has successfully captured some of these additional projects.

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. 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.


Southwest Gas Corporation		22

Summary Operating Results


Year ended December 31,	2011		2010		2009
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	91,420	$	91,382	$	79,420
Construction services		20,867		12,495		8,062

Consolidated	$	112,287	$	103,877	$	87,482

Average number of common shares outstanding		45,858		45,405		44,752

Basic earnings per share
Consolidated	$	2.45	$	2.29	$	1.95

Natural Gas Operations
Operating margin	$	789,877	$	775,732	$	748,213

2011 Overview

Consolidated operating results for 2011 increased compared to 2010 due to improvements in both the natural gas and construction services segments. Basic earnings per share were $2.45 in 2011 compared to basic earnings per share of $2.29 in 2010.

Natural gas operations highlights include the following:

•

Improved weather, rate relief, and customer growth contributed to increased operating margin during 2011

•

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

•

Operating expenses increased $10 million, or 2%, between years

•

Net financing costs decreased $8 million between 2011 and 2010

•

The Company’s credit rating was upgraded from BBB to BBB+ by both Standard & Poors and Fitch, in April and June 2011, respectively

•

Arizona general rate increase of $52.6 million and decoupling mechanism were approved effective January 2012

Construction services highlights include the following:

•

Revenues in 2011 increased $165 million, or 52%, compared to 2010

•

Contribution to net income increased $8 million

Rate Relief. During 2011, Southwest realized $2 million of incremental operating margin from rate relief in its California regulatory jurisdictions. See Rates and Regulatory Proceedings for additional information.

Weather and Conservation. The rate structures in each of Southwest’s three states provide varying levels of protection from risks that drive operating margin volatility, particularly weather risk and conservation efforts. Southwest’s exposure to these risks on operating margin was largely limited to its Arizona operating areas in 2011 as both Nevada and California operations were under decoupled rate structures during the year. Weather impacts resulted in a net increase of $14 million in operating margin between 2011 and 2010. Warmer-than-normal weather was experienced in 2010 while colder-than-normal weather was experienced in 2011.

Arizona Rate Proceedings. Southwest filed a general rate application with the Arizona Corporation Commission (“ACC”) in November 2010 requesting an increase in authorized annual operating revenues of $73.2 million, or 9.26%, to reflect


Southwest Gas Corporation		23

increased operating costs, investments in infrastructure, and costs of capital, as well as margin attrition due to decreased average usage by customers. In December 2011, the ACC issued its Order in the Company’s Arizona rate case filing approving a $52.6 million increase in general rates effective January 2012. In addition, a decoupled rate structure was approved, which is designed to eliminate the impacts of weather and conservation on margin. For more information see the Rates and Regulatory Proceedings discussion.

Customer Growth. Southwest completed 13,000 first-time meter sets, but realized 22,000 net new customers over the last twelve months. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth associated with new meter sets of 1% or less for 2012, along with the gradual return of customers from 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 $227 million at December 31, 2011. 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 $74 million at December 31, 2011 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, 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, income from changes in the cash surrender value of COLI policies and recognized net death benefits was $700,000 in 2011 and $9.8 million in 2010. 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.

Out-of-Period Adjustment. As disclosed in Note 1 to the consolidated financial statements, Southwest recorded a $3.7 million decrease to revenues in the third quarter of 2011 related to an isolated error in a regulatory deferral mechanism that overstated revenues for the periods prior to the third quarter of 2011. Approximately $800,000 of the adjustment relates to the first half of 2011 while $2.9 million pertains to years prior to 2011 ($300,000 to $400,000 per quarter in 2009 and 2010).

Liquidity. Southwest believes its liquidity position is adequate and the outlook is favorable. Southwest has a $300 million credit facility maturing in May 2012. The facility is provided through a consortium of eight major banking institutions. Historically, usage of the facility has been low and concentrated in the first half of the winter heating period when gas purchases require temporary financing. Usage of the facility was infrequent during 2011, primarily due to existing cash reserves and natural gas prices that were relatively stable. The outstanding balance at December 31, 2011 was $109 million, leaving $191 million available for working capital needs. Management intends to replenish its borrowing capacity during the first quarter of 2012.

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 February 2011 in connection with the issuance of $125 million of 6.1% Senior Notes to certain institutional investors. Other than replacing $200 million of debt maturing in May 2012, and securing a replacement credit facility, Southwest has no long-term debt maturities until 2017. In January 2012, Southwest redeemed $12.4 million in 6.1% Clark County Series A Industrial Development Revenue Bonds (“IDRBs”) at par originally due in 2038.


Southwest Gas Corporation		24

Results of Natural Gas Operations


Year Ended December 31,	2011			2010		2009
(Thousands of dollars)
Gas operating revenues	$	1,403,366		$	1,511,907	$	1,614,843
Net cost of gas sold		613,489			736,175		866,630

Operating margin		789,877			775,732		748,213
Operations and maintenance expense		358,498			354,943		348,942
Depreciation and amortization		175,253			170,456		166,850
Taxes other than income taxes		40,949			38,869		37,318

Operating income		215,177			211,464		195,103
Other income (deductions)		(5,404	)		4,016		6,590
Net interest deductions		68,777			75,113		74,091
Net interest deductions on subordinated debentures		—			1,912		7,731

Income before income taxes		140,996			138,455		119,871
Income tax expense		49,576			47,073		40,451

Contribution to consolidated net income	$	91,420		$	91,382	$	79,420

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. An 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 periods. 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 the out-of-period 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 periods primarily due to general cost increases, partially offset by favorable claims experience under Southwest’s self-insured medical plan. The increase also includes 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, which principally includes returns on COLI policies and non-utility expenses, declined $9.4 million between 2011 and 2010. The current year reflects COLI-related income (resulting from recognized death benefits net of decreases in cash surrender values) of $700,000, while the prior year included income of $9.8 million due to an increase in COLI cash surrender values and recognized net death benefits. COLI income in the previous year was especially high due to strong equity-market returns on investments underlying the policies.


Southwest Gas Corporation		25

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 includes $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.

2010 vs. 2009

Contribution to consolidated net income from natural gas operations increased $12 million in 2010 compared to 2009. The increase was a result of higher operating margin and reduced financing costs, partially offset by an increase in operating expenses.

Operating margin increased more than $27 million between years. Rate relief provided $18 million toward the operating margin increase, consisting of $15 million in Nevada and $3 million in California. Differences in heating demand caused primarily by weather variations between years resulted in an $8 million operating margin increase as warmer-than-normal temperatures were experienced during both years. Customer growth contributed $1 million of the operating margin increase.

Operations and maintenance expense increased $6 million, or 2%, principally due to the impact of higher employee-related benefit costs and general cost increases. The increase was mitigated by cost containment efforts (including lower staffing levels) and by a decline in uncollectible expense, partially due to the impacts of the tracking mechanism in Nevada for the gas-cost portion of uncollectible accounts.

Depreciation expense increased $3.6 million, or 2%, as a result of additional plant in service, partially offset by lower depreciation rates in the Nevada rate jurisdiction ($2.3 million annualized reduction) effective in June 2009. Average gas plant in service for 2010 increased $139 million, or 3%, as compared to 2009. This was attributable to reinforcement work, franchise requirements, routine pipe replacement activities, and new business.

Other income declined $2.6 million between 2010 and 2009. This was primarily due to higher costs associated with certain Arizona non-recoverable pipe replacement work, partially offset by an increase in the cash surrender values of COLI policies. In 2010, COLI policies provided $9.8 million in income due to an increase in the cash surrender values and recognized net death benefits. The prior year included an $8.5 million increase in COLI cash surrender values. COLI income in both periods was very high due to strong equity-market returns on investments underlying the policies.

Net financing costs decreased $4.8 million between 2010 and 2009 due to the redemption of the $100 million subordinated debentures in March 2010.

Outlook for 2012

Operating margin for 2012 is expected to increase primarily due to the additional revenue authorized in the Arizona rate case effective January 2012. However, the incremental margin in 2012 compared to 2011 is expected to be 10% to 20% lower than the $52.6 million approved because the average usage and margin per Arizona customer in 2011 were higher than the amounts used in calculating the deficiency when the rate case was filed in 2010.

Operating expenses for 2012 compared to 2011 will continue to be impacted by inflation and general cost increases. Incremental costs associated with a $7.5 million increase in pension expense for 2012 and additional depreciation on accelerated pipe replacement activities is expected to result in a higher level of expense increase (3% to 4%) than has been experienced over the past two years.


Southwest Gas Corporation		26

Net interest deductions for 2012 are anticipated to be favorably impacted when $200 million of 7.625% debt maturing in May 2012 is refinanced at an expected lower interest rate.

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. Effective January 2012, such rate structures are in place in all of Southwest’s operating areas.

Arizona Energy Efficiency and Decoupling Proceeding. In August 2010, the ACC issued a Notice of Proposed Rulemaking on Gas Energy Efficiency, which adopted an energy efficiency requirement for Arizona’s gas utilities, including Southwest, to achieve cumulative annual energy savings of 6% by December 2020. In October 2010, the Chairman of the ACC issued a draft Policy Statement, which would allow utilities to file proposals for alternative mechanisms including revenue-per-customer decoupling, in connection with a general rate case to address the financial disincentives to utilities of promoting energy efficiency. The Policy Statement was approved by the ACC in December 2010.

Arizona General Rate Case. Southwest filed a general rate application with the ACC in November 2010 requesting an increase in authorized annual operating revenues of $73.2 million, or 9.26%, to reflect increased operating costs, investments in infrastructure, and costs of capital, as well as margin attrition due to decreased average usage by customers. The application requested an overall rate of return of 9.73% on original cost rate base of $1.074 billion, an 11% return on common equity, and a capital structure utilizing 52% common equity.

The rate case filing also requested a rate structure to decouple recovery of the Company’s fixed costs from natural gas usage and enable the Company to aggressively advocate for increased energy efficiency by its customers. The filed structure anticipated the approval of the Policy Statement discussed in the Arizona Energy Efficiency and Decoupling Proceeding section above. The proposed mechanism is a revenue-per-customer decoupling mechanism designed to eliminate the link between volumetric sales and revenues that currently exists with traditional rate designs, such that the existing financial disincentive associated with the Company’s pursuit of cost-effective energy efficiency is eliminated.

After several weeks of negotiations, a majority of the parties agreed to a settlement, which was filed with the ACC in July 2011. Two options were presented in the settlement: one providing for partial decoupling (Alternative A) and one with a full decoupling provision (Alternative B). Alternative A would include a $54.9 million revenue increase, or 6.95%, with a 9.75% return on common equity. Alternative B would include a $52.6 million revenue increase, or 6.66%, with a 9.50% return on common equity.

In December 2011, the ACC approved the settlement (previously described as “Alternative B”) effective January 2012. The Order approved an overall revenue increase of $52.6 million, a return on common equity of 9.50%, a fair value rate of return of 6.92% and a capital structure comprised of 47.7% long-term debt and 52.3% common equity, with an embedded cost of debt of 8.34%. The Order also approved a full revenue decoupling mechanism with a monthly weather adjustor. This rate structure is designed to decouple rates such that recovery of the Company’s fixed costs is not significantly impacted by fluctuations in usage, both higher and lower, and to enable the Company to aggressively advocate for


Southwest Gas Corporation		27

increased energy efficiency by its customers. The pursuit of increased energy efficiency by customers will be supported by a detailed energy efficiency and renewable energy resource technology plan that recommends new and expanded conservation and energy efficiency programs and budgets. Current residential basic service charge levels were also maintained as part of the settlement. Southwest also agreed to not file a general rate application prior to April 30, 2016 as part of the settlement. The “stay out” provision is void if the ACC decision to allow decoupling is reversed before 2016. The decoupling mechanism is subject to an annual earnings test whereby recovery of a shortfall, if any, between per-customer margin amounts and weather-normalized billed amounts will be prohibited in the event that the recovery would increase earnings above the authorized return on common equity.

California General Rate Cases. Effective January 2009, Southwest received general rate relief in California. The California Public Utilities Commission (“CPUC”) decision authorized an overall increase of $2.8 million in 2009 with an additional $400,000 deferred to 2010. In addition, attrition increases were approved to be effective for the years 2010-2013 of 2.95% in southern and northern California and approximately $100,000 per year for the South Lake Tahoe rate jurisdiction. Attrition increases were effective January 2011 in the amount of $2.3 million. Attrition adjustments to be effective January 2012 were $2.3 million; however, the low interest rate environment triggered an automatic rate of return adjustment mechanism resulting in offsetting decreases of $2.4 million, with an overall net decrease throughout the California rate jurisdictions of $100,000 beginning January 2012.

Nevada General Rate Case. Southwest currently intends to file a general rate application with the Public Utilities Commission of Nevada (“PUCN”) in the second quarter of 2012. The operating revenue increase to be requested has not yet been determined, but will reflect additional investments in infrastructure and include changes in depreciation, cost of service, and cost of capital. Southwest’s last general rate increase in Nevada occurred in 2009.

Pipe Replacement Tracking Mechanisms

Customer-Owned Yardline (“COYL”) Program. There are 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 new program (as part of its recent 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. The costs of the replacement portion of this program will be capitalized by the Company. Subject to an annual reporting requirement, a surcharge will be 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 recently concluded 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).

Nevada Pipe Replacement Program. The Company has 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 has 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.


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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- and under-collections. At December 31, 2011, over-collections in Arizona and Nevada resulted in a liability of $72.4 million and under-collections in California resulted in an asset of $2.3 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):


	2011			2010
Arizona	$	(28.4	)	$	(45.2	)
Northern Nevada		(7.9	)		(8.4	)
Southern Nevada		(36.1	)		(69.8	)
California		2.3			0.4

	$	(70.1	)	$	(123.0	)

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, which continued throughout 2011. On an annual basis, the surcredit is designed to refund approximately $40 million; however, continued low natural gas prices have resulted in a continuing balance due customers. A prudence review of gas costs is conducted in conjunction with general rate cases.

California Gas Cost Filings. In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments 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 2011, 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 Recovery, the Uncollectible Gas Cost Expense rates, and other rate-related items). Recently approved legislation allows Southwest to make quarterly DEAA adjustments based upon a twelve-month rolling average. Southwest filed its first quarterly DEAA rate adjustment application under the new rules in July 2011, which was approved, and was made effective in October 2011.

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 2011/2012 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $7 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.


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Capital Resources and Liquidity

Cash on hand and cash flows from operations in 2011 provided the majority of cash used in investing activities (primarily for construction expenditures and property additions). Certain pipe replacement work was accelerated during 2011 to take advantage of bonus depreciation tax incentives. In 2009 and 2010, cash on hand and cash flows from operations were generally sufficient to provide for net investing activities and the Company was able to reduce the net amount of debt outstanding (including subordinated debentures and short-term borrowings) as well as amounts due to customers under its PGA mechanisms. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt.

Cash Flows

Operating Cash Flows. Cash flows provided by consolidated operating activities decreased $119 million in 2011 as compared to 2010. An increase in operating cash flows attributable to greater net income and non-cash depreciation expense was more than offset by temporary cash flow reductions in working capital components, most notably, deferred purchased gas costs and accounts receivable.

Investing Cash Flows. Cash used in consolidated investing activities increased $156 million in 2011 as compared to 2010. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement (to take advantage of bonus depreciation tax incentives), and equipment purchases by NPL due to the increased replacement construction work of its customers. Offsetting these cash outflows in 2011 and 2010 were draw-downs of funds, restricted to utilization for construction activities, associated with an industrial development revenue bond issuance in 2009.

Financing Cash Flows. Net cash provided by consolidated financing activities increased $130 million in 2011 as compared to 2010 primarily due to the issuance of new debt including $125 million 6.1% Senior Notes and borrowings on Southwest’s credit facility, partially offset by debt repayments including the $200 million 8.375% Notes repaid in February 2011. 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 period included the redemption of the subordinated debentures as well as the repayment of other debt, primarily repayment of previous borrowings under Southwest’s credit facility. See also 2011 Financing Activity below. Dividends paid increased in 2011 as compared to 2010 as a result of a quarterly dividend increase and an increase in the number of shares outstanding.

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

2011 Construction Expenditures

During the three-year period ended December 31, 2011, total gas plant increased from $4.3 billion to $4.8 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 48,000 meters, resulting in 40,000 net new customers during the three-year period.

During 2011, construction expenditures for the natural gas operations segment were $306 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 $217 million and provided approximately 61% 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.


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2011 Financing Activity

In December 2010, the Company issued $125 million in 4.45% Senior Notes, due December 2020 at a discount of 0.182%. A portion of the net proceeds was used to pay down borrowings under the credit facility. In February 2011, the Company used approximately $75 million of the remaining net proceeds in connection with its repayment of the 8.375% $200 million Notes that matured in February 2011. The remaining proceeds were used for general corporate purposes.

In February 2011, the Company issued $125 million of 6.1% Senior Notes to certain institutional investors pursuant to a November 2010 note purchase agreement. The Senior Notes are unsecured and unsubordinated obligations of the Company, due in February 2041. Funds from the issuance were used to partially repay the 8.375% $200 million Notes that matured in February 2011.

During 2011, the Company issued shares of common stock through its various stock plans, including the Stock Incentive Plan, raising approximately $7 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 provides 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 extends the availability of the 50% bonus tax depreciation deduction through December 31, 2012.

As a result of the two acts signed into law in 2010, 50% bonus tax depreciation will be available for qualified property acquired or constructed and placed in service from January 1, 2012 through December 31, 2012. Bonus tax depreciation of 100% applied to qualified property acquired or constructed and placed in service from September 9, 2010 through December 31, 2011. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provisions of the two acts will defer the payment of approximately $62 million and $28 million of federal income taxes during 2011 and 2012, respectively.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2014 will range from approximately $750 million to $1 billion. Of this amount, approximately $300 million are expected to be incurred in 2012. Southwest is taking advantage of bonus depreciation to accelerate projects that improve system flexibility and enhance safety (including replacement of early vintage plastic and steel pipe). Significant replacement projects 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 a substantial majority of the funding for the gas operations total construction expenditures and dividend requirements. During the three-year period, the Company expects to raise additional funds from its various common stock programs. Southwest also has $12.8 million in restricted cash from a 2009 Industrial Development Revenue Bond offering that was drawn upon in February 2012 to fund qualifying construction expenditures in southern Nevada. 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 these 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. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

Southwest also has $200 million of long-term debt maturing in May 2012 and expects to refinance the $200 million of debentures by the maturity date. In connection with the planned 2012 debt issuance, the Company, in January 2010, entered into a forward-starting interest rate swap (“FSIRS”) agreement with a notional amount of $100 million to hedge the risk of interest rate variability during the period leading up to the planned issuance. See Note 13 - Derivatives and Fair Value Measurements for more information on the FSIRS.


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

Liquidity

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

On an interim basis, Southwest 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, 2011, the combined balance in the PGA accounts totaled an over-collection of $70.1 million. See PGA Filings for more information on recent regulatory filings.

The Company has a $300 million credit facility that expires in May 2012. At December 31, 2011, $109 million was outstanding on the credit facility. Borrowings under the credit facility ranged from $0 for the first eight months of 2011 to a maximum of $121 million during December 2011. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any, or meeting the refund needs of over-collected balances. This credit facility has been adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing. Management intends to replenish its borrowing capacity during the first quarter of 2012.

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 June 2011, Fitch Ratings (“Fitch”) upgraded the Company’s long-term issuer debt rating and its senior unsecured rating to BBB+ from BBB; the outlook has been revised to stable from positive. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB+ indicates a credit quality that is considered prudent for investment.

In April 2011, Standard & Poor’s Ratings Services (“S&P”) upgraded the Company’s unsecured long-term debt ratings from BBB (with a positive outlook) to BBB+ (with a stable outlook). S&P cited the Company’s improved financial results and stable financial metrics. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal.

The Company’s unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is Baa2 with a stable outlook as of May 2010. 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.


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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, 2011, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.6 billion in additional debt and meet the leverage ratio requirement. The Company has at least $600 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.

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, 2011 (millions of dollars):


	Payments due by period
Contractual Obligations	Total		2012		2013-2014		2015-2016		Thereafter
Operating activities:
Operating leases (Note 2)	$	22	$	6	$	9	$	6	$	1
Gas purchase obligations		212		154		57		1		—
Pipeline capacity		803		95		167		139		402
Derivatives (Note 13)		37		36		1		—		—
Other commitments		11		6		4		1		—
Financing activities:
Long-term debt, including current maturities (Note 7)		1,253		323		19		1		910
Interest on long-term debt		881		46		89		89		657
Other		16		—		1		2		13

Total	$	3,235	$	666	$	347	$	239	$	1,983


Southwest Gas Corporation		33

Obligations for Operating Activities: The table 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 165 million dekatherms. Fixed-price contracts range in price from approximately $4 to $7 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.

Other: Estimated funding for pension and other postretirement benefits during calendar year 2012 is $47 million.

Results of Construction Services


Year Ended December 31,	2011			2010			2009
(Thousands of dollars)
Construction revenues	$	483,822		$	318,464		$	278,981
Operating expenses:
Construction expenses		423,703			277,804			242,461
Depreciation and amortization		25,216			20,007			23,232

Operating income		34,903			20,653			13,288
Other income (deductions)		(8	)		(166	)		55
Net interest deductions		825			564			1,179

Income before income taxes		34,070			19,923			12,164
Income tax expense		13,727			7,852			4,466

Net income		20,343			12,071			7,698
Net income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)

Contribution to consolidated net income attributable to NPL	$	20,867		$	12,495		$	8,062

2011 vs. 2010

Contribution to consolidated net income from construction services for 2011 increased $8.4 million compared to 2010. The increase was due primarily to revenue growth. Gains on sales of equipment were $3.3 million and $1.5 million in 2011 and 2010, respectively.

During the past two years, NPL has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. Federal and state pipeline safety-related programs and bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. NPL’s established relationships with utilities and history of quality work and expertise are anticipated to result in a sustained level of performance and the potential for growth in the replacement market for the next several years.

Revenues increased $165 million, a 52% improvement, when compared to 2010 primarily due to increased replacement construction. The construction revenues include 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.


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Construction expenses increased $146 million, or 53%, between years 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 years due to an increase in outstanding debt.

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 and profit are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating results typically improve as more favorable weather conditions occur during the summer and fall months. Current low interest rates, 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 growth and resulting earnings.

2010 vs. 2009

Contribution to consolidated net income from construction services for 2010 increased $4.4 million compared to 2009. The increase was due primarily to revenue growth and a reduction in depreciation expense. Gains on sales of equipment were $1.5 million for 2010 and $3.3 million for 2009.

The prolonged economic downturn and general slowdown in the new housing market dramatically reduced the amount of new construction activities in 2010. NPL was able to offset reductions in new construction with replacement work received under existing blanket contracts and incremental bid work in 2010.

Revenues increased $39.5 million due primarily to increased replacement and bid work. The construction revenues include NPL contracts with Southwest totaling $61.3 million in 2010 and $52.6 million in 2009. NPL accounts for the services provided to Southwest at contractual (market) prices.

Construction expenses increased $35.3 million due primarily to the overall increase in construction work, partially offset by cost savings initiatives and a $1.1 million payroll tax credit from the Hiring Incentives to Restore Employment Act. Depreciation expense decreased $3.2 million as a result of a reduction in the construction equipment fleet. Interest expense decreased $615,000 between years due to a reduction in outstanding debt.

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates dealing with the presentation of comprehensive income, disclosures about fair value measurements, goodwill impairment testing, and the offsetting of assets and liabilities on the balance sheets. 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.


Southwest Gas Corporation		35

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, net revenues for natural gas that has been delivered but not yet billed are accrued. This accrued utility revenue is estimated each month based on daily sales volumes, applicable rates, number of customers, rate structure, analyses reflecting significant historical trends, weather, and experience. In periods of extreme weather conditions, the interplay of these assumptions could impact the variability of the accrued utility revenue estimates. The California and Nevada rate jurisdictions have decoupled rate structures in place such that when combined with Arizona’s decoupled rate structure effective January 2012, variability due to extreme weather conditions will be significantly reduced.

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 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 $24.8 million and future pension expense by $2.7 million. A change of


Southwest Gas Corporation		36

0.25% in the employee compensation assumption would change the pension obligation by approximately $6.1 million and expense by $1.3 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.4 million (but has no impact on the pension obligation).

At December 31, 2011, the Company lowered the discount rate to 5.00% from a rate of 5.75% at December 31, 2010. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase decreased to 3.00% at December 31, 2011 from 3.25% in the prior year. The asset return assumption remains the same at 8.00%. Low asset returns were experienced during 2011, relative to the assumed rate of return. This, combined with significant favorable returns in 2010 and 2009, partially offset substantial losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2012. Pension expense for 2012 is estimated to increase by $7.5 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 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, 2011 are included as exhibits to the 2011 Annual Report on Form 10-K filed with the SEC.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “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, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, amount and timing for completion of estimated future construction expenditures, forecasted operating cash flows and results of operations, incremental margin in 2012, operating expense increases in 2012, 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, the amount and form of any such financing, plans to fund maturing obligations, expected interest rate upon refinancing maturing debt. the effectiveness of forward-starting interest rate swap agreements in hedging against changing interest rates, future dividend increases, earnings trends, pension and post-retirement benefits, liquidity, certain benefits of tax acts, the effect of rate decoupling in Arizona, the impact of fuel switching by large customers, expenditures for compliance with any EPA requirements, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, and the impact of certain legal proceedings 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, renewal of franchises, easements and rights-of-way, 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, acquisitions and management’s plans related


Southwest Gas Corporation		37

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 operations and maintenance 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, 2011.

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

Common Stock Price and Dividend Information


	2011				2010				Dividends Declared
	High		Low		High		Low		2011		2010
First quarter	$	39.68	$	36.33	$	30.70	$	26.28	$	0.265	$	0.250
Second quarter		40.59		36.61		32.91		28.12	$	0.265	$	0.250
Third quarter		39.92		32.12		34.06		28.58	$	0.265	$	0.250
Fourth quarter		43.20		34.55		37.25		33.41	$	0.265	$	0.250

									$	1.060	$	1.000

In reviewing dividend policy, the Board of Directors (“Board”) considers the adequacy and sustainability of the 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 23.75 cents per share throughout 2009, 25 cents per share throughout 2010, and 26.5 cents per share throughout 2011. As a result of its ongoing review of dividend policy, in February 2012, the Board increased the quarterly dividend from 26.5 cents to 29.5 cents per share, effective with the June 2012 payment. This marks the sixth consecutive year in which the dividend was increased. Over time, the Board intends to prudently increase the dividend such that the payout ratio approaches a local distribution company peer group average while not compromising the Company’s stable and strong credit ratings or the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Board’s review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects.


Southwest Gas Corporation		38

Southwest Gas Corporation

Consolidated Balance Sheets

(Thousands of dollars, except par value)



December 31,	2011			2010
ASSETS
Utility plant:
Gas plant	$	4,811,050		$	4,569,105
Less: accumulated depreciation		(1,638,091	)		(1,535,429	)
Acquisition adjustments, net		1,091			1,271
Construction work in progress		44,894			37,489

Net utility plant (Note 2)		3,218,944			3,072,436

Other property and investments		192,004			134,648

Restricted cash		12,785			37,781

Current assets:
Cash and cash equivalents		21,937			116,096
Accounts receivable, net of allowances (Note 3)		209,246			147,605
Accrued utility revenue		70,300			64,400
Income taxes receivable, net		7,793			21,514
Deferred income taxes (Note 12)		53,435			8,046
Deferred purchased gas costs (Note 4)		2,323			356
Prepaids and other current assets (Note 4)		96,598			87,877

Total current assets		461,632			445,894

Deferred charges and other assets (Notes 4 and 13)		390,642			293,434

Total assets	$	4,276,007		$	3,984,193


Southwest Gas Corporation		39

Consolidated Balance Sheets - Continued



December 31,	2011			2010
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 45,956,088 and 45,599,036 shares) (Note 11)	$	47,586		$	47,229
Additional paid-in capital		821,640			807,885
Accumulated other comprehensive income (loss), net (Note 5)		(49,331	)		(30,784	)
Retained earnings		406,125			343,131

Total Southwest Gas Corporation equity		1,226,020			1,167,461
Noncontrolling interest		(989	)		(465	)

Total equity		1,225,031			1,166,996
Long-term debt, less current maturities (Note 7)		930,858			1,124,681

Total capitalization		2,155,889			2,291,677

Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		322,618			75,080
Accounts payable		186,755			165,536
Customer deposits		83,839			86,891
Accrued general taxes		42,102			40,438
Accrued interest		16,699			20,162
Deferred purchased gas costs (Note 4)		72,426			123,344
Other current liabilities (Notes 4 and 13)		123,129			85,510

Total current liabilities		847,568			596,961

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 12)		557,118			466,628
Taxes payable		828			1,234
Accumulated removal costs (Note 4)		233,000			211,000
Other deferred credits (Notes 4 and 10)		481,604			416,693

Total deferred income taxes and other credits		1,272,550			1,095,555

Total capitalization and liabilities	$	4,276,007		$	3,984,193

The accompanying notes are an integral part of these statements.


Southwest Gas Corporation		40

Southwest Gas Corporation

Consolidated Statements of Income

(In thousands, except per share amounts)



Year Ended December 31,	2011			2010			2009
Operating revenues:
Gas operating revenues	$	1,403,366		$	1,511,907		$	1,614,843
Construction revenues		483,822			318,464			278,981

Total operating revenues		1,887,188			1,830,371			1,893,824

Operating expenses:
Net cost of gas sold		613,489			736,175			866,630
Operations and maintenance		358,498			354,943			348,942
Depreciation and amortization		200,469			190,463			190,082
Taxes other than income taxes		40,949			38,869			37,318
Construction expenses		423,703			277,804			242,461

Total operating expenses		1,637,108			1,598,254			1,685,433

Operating income		250,080			232,117			208,391

Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(69,602	)		(75,677	)		(75,270	)
Net interest deductions on subordinated debentures (Note 6)		—			(1,912	)		(7,731	)
Other income (deductions)		(5,412	)		3,850			6,645

Total other income and (expenses)		(75,014	)		(73,739	)		(76,356	)

Income before income taxes		175,066			158,378			132,035
Income tax expense (Note 12)		63,303			54,925			44,917

Net income		111,763			103,453			87,118
Net income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)

Net income attributable to Southwest Gas Corporation	$	112,287		$	103,877		$	87,482

Basic earnings per share (Note 15)	$	2.45		$	2.29		$	1.95

Diluted earnings per share (Note 15)	$	2.43		$	2.27		$	1.94


Average number of common shares outstanding		45,858			45,405			44,752
Average shares outstanding (assuming dilution)		46,291			45,823			45,062

The accompanying notes are an integral part of these statements.


Southwest Gas Corporation		41

Southwest Gas Corporation

Consolidated Statements of Comprehensive Income

(Thousands of dollars)



Year Ended December 31,	2011			2010			2009
Net Income	$	111,763		$	103,453		$	87,118

Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)		(84,005	)		(5,616	)		(16,398	)
Amortization of prior service credit		—			—			(1	)
Amortization of transition obligation		537			538			538
Amortization of net loss		9,653			7,516			3,470
Regulatory adjustment		65,677			404			9,567

Net defined benefit pension plans		(8,138	)		2,842			(2,824	)

Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 13)		(11,134	)		(11,436	)		—
Amounts reclassified into net income (Notes 5 and 13)		725			60			—

Net forward-starting interest rate swaps		(10,409	)		(11,376	)		—

Total other comprehensive income (loss), net of tax		(18,547	)		(8,534	)		(2,824	)

Comprehensive income	$	93,216		$	94,919		$	84,294
Comprehensive income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)

Comprehensive income attributable to Southwest Gas Corporation	$	93,740		$	95,343		$	84,658

The accompanying notes are an integral part of these statements.


Southwest Gas Corporation		42

Southwest Gas Corporation

Consolidated Statements of Cash Flows

(Thousands of dollars)



Year Ended December 31,	2011			2010			2009
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	111,763		$	103,453		$	87,118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		200,469			190,463			190,082
Deferred income taxes		56,467			50,111			42,798
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(61,641	)		10,117			11,107
Accrued utility revenue		(5,900	)		7,300			900
Deferred purchased gas costs		(52,885	)		33,013			56,902
Accounts payable		15,826			6,680			(32,578	)
Accrued taxes		14,979			(15,240	)		22,497
Other current assets and liabilities		(3,347	)		12,895			32,733
Gains on sale		(3,307	)		(1,547	)		(3,291	)
Changes in undistributed stock compensation		6,125			4,429			3,942
AFUDC and property-related changes		(1,154	)		(945	)		(1,221	)
Changes in other assets and deferred charges		11,025			(12,262	)		(15,553	)
Changes in other liabilities and deferred credits		(36,378	)		(17,474	)		10,366

Net cash provided by operating activities		252,042			370,993			405,802


Southwest Gas Corporation		43

Consolidated Statements of Cash Flows - Continued



Year Ended December 31,	2011			2010			2009
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(380,991	)		(215,439	)		(216,985	)
Restricted cash		24,996			11,988			(49,769	)
Changes in customer advances		(7,771	)		(830	)		(2,476	)
Miscellaneous inflows		7,686			4,075			7,933
Miscellaneous outflows		(2,719	)		(2,800	)		(3,620	)

Net cash provided by (used in) investing activities		(358,799	)		(203,006	)		(264,917	)

CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		7,402			11,098			18,401
Dividends paid		(47,929	)		(44,846	)		(41,950	)
Interest rate swap settlement		—			(11,691	)		—
Issuance of long-term debt, net		274,598			123,960			49,834
Retirement of long-term debt		(330,473	)		(3,327	)		(15,654	)
Redemption of subordinated debentures		—			(100,000	)		—
Change in credit facility		109,000			(92,400	)		(57,600	)
Change in short-term debt		—			—			(55,000	)

Net cash provided by (used in) financing activities		12,598			(117,206	)		(101,969	)

Change in cash and cash equivalents		(94,159	)		50,781			38,916
Cash and cash equivalents at beginning of period		116,096			65,315			26,399

Cash and cash equivalents at end of period	$	21,937		$	116,096		$	65,315

Supplemental information:
Interest paid, net of amounts capitalized	$	69,842		$	87,000		$	80,771

Income taxes paid (received)	$	(13,635	)	$	19,200		$	(21,616	)

The accompanying notes are an integral part of these statements.


Southwest Gas Corporation		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		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total

DECEMBER 31, 2008		44,192		$	45,822	$	770,463	$	(19,426	)	$	240,982		$	—		$	1,037,841
Common stock issuances		900			900		21,876											22,776
Net income (loss)												87,482			(364	)		87,118
Noncontrolling interest capital investment															323			323
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)									(2,824	)								(2,824	)
Dividends declared Common: $0.95 per share												(43,148	)					(43,148	)

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	)

DECEMBER 31, 2011		45,956	*	$	47,586	$	821,640	$	(49,331	)	$	406,125		$	(989	)	$	1,225,031

*At December 31, 2011, 2.1 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 177,000 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.


Southwest Gas Corporation		45

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. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. 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 the 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.

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.

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.


Southwest Gas Corporation		46

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, 2011		December 31, 2010
Accumulated removal costs	$	233,000	$	211,000

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 amount of natural gas distributed, 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 franchise fees, sales and use taxes, and surcharges. These taxes are not included in gas operating revenues, except for certain franchise fees in California operating jurisdictions which are not significant. 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 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.

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


Southwest Gas Corporation		47

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.


	2011		2010		2009
(In thousands)
AFUDC:
Debt portion	$	718	$	512	$	957
Equity portion		1,154		945		1,221

AFUDC capitalized as part of utility plant	$	1,872	$	1,457	$	2,178

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):


	2011			2010			2009
Change in COLI policies	$	700		$	9,770		$	8,546
Interest income		485			194			271
Pipe replacement costs		(4,761	)		(5,024	)		(2,642	)
Miscellaneous income and (expense)		(1,836	)		(1,090	)		470

Total other income (deductions)	$	(5,412	)	$	3,850		$	6,645

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.

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.


	2011		2010		2009
(In thousands)
Average basic shares		45,858		45,405		44,752
Effect of dilutive securities:
Stock options		52		56		14
Performance shares		271		260		216
Restrictled stock units		110		102		80

Average diluted shares		46,291		45,823		45,062


Southwest Gas Corporation		48

Out-of-Period Adjustment. In September 2011, the Company identified an isolated error in a regulatory deferral mechanism that overstated revenues by $3.7 million for periods prior to the third quarter of 2011. Management concluded the error was not material to any individual prior interim or annual period (or to the current annual period) and, therefore, the error was corrected during the third quarter of 2011. The effect was a decrease in revenues and regulatory assets of $3.7 million, of which $2.9 million pertains to years prior to 2011.

Recently Issued Accounting Standards Updates. In May 2011, the Financial Accounting Standards Board (“FASB”) issued the update “Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The amended guidance includes several new fair value disclosure requirements, including, among other things, information about transfers between Level 1 and Level 2 of the fair value hierarchy, enhanced information about valuation techniques and unobservable inputs used in Level 3 fair value measurements, and a narrative description of Level 3 measurements’ sensitivity to changes in unobservable inputs. For the Company, the update is effective prospectively beginning January 2012. The adoption of the update is not expected to significantly impact the disclosures of the Company.

In June 2011, The FASB issued the update “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” which eliminates the current option to report the components of other comprehensive income in the statement of changes in equity. An entity will have the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in one continuous statement of comprehensive income or in two separate but consecutive statements. The update includes no changes to the components that are recognized in net income or other comprehensive income under current U.S. GAAP. In December 2011, the FASB issued the update “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” to defer the requirement in the previous update to present reclassifications out of accumulated other comprehensive income separately in the income statement. The Company chose to present two separate but consecutive statements and to adopt the update as of December 31, 2011, as permitted.

In September 2011, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350) Testing Goodwill for Impairment.” The update is intended to simplify how entities test goodwill for impairment. The update permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350 “Intangibles – Goodwill and Other.” The more-likely-than-not threshold is defined as having a likelihood of more than 50%. The Company chose to adopt the update as of December 31, 2011 as permitted. The update did not have an impact on the Company’s financial position or results of operations.

In December 2011, the FASB issued the update “Balance Sheet (Topic 210).” 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. The Company will adopt this update, as required, on January 1, 2013 for interim and annual reporting periods. All disclosures are required to be provided retrospectively for all periods presented. This update is not expected to have a material impact on the Company’s disclosures.

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


Southwest Gas Corporation		49

Note 2 – Utility Plant

Net utility plant as of December 31, 2011 and 2010 was as follows (thousands of dollars):


December 31,	2011			2010
Gas plant:
Storage	$	20,496		$	20,396
Transmission		295,103			274,646
Distribution		4,048,078			3,847,731
General		291,639			279,402
Other		155,734			146,930

		4,811,050			4,569,105
Less: accumulated depreciation		(1,638,091	)		(1,535,429	)
Acquisition adjustments, net		1,091			1,271
Construction work in progress		44,894			37,489

Net utility plant	$	3,218,944		$	3,072,436

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


	2011		2010		2009
Depreciation and amortization expense	$	172,712	$	167,050	$	162,240

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.


	2012		2013		2014		2015		2016		2017
(In thousands)
Corporate headquarters (expires in 2017)	$	2,100	$	2,140	$	2,190	$	2,270	$	2,343	$	1,194
Phoenix administrative offices (expires in 2014)		1,396		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 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):


	2011		2010		2009
Southwest Gas	$	7,812	$	7,585	$	8,630
NPL		19,017		11,780		11,301

Consolidated rental payments/lease expense	$	26,829	$	19,365	$	19,931


Southwest Gas Corporation		50

The following is a schedule of future minimum lease payments for significant non-cancelable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2011 (thousands of dollars):


Year Ending December 31,
2012	$	6,310
2013		5,674
2014		3,358
2015		2,881
2016		2,449
Thereafter		1,194

Total minimum lease payments	$	21,866

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, 2011, and the percentage of customers in each of the three states.


Gas utility customer accounts receivable balance (in thousands)	$	124,794

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 based on experience and recorded monthly, as needed. They are included in the ratemaking process as a cost of service. Beginning in November 2009, a regulatory mechanism was implemented in the Nevada jurisdictions 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, 2008	$	3,788
Additions charged to expense		6,658
Accounts written off, less recoveries		(6,493	)

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


Southwest Gas Corporation		51

Note 4 - Regulatory Assets and Liabilities

Natural gas operations are subject to the regulation of the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”). 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,	2011			2010
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	330,844		$	224,913
Unrealized loss on non-trading derivatives (Swaps) (2)		11,743			11,482
Deferred purchased gas costs (3)		2,323			356
Accrued purchased gas costs (4)		18,400			14,000
Unamortized premium on reacquired debt (5)		19,011			19,881
Other (6)		32,988			28,402

		415,309			299,034
Regulatory liabilities:
Deferred purchased gas costs (3)		(72,426	)		(123,344	)
Accumulated removal costs		(233,000	)		(211,000	)
Unrealized gain on non-trading derivatives (Swaps) (2)		—			(656	)
Deferred gain on southern Nevada division operations facility (7)		(806	)		(1,246	)
Rate refunds due customers (8)		—			(546	)
Unamortized gain on reacquired debt (9)		(12,470	)		(13,006	)
Other (10)		(14,501	)		(2,811	)

Net regulatory assets (liabilities)	$	82,106		$	(53,575	)

(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	2011		2010
Swaps	Deferred charges and other assets	$	621	$	—
Swaps	Prepaids and other current assets		11,122		11,482
Swaps	Other deferred credits		—		(656	)

(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.


Southwest Gas Corporation		52

(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 recovered over a four-year period beginning in the fourth quarter of 2009.

(8)	Included in Other current liabilities on the Consolidated Balance Sheet.

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

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

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

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)								AOCI
	Before- Tax			Tax (Expense) Benefit		After- Tax			Before- Tax			Tax (Expense) Benefit		After-Tax			AOCI
Beginning Balance AOCI December 31, 2010	$	(31,304	)	$	11,896	$	(19,408	)	$	(18,349	)	$	6,973	$	(11,376	)	$	(30,784	)
Current period other comprehensive income (loss)		(13,125	)		4,987		(8,138	)		(16,789	)		6,380		(10,409	)		(18,547	)

Ending Balance AOCI December 31, 2011	$	(44,429	)	$	16,883	$	(27,546	)	$	(35,138	)	$	13,353	$	(21,785	)	$	(49,331	)

Approximately $1.9 million of realized losses (net of tax) related to the FSIRS reported in AOCI at December 31, 2011 will be reclassified into expense within the next twelve months as the related interest payments on long-term debt occur.

The information below provides insight into amounts impacting Other Comprehensive Income (Loss), before and after- tax impacts, 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.


Southwest Gas Corporation		53

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


	2011									2010									2009
	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)	$	(135,492	)	$	51,487		$	(84,005	)	$	(9,058	)	$	3,442		$	(5,616	)	$	(26,448	)	$	10,050		$	(16,398	)
Amortization of prior service credit		—			—			—			—			—			—			(2	)		1			(1	)
Amortization of transition obligation		867			(330	)		537			867			(329	)		538			867			(329	)		538
Amortization of net loss		15,569			(5,916	)		9,653			12,122			(4,606	)		7,516			5,596			(2,126	)		3,470
Regulatory adjustment		105,931			(40,254	)		65,677			652			(248	)		404			15,431			(5,864	)		9,567

Pension plans other comprehensive income (loss)		(13,125	)		4,987			(8,138	)		4,583			(1,741	)		2,842			(4,556	)		1,732			(2,824	)
FSIRS (designated hedging activities):

Unrealized/realized loss		(17,958	)		6,824			(11,134	)		(18,446	)		7,010			(11,436	)		—			—			—
Amounts reclassified into net income		1,169			(444	)		725			97			(37	)		60			—			—			—

FSIRS other comprehensive income (loss)		(16,789	)		6,380			(10,409	)		(18,349	)		6,973			(11,376	)		—			—			—

Total other comprehensive income (loss)	$	(29,914	)	$	11,367		$	(18,547	)	$	(13,766	)	$	5,232		$	(8,534	)	$	(4,556	)	$	1,732		$	(2,824	)

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

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


Retirement plan net actuarial loss	$	24,000
SERP net actuarial loss		700
PBOP net actuarial loss		1,000
PBOP transition obligation		870

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 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.


Southwest Gas Corporation		54

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 $300 million credit facility.

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

Note 7 – Long-Term Debt


December 31,	2011					2010
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011	$	—		$	—	$	200,000		$	201,560
Notes, 7.625%, due 2012		200,000			204,312		200,000			214,666
Notes, 4.45%, due 2020		125,000			128,673		125,000			125,325
Notes, 6.1%, due 2041		125,000			143,074		—			—
8% Series, due 2026		75,000			96,340		75,000			99,968
Medium-term notes, 7.59% series, due 2017		25,000			30,199		25,000			30,295
Medium-term notes, 7.78% series, due 2022		25,000			31,932		25,000			32,063
Medium-term notes, 7.92% series, due 2027		25,000			31,648		25,000			33,211
Medium-term notes, 6.76% series, due 2027		7,500			8,510		7,500			8,956
Unamortized discount		(2,087	)				(2,534	)

		605,413					679,966

Revolving credit facility and commercial paper, due 2012		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		12,410			11,968
5.95% 1999 Series C, due 2038		14,320			14,449		14,320			13,594
5.55% 1999 Series D, due 2038		8,270			8,253		8,270			7,468
5.45% 2003 Series C, due 2038 (rate resets in 2013)		30,000			31,332		30,000			31,547
5.25% 2003 Series D, due 2038		20,000			19,583		20,000			17,474
5.80% 2003 Series E, due 2038 (rate resets in 2013)		15,000			15,634		15,000			15,436
5.25% 2004 Series A, due 2034		65,000			64,291		65,000			58,574
5.00% 2004 Series B, due 2033		31,200			30,283		31,200			27,295
4.85% 2005 Series A, due 2035		100,000			94,836		100,000			84,485
4.75% 2006 Series A, due 2036		24,855			23,179		24,855			20,518
Unamortized discount		(3,360	)				(3,502	)

		517,695					517,553

NPL debt obligations		21,368			21,380		2,242			2,473

		1,253,476					1,199,761
Less: current maturities		(322,618	)				(75,080	)

Long-term debt, less current maturities	$	930,858				$	1,124,681


Southwest Gas Corporation		55

The Company has a $300 million credit facility that expires in May 2012. The Company has designated $150 million for long-term purposes and the remaining $150 million for working capital purposes. Interest rates for the facility are calculated at either the London Interbank Offering Rate plus an applicable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. At December 31, 2011, $109 million was outstanding on the credit facility and is reflected as current maturities of the long-term debt in the schedule above. Borrowings under the credit facility ranged from $0 for the first eight months of the year to a maximum of $121 million during December 2011. The effective interest rate on the long-term portion of the credit facility was 0.7% at December 31, 2011. There were no borrowings outstanding on the short-term portion of the credit facility at December 31, 2010 and 2011. (See Note 8 – Short-Term Debt). Management intends to refinance its borrowing capacity under the facility during the first quarter of 2012.

In January 2012, the Company redeemed its $12.4 million 1999 6.1% Series A fixed-rate IDRBs at par originally due in 2038. These IDRBs are shown as current maturities in the schedule above.

In November 2010, the Company entered into a note purchase agreement with Metropolitan Life Insurance Company, John Hancock Life Insurance Company (U.S.A.), certain of their respective affiliates, and Union Fidelity Life Insurance Company (collectively, the “Purchasers”), pursuant to which the Company agreed to issue $125 million of 6.1% Senior Notes to the Purchasers. In February 2011, the Company issued $125 million of 6.1% Senior Notes pursuant to the agreement and used the proceeds to partially redeem the 8.375% debentures that matured in February 2011. The Senior Notes are unsecured and unsubordinated obligations of the Company, due in February 2041.

In December 2010, the Company issued $125 million in 4.45% Senior Notes due December 2020 at a 0.182% discount. The notes will mature on December 1, 2020. In February 2011, the Company used $75 million of the proceeds to repay a portion of the $200 million 8.375% Notes; the remaining net proceeds were used for general corporate purposes.

In December 2009, the Company issued $50 million in Clark County, Nevada variable-rate 2009 Series A IDRBs, supported by a letter of credit with JPMorgan Chase Bank. At December 31, 2010 and 2011, $37.8 million and $12.8 million, respectively, in proceeds from the issuance of IDRBs remained in trust and are shown as restricted cash on the consolidated balance sheets. The remaining $12.8 million in trust funds were drawn in February 2012.

The $200 million 7.625% notes due in May 2012 are shown as current maturities, but are expected to be refinanced before the maturity date. See Note 13 – Derivatives and Fair Value Measurements.

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


	December 31, 2011			December 31, 2010
2003 Series A		0.83	%		1.20	%
2008 Series A		1.62	%		2.72	%
2009 Series A		1.56	%		2.68	%
Tax-exempt Series A		2.22	%		1.18	%

In Nevada, interest fluctuations due to changing interest rates on the 2003 Series A and 2008 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account. The 2009 Series A IDRBs were issued after the effective date of the last Nevada general rate case and, therefore, related interest fluctuations for that Series are not part of the tracking mechanism.

The fair values of the revolving credit facility and the variable-rate IDRBs approximate carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for December 31, 2011 and 2010, as applicable, and other secondary sources which are customarily consulted for data of this kind.


Southwest Gas Corporation		56

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


2012	$	322,618
2013		17,805
2014		1,271
2015		1,084
2016		—

After 2012, all debt maturities indicated above relate to debt obligations of NPL.

Note 8 - Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that expires in May 2012, of which $150 million of the $300 million facility was designated by management for working capital purposes. The Company had no short-term borrowings outstanding at December 31, 2010 and 2011. Management intends to refinance its borrowing capacity during the first quarter of 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 has been 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. 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):


	2011		2010		2009
Employee Investment Plan cost	$	4,626	$	4,583	$	4,511

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


Southwest Gas Corporation		57

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


Southwest Gas Corporation		58

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 2011 from 2010. 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 2011 from 2010 and the asset return assumption was unchanged between periods. The rates are presented in the table below:


	December 31, 2011			December 31, 2010
Discount rate		5.00	%		5.75	%
Weighted-average rate of compensation increase		3.00	%		3.25	%
Asset return assumption		8.00	%		8.00	%

Low asset returns were experienced during 2011, relative to the assumed rate of return. This, combined with significant favorable returns in 2010 and 2009, partially offset substantial losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2012. Pension expense for 2012 is estimated to increase by $7.5 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 status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.


	2011									2010
	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)	$	662,134		$	31,860		$	46,765		$	606,276		$	35,339		$	42,322
Service cost		17,725			217			858			16,932			372			856
Interest cost		37,276			1,766			2,631			35,614			2,045			2,491
Actuarial loss (gain)		89,922			2,427			2,835			27,680			(3,480	)		2,632
Benefits paid		(26,486	)		(2,443	)		(907	)		(24,368	)		(2,416	)		(1,536	)

Benefit obligation at end of year (PBO/PBO/APBO)		780,571			33,827			52,182			662,134			31,860			46,765

Change in plan assets
Market value of plan assets at beginning of year		475,931			-			29,640			392,975			-			25,511
Actual return on plan assets		2,384			-			(200	)		53,224			-			3,181
Employer contributions		70,000			2,443			904			54,100			2,416			1,348
Benefits paid		(26,486	)		(2,443	)		(400	)		(24,368	)		(2,416	)		(400	)

Market value of plan assets at end of year		521,829			-			29,944			475,931			-			29,640

Funded status at year end	$	(258,742	)	$	(33,827	)	$	(22,238	)	$	(186,203	)	$	(31,860	)	$	(17,125	)

Weighted-average assumptions (benefit obligation)
Discount rate		5.00%			5.00%			5.00%			5.75%			5.75%			5.75%
Weighted-average rate of compensation increase		3.00%			3.00%			3.00%			3.25%			3.25%			3.25%


Southwest Gas Corporation		59

Estimated funding for the plans above during calendar year 2012 is approximately $47 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, 2011		December 31, 2010
Retirement plan	$	699,269	$	590,811
SERP		32,695		30,725

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


	2012		2013		2014		2015		2016		2017-2021
Pension	$	30.5	$	32.1	$	33.8	$	35.6	$	37.6	$	220.4
Retiree welfare		2.5		2.6		2.8		2.9		3.0		15.9
SERP		2.5		2.5		2.4		2.4		2.4		11.8

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

For PBOP measurement purposes, the per capita cost of 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
	2011			2010			2009			2011			2010			2009			2011			2010			2009
(Thousands of dollars)
Service cost	$	17,725		$	16,932		$	15,390		$	217		$	372		$	195		$	858		$	856		$	729
Interest cost		37,276			35,614			34,527			1,766			2,045			2,065			2,631			2,491			2,370
Expected return on plan assets		(40,114	)		(36,538	)		(35,221	)		—			—			—			(2,379	)		(2,093	)		(1,603	)
Amortization of prior service costs (credits)		—			—			(2	)		—			—			—			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			867			867
Amortization of net actuarial loss		14,348			10,478			4,253			631			1,155			909			590			489			434

Net periodic benefit cost	$	29,235		$	26,486		$	18,947		$	2,614		$	3,572		$	3,169		$	2,567		$	2,610		$	2,797

Weighted-average assumptions (net benefit cost)
Discount rate		5.75	%		6.00	%		6.75	%		5.75	%		6.00	%		6.75	%		5.75	%		6.00	%		6.75	%
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		3.25	%		3.25	%		3.75	%		3.25	%		3.25	%		3.75	%		3.25	%		3.25	%		3.75	%


Southwest Gas Corporation		60

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


	2011												2010												2009
	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)	$	135,492		$	127,651		$	2,427		$	5,414		$	9,058		$	10,994		$	(3,480	)	$	1,544		$	26,448		$	21,054		$	3,785		$	1,609
Amortization of prior service credit (b)		—			—			—			—			—			—			—			—			2			2			—			—
Amortization of transition obligation (b)		(867	)		—			—			(867	)		(867	)		—			—			(867	)		(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(15,569	)		(14,348	)		(631	)		(590	)		(12,122	)		(10,478	)		(1,155	)		(489	)		(5,596	)		(4,253	)		(909	)		(434	)
Regulatory adjustment		(105,931	)		(101,974	)		—			(3,957	)		(652	)		(464	)		—			(188	)		(15,431	)		(15,123	)		—			(308	)

Recognized in other comprehensive (income) loss	$	13,125		$	11,329		$	1,796		$	—		$	(4,583	)	$	52		$	(4,635	)	$	—		$	4,556		$	1,680		$	2,876		$	—
Net period benefit costs recognized in net income		34,416			29,235			2,614			2,567			32,668			26,486			3,572			2,610			24,913			18,947			3,169			2,797

Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	47,541		$	40,564		$	4,410		$	2,567		$	28,085		$	26,538		$	(1,063	)	$	2,610		$	29,469		$	20,627		$	6,045		$	2,797

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.


Southwest Gas Corporation		61

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, 2011 and December 31, 2010. The SERP has no assets.


	December 31, 2011						December 31, 2010
	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	$	48		$	2		$	50
Common stock
Capital equipment		4,332		133		4,465		11,083			362			11,445
Chemicals/materials		7,425		227		7,652		4,273			140			4,413
Consumer goods		40,806		1,249		42,055		35,491			1,158			36,649
Energy and mining		39,080		1,196		40,276		34,530			1,127			35,657
Finance/insurance		23,808		729		24,537		27,097			884			27,981
Healthcare		26,070		798		26,868		19,275			629			19,904
Information technology		29,052		889		29,941		33,445			1,091			34,536
Services		17,417		533		17,950		20,570			671			21,241
Telecommunications/utilities		16,257		498		16,755		12,172			397			12,569
Other		22,473		688		23,161		15,917			519			16,436
Real estate investment trusts		5,779		177		5,956		4,504			147			4,651
Mutual funds		57,512		14,154		71,666		49,994			14,234			64,228
Government fixed income		5,727		175		5,902		11,020			360			11,380
Futures contracts		4		—		4		(51	)		(2	)		(53	)

Total Level 1 Assets (1)	$	295,762	$	21,447	$	317,209	$	279,368		$	21,719		$	301,087


Level 2 - Significant other observable inputs
Government fixed income and mortgage backed	$	42,361	$	1,297	$	43,658	$	39,201		$	1,279		$	40,480
Corporate fixed income
Asset-backed and mortgage-backed		16,969		519		17,488		14,014			457			14,471
Banking		16,192		496		16,688		17,178			561			17,739
Utilities		5,064		155		5,219		2,430			79			2,509
Other		25,769		789		26,558		20,575			671			21,246
Pooled funds and mutual funds		17,447		2,244		19,691		8,230			1,974			10,204
State and local obligations		936		29		965		626			20			646

Total Level 2 assets (2)	$	124,738	$	5,529	$	130,267	$	102,254		$	5,041		$	107,295

Level 3 - Significant unobservable inputs
Commingled equity funds	$	97,295	$	2,978	$	100,273	$	94,389		$	3,080		$	97,469

Total Level 3 assets (3)	$	97,295	$	2,978	$	100,273	$	94,389		$	3,080		$	97,469


Total Plan assets at fair value	$	517,795	$	29,954	$	547,749	$	476,011		$	29,840		$	505,851
Guaranteed investment contracts/guaranteed annuity contracts (4)		4,952		—		4,952		5,342			—			5,342

Total Plan assets (5)	$	522,747	$	29,954	$	552,701	$	481,353		$	29,840		$	511,193


Southwest Gas Corporation		62

(1)	Equity securities, Real Estate Investment Trusts, 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. 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

(4)

The guaranteed investment contracts/guaranteed annuity 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 $928,000 (qualified retirement plan - $918,000, PBOP - $10,000) and $5.6 million (qualified retirement plan - $5.4 million, PBOP - $200,000) for 2011 and 2010, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.


Southwest Gas Corporation		63

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)


	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2009	$	77,879
Actual return on plan assets:
Relating to assets still held at the reporting date		13,090
Relating to assets sold during the period		—
Purchases		6,500
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—

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

Note 11 – Stock-Based Compensation

At December 31, 2011, 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):


	2011		2010		2009
Stock-based compensation expense, net of related tax benefits	$	7,262	$	5,874	$	5,194
Stock-based compensation related tax benefits		4,451		3,600		3,184

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):


	2011					2010					2009
	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		369		$	28.04		651		$	27.49		731		$	27.12
Exercised during the year		(192	)		28.75		(273	)		26.67		(66	)		23.18
Forfeited or expired during the year		—			—		(9	)		29.51		(14	)		28.88

Outstanding and exercisable at year end		177		$	27.28		369		$	28.04		651		$	27.49


Southwest Gas Corporation		64

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):


	2011		2010		2009
Outstanding and exercisable	$	2,697	$	3,186	$	1,695
Exercised		1,949		1,689		294


	December 31, 2011		December 31, 2010		December 31, 2009
Market value of Southwest Gas stock	$	42.49	$	36.67	$	28.53

The weighted-average remaining contractual life for outstanding options was 3.4 years for 2011. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2011 (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	52	2.1 Years	$22.45
$24.50 to $26.10	58	3.3 Years	$25.81
$29.08 to $33.07	67	4.5 Years	$32.29

The total grant date fair value of options vested was $405,000 during 2009. The Company received $5.4 million in cash from the exercise of options during 2011 and a corresponding tax benefit of $702,000 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 will vest immediately upon grant. The issuance of common stock for directors occurs when their service on the Board ends.


Southwest Gas Corporation		65

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2011 (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		366		$	27.54		170		$	27.42
Granted		125			37.87		92			37.87
Dividends		11					5
Forfeited or expired		(4	)		30.11		(2	)		30.50
Vested and issued*		(137	)		29.52		(89	)		28.45

Nonvested/unissued at December 31, 2011		361		$	30.66		176		$	32.65

*Includes shares converted for taxes and retiree payouts.

The average grant date fair value of performance shares and restricted stock/units granted in 2010 and 2009 was $29.04 and $24.46, respectively.

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 2007, and is subject to examination by the various state taxing authorities for years after 2006.

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):


	2011		2010		2009
Tax-related interest income	$	100	$	500	$	200

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


	2011		2010
Tax-related interest receivable (payable)	$	6	$	(100	)

As shown in the table below, the Company had no uncertain tax liabilities at December 31, 2011. Due to the lapse of the statute of limitations, the balance of unrecognized tax benefits at the beginning of the year was eliminated and favorably impacted the effective tax rate during 2011. The Company expects no change in unrecognized tax benefits in the next twelve months.


Southwest Gas Corporation		66

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


	2011			2010
Unrecognized tax benefits at beginning of year	$	1,445		$	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	$	—		$	1,445

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


Year Ended December 31,	2011			2010		2009
Current:
Federal	$	(265	)	$	4,204	$	(1,020	)
State		2,122			4,442		3,101

		1,857			8,646		2,081

Deferred:
Federal		58,584			44,778		41,410
State		2,862			1,501		1,426

		61,446			46,279		42,836

Total income tax expense	$	63,303		$	54,925	$	44,917

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


Year Ended December 31,	2011			2010			2009
Deferred federal and state:
Property-related items	$	51,710		$	43,420		$	46,201
Purchased gas cost adjustments		(92	)		(315	)		(4,167	)
Employee benefits		11,766			8,753			(452	)
All other deferred		(1,070	)		(4,711	)		2,122

Total deferred federal and state		62,314			47,147			43,704
Deferred ITC, net		(868	)		(868	)		(868	)

Total deferred income tax expense	$	61,446		$	46,279		$	42,836


Southwest Gas Corporation		67

The consolidated effective income tax rate for the period ended December 31, 2011 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,	2011			2010			2009
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.7			2.8			2.5
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		(0.9	)		(0.3	)		(0.2	)
Tax credits		(0.6	)		(0.5	)		(0.7	)
Company owned life insurance		(0.1	)		(2.3	)		(2.5	)
All other differences		(0.1	)		(0.2	)		(0.3	)

Consolidated effective income tax rate		36.2	%		34.7	%		34.0	%

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


December 31,	2011			2010
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	3,743		$	4,280
Employee benefits		24,605			31,384
Alternative minimum tax credit		17,411			15,495
Net operating losses and credits		59,096			—
Interest rate swap		13,352			6,973
Other		15,099			8,026
Valuation allowance		(142	)		—

		133,164			66,158

Deferred tax liabilities:
Property-related items, including accelerated depreciation		611,022			500,216
Regulatory balancing accounts		743			836
Property-related items previously flowed through		2,797			3,910
Unamortized ITC		5,992			6,860
Debt-related costs		4,379			4,824
Other		11,914			8,094

		636,847			524,740

Net deferred tax liabilities	$	503,683		$	458,582

Current	$	(53,435	)	$	(8,046	)
Noncurrent		557,118			466,628

Net deferred tax liabilities	$	503,683		$	458,582

At December 31, 2011, the Company has a federal net operating loss carryforward of $169 million and a federal general business credit carryforward of $231,000, both of which expire in 2031. The Company also has a net capital loss carryforward of $323,000 and a charitable contribution carryforward of $742,000, both of which expire in 2016.


Southwest Gas Corporation		68

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 2012 through March 2014. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):


	December 31, 2011		December 31, 2010
Contract notional amounts		10,827		14,207

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, 2011, 2010, and 2009 and their location in the income statements (thousands of dollars):

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


Instrument	Location of Gain or (Loss) Recognized in Income on Derivative	2011			2010			2009
Swaps	Net cost of gas sold	$	(18,201	)	$	(27,690	)	$	(4,391	)
Swaps	Net cost of gas sold		18,201	*		27,690	*		4,391	*

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 maturing in May 2012. The counterparties to each agreement are 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 terms of the remaining FSIRS are as follows:


Notional amount	$	100 million
Fixed rate to be paid by Southwest		4.78	%
Mandatory termination date (on or before)		March 20, 2012

Southwest has designated the second FSIRS agreement as a cash flow hedge of forecasted future interest payments. At the inception of the hedge, the terms of the derivative were the same as a perfect hypothetical derivative; thus, there was an expectation that there will be no ineffectiveness, and that the effective portion of unrealized gains and losses on the FSIRS


Southwest Gas Corporation		69

leading up to the forecasted debt issuance will be reported as a component of other comprehensive income. At termination, the final value will be reclassified from accumulated other comprehensive income into earnings over the same period the hedged forecasted transaction affects earnings. However, should conditions occur that indicate the existence of ineffectiveness (e.g., deterioration of counterparty creditworthiness, delay in the forecasted debt issuances, etc.), Southwest will measure ineffectiveness by comparing changes in the fair value of the FSIRS with the change in the fair value of a hypothetical swap (the hypothetical derivative method). Gains and losses due to ineffectiveness will be recognized immediately in earnings. At December 31, 2011, the remaining FSIRS continued to qualify as an effective hedge. There was no gain or loss reclassified from accumulated other comprehensive income (“AOCI”) into income (effective portion) and no gain or loss recognized in income (ineffective portion) for the Company’s remaining derivative designated as a hedging instrument.

The following table sets forth the gains and (losses) on a before-tax basis recognized on the Company’s FSIRS (thousands of dollars):

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


	Year Ended December 31, 2011			Year Ended December 31, 2010
Amount of loss on unrealized FSIRS recognized in other comprehensive income on derivative (effective portion)	$	(17,958	)	$	(6,755	)
Amount of loss on realized FSIRS recognized in other comprehensive income on derivative		—			(11,691	)

Total	$	(17,958	)	$	(18,446	)

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, 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	)


December 31, 2010 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	656	$	—		$	656
Swaps	Other current liabilities		65		(11,547	)		(11,482	)

Total		$	721	$	(11,547	)	$	(10,826	)


Southwest Gas Corporation		70

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	)


December 31, 2010 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other deferred credits	$	—	$	(6,755	)	$	(6,755	)

The estimated fair values of the Swaps 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, 2011		Year ended December 31, 2010		Year ended December 31, 2009
(Thousands of dollars)
Paid to counterparties	$	17,283	$	16,574	$	19,661

Received from counterparties	$	—	$	831	$	—

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


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

December 31, 2010
Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(656	)
Swaps	Prepaids and other current assets		11,482

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at December 31, 2011 and 2010 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 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.


Southwest Gas Corporation		71

The estimated fair value of Southwest’s FSIRS was determined using a discounted cash flow model that utilizes forward interest rate curves. The inputs to the model are the terms of the FSIRS. These Level 2 inputs are observable in the marketplace throughout the full term of the FSIRS, but have been credit-risk adjusted with no significant impact to the overall fair value measure. See Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income 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, 2011			December 31, 2010
(Thousands of dollars)
Assets at fair value:
Deferred charges and other assets - swaps	$	—		$	656
Liabilities at fair value:
Other current liabilities - swaps		(11,122	)		(11,482	)
Other deferred credits - swaps		(621	)		—
Other current liabilities - FSIRS		(24,713	)		—
Other deferred credits - FSIRS		—			(6,755	)

Net Assets (Liabilities)	$	(36,456	)	$	(17,581	)

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

Note 14 - Segment Information

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

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. Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).


	December 31, 2011		December 31, 2010
Accounts receivable for NPL services	$	6,205	$	8,111


Southwest Gas Corporation		72

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, 2011 is as follows (thousands of dollars):


2011	Gas Operations		Construction Services		Adjustments	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		Adjustments	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


Southwest Gas Corporation		73


2009	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,614,843	$	226,407				$	1,841,250
Intersegment sales		—		52,574					52,574

Total	$	1,614,843	$	278,981				$	1,893,824

Interest revenue	$	189	$	82				$	271

Interest expense	$	81,822	$	1,179				$	83,001

Depreciation and amortization	$	166,850	$	23,232				$	190,082

Income tax expense	$	40,451	$	4,466				$	44,917

Segment net income	$	79,420	$	8,062				$	87,482

Segment assets	$	3,782,913	$	124,755	$	(1,376	)	$	3,906,292

Capital expenditures	$	212,919	$	4,066				$	216,985

(a) Reflects construction services segment income taxes payable in 2009, which were netted against gas operations segment income taxes receivable during consolidation.


Southwest Gas Corporation		74

Note 15 - Quarterly Financial Data (Unaudited)


	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
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

2009
Operating revenues	$	689,862	$	387,648		$	317,509		$	498,805
Operating income		102,729		14,685			522			90,455
Net income (loss)		49,981		(594	)		(8,297	)		46,392
Basic earnings (loss) per common share*		1.13		(0.01	)		(0.18	)		1.03
Diluted earnings (loss) per common share*		1.12		(0.01	)		(0.18	)		1.02

*	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 the 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.


Southwest Gas Corporation		75

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, 2011. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 28, 2012


Southwest Gas Corporation		76

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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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.

LOGO

Las Vegas, Nevada

February 28, 2012

List of Subsidiaries of Southwest Gas Corp.

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2011


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

Consent of PricewaterhouseCoopers LLP

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. 333-157930) and Form S-8 (Nos. 333-168731, 333-147952, 333-155581, and 333-106762) of Southwest Gas Corporation of our report dated February 28, 2012 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 28, 2012

Section 302 Certifications

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;

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 28, 2012

/S/ JEFFREY W. SHAW

Jeffrey W. Shaw

Chief Executive Officer

Southwest Gas Corporation

Certification

I, Roy R. Centrella, certify that:

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

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

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

(a)

(b)

(c)

(d)

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)

(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 28, 2012

/S/ ROY R. CENTRELLA

Roy R. Centrella

Senior Vice President/Chief Financial Officer

Southwest Gas Corporation

Section 906 Certifications

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, 2011 as filed with the Securities and Exchange Commission (the “Report”), I, Jeffrey W. Shaw, the Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)

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

(2)

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

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

Dated: February 28, 2012

/s/ Jeffrey W. Shaw

Jeffrey W. Shaw

Chief Executive Officer

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2011 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 28, 2012

/s/ Roy R. Centrella

Roy R. Centrella

Senior Vice President/Chief Financial Officer

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