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, 2006

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.
7.70% Preferred Trust Securities		New York Stock Exchange, Inc.

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

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

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

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

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

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨

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

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

$1,275,488,075 as of June 30, 2006

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 41,997,015 shares as of February 15, 2007

DOCUMENTS INCORPORATED BY REFERENCE


Description		Part Into Which Incorporated
Annual Report to Shareholders for the Year Ended December 31, 2006		Parts I, II, and IV
2007 Proxy Statement		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	3

	Competition	4

	Environmental Matters	5

	Employees	5

	Construction Services	5

Item 1A.	RISK FACTORS	6

Item 1B.	UNRESOLVED STAFF COMMENTS	8

Item 2.	PROPERTIES	8

Item 3.	LEGAL PROCEEDINGS	9

Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	9

Item 4A.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	9

PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	10

Item 6.	SELECTED FINANCIAL DATA	10

Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	10

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	10

Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	11

Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	11

Item 9A.	CONTROLS AND PROCEDURES	12

Item 9B.	OTHER INFORMATION	12

PART III

Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	13

Item 11.	EXECUTIVE COMPENSATION	14

Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	14

Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	15

Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	15

PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	16

	List of Exhibits	17

SIGNATURES		21

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, transporting, and distributing natural gas 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.

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

Financial information concerning the Company’s business segments is included in Note 12 of the Notes to Consolidated Financial Statements, which is included in the 2006 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 website and are available in print by request.

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, 2006, Southwest purchased and distributed or transported natural gas to 1,784,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. There were 71,000 customers added to the system during 2006.

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, 2006	85	%	6	%	9	%
December 31, 2005	86	%	5	%	9	%
December 31, 2004	86	%	5	%	9	%

Southwest is not dependent on any one or a few customers such that the loss of any one or several would have a significant adverse impact on earnings or cash flows.

Transportation of customer-secured gas to end-users accounted for 48 percent of total system throughput in 2006. Customers who utilized this service transported 118 million dekatherms in 2006, 127 million dekatherms in 2005, and 126 million dekatherms in 2004. Although these volumes were significant, these customers provide a much smaller proportionate share of operating margin.

The demand for natural gas is seasonal. Variability in weather from normal temperatures can materially impact results of operations. It is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in operations. Also, earnings for interim periods can be significantly affected by the timing of general rate relief.

Rates and Regulation

Rates that Southwest is authorized to charge its distribution system customers are determined by the ACC, PUCN, and CPUC in general rate cases and are derived using rate base, cost of service, and cost of capital experienced in an historical test year, as adjusted in Arizona and Nevada, and projected for a future test year in California. The FERC regulates the northern Nevada transmission and liquefied natural gas (“LNG”) storage facilities of Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary, and the rates it charges for transportation of gas directly to certain end-users and to various local distribution companies (“LDCs”). The LDCs transporting on the Paiute system are: Sierra Pacific Power Company (serving Reno and Sparks, Nevada) and Southwest Gas Corporation (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 and subordinated debentures, and a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, plus certain other assets such as working capital and inventories, less accumulated depreciation on utility plant in service, net deferred income tax liabilities, and certain other deductions. Rate schedules in Southwest’s service territories, with the exception of Nevada, contain purchased gas adjustment clauses, which allow Southwest to file for rate adjustments as the cost of purchased gas changes. In Nevada, effective November 2005, Southwest began operating under the deferred energy regulations as established by the Nevada Administrative Code, which governs the recovery of energy costs in the state. These provisions result in little difference from purchased gas adjustment clauses in the method used to account for or report purchased gas costs, including the ability of the Company to defer over or under-collections of gas costs to balancing accounts. Effective October 2005, the Company began filing for quarterly gas cost adjustments in Nevada, calculated on a twelve-month rolling average. These adjustments are made effective immediately upon filing each quarter, but are subject to an annual prudence review and audit of the natural gas costs incurred. The Company filed its first quarterly adjustment in April 2006. 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 2006 Annual Report to Shareholders.

The table below lists the docketed general rate filings last initiated 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	December 2004	March 2006
California:
Northern and Southern	General rate case	February 2002	May 2003
Northern and Southern	Annual attrition	October 2006	January 2007
Nevada:
Northern and Southern	General rate case	March 2004	September 2004
FERC:
Paiute	General rate case	January 2005	August 2005

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 may be as much as 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. No weather-related curtailments occurred during the latest peak heating season. Southwest maintains no significant backlog on its orders for gas service.

Natural Gas Supply

Southwest is responsible for acquiring (purchasing) and arranging delivery of (transporting via interstate pipelines) natural gas to its system for all sales customers.

The primary objective of Southwest in acquiring gas supply is to ensure that adequate supplies of natural gas are available from reliable sources 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 2006, Southwest acquired gas supplies from 56 suppliers. Southwest regularly monitors the number of suppliers, their quality and their relative contribution to the overall customer supply portfolio. New suppliers are contracted whenever possible, and solicitations for supplies are extended to the largest possible list of suppliers. Competitive pricing, flexibility in meeting Southwest requirements, and aggressive participation by suppliers who have demonstrated reliability of service are key to their inclusion in the annual portfolio mix. The goal of this practice is to mitigate the risk of nonperformance by any one supplier and ensure competitive prices for customer supplies.

Balancing reliable supply assurances with the associated costs 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. Firm and spot market natural gas purchases are made in a competitive bid environment. Southwest has experienced price volatility over the past five years, as the weighted average delivered cost of natural gas has ranged from a low of 38 cents per therm in 2002 to a high of 79 cents per therm in 2006. Price volatility is expected to continue throughout 2007.

To mitigate customer exposure to market price volatility, Southwest continues to purchase a significant percentage of its forecasted annual normal weather requirements under firm, fixed-price arrangements that are secured periodically throughout the year. About half of Southwest’s annual normal weather supply needs are secured using short duration contracts (one year or less). For the 2006/2007 heating season, fixed-price contracts ranged in price from $6 to $11 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.

The firm, fixed-price arrangements are structured such that a stated volume of gas is required to be scheduled by Southwest and delivered by the supplier. If the gas is not needed by Southwest or cannot be procured by the supplier, the contract provides for fixed or market-based penalties to be paid by the non-performing party.

In managing its gas supply portfolios, Southwest uses the fixed-price and variable-price arrangements noted above, but does not currently utilize other stand-alone derivative financial instruments for speculative purposes or for hedging. During 2007, Southwest intends to supplement its current volatility mitigation program with stand-alone financial derivative instruments. The combination of fixed-price contracts and derivative instruments should increase flexibility for Southwest and increase supplier diversification. The costs of such derivative financial instruments are expected to be recovered from customers. None of the Company’s current long-term financial instruments or other contracts are derivatives that are marked to market or contain embedded derivatives with significant mark-to-market value.

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.

Gas supplies for the southern system of Southwest (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.

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”), Northwest Pipeline Corporation, Tuscarora Gas Pipeline Company (“Tuscarora”), Southern California Gas Company, and Paiute. Supply and pipeline capacity availability on both short- and long-term bases is regularly monitored by Southwest 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 additional capacity to be acquired should an unforeseen need arise.

Southwest is dependent upon the El Paso pipeline system for the transportation of gas to virtually all of its Arizona service territories and, for part of 2006, to a portion of its southern Nevada service territory. During 2005, Southwest entered into negotiations with alternative transportation service providers to evaluate capacity options for its southern Nevada service territory. After evaluating several proposals, Transwestern was chosen to replace the capacity previously provided by El Paso for southern Nevada, effective September 2006. The new five-year contract with Transwestern extends capacity during winter months and provides greater flexibility in meeting monthly requirements. Rates under the new contract do not differ significantly from those previously paid. El Paso service is available in Southern Nevada on an interruptible basis.

The Company believes that the current level of contracted firm interstate capacity is sufficient to serve each of its service territories. 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. As a result of its success in these markets, Southwest has experienced consistent growth 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 alternative energy sources such as electricity, fuel oils, and coal. However, high natural gas prices may 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.

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 had little direct impact upon Southwest. Environmental efforts, with respect to matters such as protection of endangered species and archeological finds, have increased the complexity and time required to obtain pipeline rights-of-way and construction permits. However, increased environmental legislation and regulation are also beneficial to the natural gas industry. Because natural gas is one of the most environmentally safe fossil fuels currently available, its use can help energy users to comply with stricter environmental standards.

Employees

At December 31, 2006, the natural gas operations segment had 2,525 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 underground piping contractor that 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. Construction activity is also cyclical and can be significantly impacted by changes in general and local economic conditions, including interest rates, employment levels, job growth, equipment resale market, and local and federal tax rates.

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 2006, approximately 91 percent of revenue was earned under unit-price contracts. As of December 31, 2006, no significant backlog existed with respect to outstanding construction contracts.

Materials used by NPL in its pipeline 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 approximately 16 major markets nationwide. Its customers are the primary LDCs in those markets. During 2006, NPL served 59 major customers, with Southwest accounting for approximately 27 percent of NPL revenues. With the exception of three other customers that in total accounted for approximately 31 percent of revenue, no other customer had a relatively significant contribution to NPL revenues.

Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2006, NPL had 2,377 regular full-time equivalent employees. Employment peaked in September 2006 when there were 2,526 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 17 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 construction 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.

Item 1A.

RISK FACTORS

Although the Company is not able to predict all factors that may affect future results, described below (and in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this report) are some of the risk factors identified by the Company 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.

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 PGA 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 2007, if the need again arises.

We may file requests for rate increases to cover the rise in the costs 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.

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 ACC, the CPUC, the FERC, and the PUCN 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 operation.

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.

Significant customer growth in Arizona and Nevada could strain our capital resources.

We continue to experience significant population and customer growth throughout our service territories. During 2006, we added 71,000 customers, a four percent growth rate. This growth has required large amounts of capital to finance the investment in new transmission and distribution plant. In 2006, our natural gas construction expenditures totaled $306 million. Approximately 76 percent of these current-period expenditures represented new construction, and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant.

Cash flows from operating activities (net of dividends) have been insufficient, and are expected to continue to be insufficient, to fund all necessary capital expenditures. We have funded this shortfall through the issuance of additional debt and equity securities, and expect to continue to do so. However, our ability to issue additional securities is dependent upon, among other things, conditions in the capital markets, regulatory authorizations, our credit rating, and our level of earnings.

Significant customer growth in Arizona and Nevada could also impact earnings.

Our ability to earn the rates of return authorized by the ACC and the PUCN is also more difficult because of significant customer growth. The rates we charge our distribution customers in Arizona and Nevada are derived using rate base, cost of service, and cost of capital experienced in a historical test year, as adjusted. This results in “regulatory lag” which delays our recovery of some of the costs of capital improvements and operating costs from customers in Arizona and Nevada.

Our earnings are greatly affected by variations in temperature during the winter heating season.

The demand for natural gas is seasonal and is greatly affected by temperature. Variability in weather from normal temperatures can materially impact results of operations, particularly in our Arizona service territories where rates are highly leveraged. On cold days, use of gas by residential and commercial customers may be as much as six times greater than on warm days because of the increased use of gas for space heating. Weather has been and will continue to be one of the dominant factors in our financial performance.

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.

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, 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 and vandalism. Any of these 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 have 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 Company’s current insurance contracts limit the self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million. 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.

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, particularly in our Arizona service territories where we are wholly dependent upon the El Paso pipeline system. A prolonged interruption or reduction of service, particularly during the winter heating season, would reduce cash flow and earnings.

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 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. For example, in May 2006, Moody’s Investors Service, Inc. (“Moody’s”) lowered its rating on the Company’s unsecured long-term debt to Baa3 from Baa2 and changed the outlook for the rating to stable from negative. The change in credit rating will result in an estimated annualized increase of $375,000 in interest expense on existing long-term debt. No debt covenants were affected by the downgrade.

Any future downgrade could further 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.

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, 2006 was $3.8 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 the 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 5 of this Form 10-K under Construction Services.

Item 3.

LEGAL PROCEEDINGS

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In May 2005, a leaking natural gas line was involved in a fire that severely injured an individual. By December 2005, the Company had recorded a total liability related to this incident equal to the Company’s maximum self-insured retention level for the policy year August 2004 to July 2005 of $11 million. In the fourth quarter of 2006, the case was settled. The amount of the settlement that exceeded $11 million was covered by insurance. The Company’s current insurance contracts limit the self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million.

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.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Item 4A.

DIRECTORS AND 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, 2007, there were 23,306 holders of record of common stock, and the market price of the common stock was $38.80. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2006 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.

The Company’s common stock dividend policy states that common stock dividends will be paid at a prudent level within the normal dividend payout range for its respective businesses, and that dividends will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend was 20.5 cents per share throughout 2005 and 2006. The dividend of 20.5 cents per share has been paid quarterly since September 1994. In February 2007, the Board of Directors increased the quarterly dividend payout to 21.5 cents per share, effective with the June 2007 payment.

Item 6.

SELECTED FINANCIAL DATA

Information required by this item is included in the 2006 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 2006 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

About half of Southwest’s annual normal weather gas supply needs are secured using short duration contracts (one year or less). For the 2006/2007 heating season, fixed-price contracts ranged in price from $6 to $11 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. The PGA mechanism allows Southwest to file to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs.

The Company does not currently utilize stand-alone derivative financial instruments, other than fixed-price term and variable-rate contracts, for speculative purposes or for hedging. During 2007, Southwest intends to supplement its current volatility mitigation program with stand-alone derivative instruments. The combination of fixed-price contracts and derivative instruments should increase flexibility for Southwest and increase supplier diversification. The Company intends to pursue the recovery of such costs as part of the PGA mechanisms upon approval by Southwest’s regulatory commissions in each jurisdiction.

Weather Risk

A significant portion of the Company’s operating margin is volume driven with current rates based on an assumption of normal weather. Demand for natural gas is greatly affected by temperature. On cold days, use of gas by residential and commercial customers may be as much as six times greater than on warm days because of increased use of gas for

space heating. Space heating-related volumes are the primary component of billings for these customer classes and are concentrated in the months of November to April. Variances in temperatures from normal levels, especially during these months, have a significant impact on the margin and associated net income of the Company. This impact is most pronounced in Arizona, where 54 percent of Southwest’s customers are located and where rates are highly leveraged.

The Company continues to pursue mechanisms in each of its service territories intended to stabilize the recovery of the Company’s fixed costs and reduce fluctuations in customers’ bills due to colder or warmer-than-normal weather. In California, the CPUC authorized a margin tracker balancing account in April 2004 that mitigates margin volatility due to weather and other usage variations. In Nevada, the PUCN approved certain rate design improvements in September 2004 to mitigate weather variations, including an increase in the monthly basic service charge and the use of declining block rates. In Arizona, most of Southwest’s requests for weather mitigation measures in its recent general rate case were rejected in the ACC’s final order approved in February 2006. The ACC did however encourage Southwest to work with the ACC Staff and other interested parties prospectively to seek rate design alternatives that will provide benefits to all affected stakeholders.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for the Company include 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 variable-rate Industrial Development Revenue Bonds (“IDRBs”) are tracked and recovered from ratepayers through an interest balancing account. As of December 31, 2006 and 2005, the Company had $197 million and $224 million, respectively, in variable-rate debt outstanding, excluding Nevada variable-rate IDRBs. Assuming a constant outstanding balance in variable-rate debt for the next twelve months, a hypothetical one percent change in interest rates would increase or decrease interest expense for the next twelve months by approximately $2 million.

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

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 2006 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 is recorded, processed, summarized, communicated to management, and reported within the time periods specified in the SEC’s rules and forms. 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, 2006, 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 2006 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 61.

The Attestation Report of the Registered Public Accounting Firm required to be reported herein is incorporated by reference to the information reported in the 2006 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 62.

There has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B.

OTHER INFORMATION

None.

PART III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

(a) Identification of Directors. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive 2007 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, 2006 are as follows:


Name	Age	Position	Period Position Held
Jeffrey W. Shaw	48	Chief Executive Officer	2004-Present
		President	2003-2004
		Senior Vice President/Gas Resources and Pricing	2002-2003
		Senior Vice President/Finance and Treasurer	2002
James P. Kane	60	President	2004-Present
		Executive Vice President/Operations	2002-2004
George C. Biehl	59	Executive Vice President/Chief Financial Officer and Corporate Secretary	2002-Present
John P. Hester	44	Senior Vice President/Regulatory Affairs & Energy Resources	2006-Present
		Vice President/Regulatory Affairs and Systems Planning	2003-2006
		Director/State Regulatory Affairs and Systems Planning	2002-2003
Edward A. Janov	52	Senior Vice President/Finance	2004-Present
		Vice President/Finance	2003-2004
		Vice President/Finance and Treasurer	2002-2003
		Vice President/Chief Accounting Officer	2002
Christina A. Palacios	61	Senior Vice President/Central Arizona Division	2005-Present
		Senior Vice President/Southern Arizona Division	2004-2005
		Vice President/Southern Arizona Division	2002-2004
Thomas R. Sheets	56	Senior Vice President/Legal Affairs and General Counsel	2002-Present
Dudley J. Sondeno	54	Senior Vice President/Chief Knowledge and
		Technology Officer	2002-Present
Roy R. Centrella	49	Vice President/Controller and Chief Accounting Officer	2002-Present
		Controller	2002
Kenneth J. Kenny	44	Vice President/Treasurer	2005-Present
		Treasurer	2003-2005
		Assistant Treasurer/Director Financial Services	2002-2003

(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 2007 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 2007 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 2007 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, as amended, which includes assisting in the preparation of forms for filing. For 2006, all reports were timely filed.

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 2007 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 2007 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 2007 Proxy Statement, which by this reference is incorporated herein.

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

At December 31, 2006, the Company had two stock-based compensation plans. With respect to the first plan, the Company may grant options to purchase shares of common stock to key employees and outside directors.

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
(Thousands of shares)
Equity compensation plans approved by security holders	957	$	26.26	—
Equity compensation plans not approved by security holders	—		—	—

Total	957	$	26.26	—

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
(Thousands of shares)
Equity compensation plans approved by security holders	319	$	24.61	—	(a)
Equity compensation plans not approved by security holders	—		—	—

Total	319	$	24.61	—

(a)	No common shares are registered for this plan, but performance shares are authorized for future grant under the terms of the plan.

Additional information regarding the two equity compensation plans is included in Note 10 of the Notes to Consolidated Financial Statements in the 2006 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 2007 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 Accountants” in the definitive 2007 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 Reports of Independent Accountants) required to be reported herein are incorporated by reference to the information reported in the 2006 Annual Report to Shareholders under the following captions:


Consolidated Balance Sheets		38
Consolidated Statements of Income		39
Consolidated Statements of Cash Flows		40
Consolidated Statements of Stockholders’ Equity and Comprehensive Income		41
Notes to Consolidated Financial Statements		42
Management’s Report on Internal Control Over Financial Reporting		61
Report of Independent Registered Public Accounting Firm		62

(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
1.01		Sales Agency Financing Agreement, dated as of March 16, 2006, between Southwest Gas Corporation and BNY Capital Markets, Inc. Incorporated herein by reference to the report on Form 8-K dated March 16, 2006.

3(i)		Restated Articles of Incorporation, as amended. Incorporated herein by reference to the report on Form 10-Q for the quarter ended March 31, 1997.

3(ii)		Amended Bylaws of Southwest Gas Corporation. Incorporated herein by reference to the report on Form 8-K dated March 16, 2006.

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 the report on Form 10-K for the year ended December 31, 1993.

4.02		Form of Deposit Agreement. Incorporated herein by reference to the Registration Statement on Form S-3, 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 the Registration Statement on Form S-3, 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 the report on Form 8-K dated July 26, 1996.

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 the report on Form 8-K dated July 31, 1996.

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 the report on Form 8-K dated December 30, 1996.

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 the report on Form 10-K for the year ended December 31, 1999.

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 the report on Form 8-K dated February 8, 2001.

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 the report on Form 8-K dated May 1, 2002.

4.10		Certificate of Trust of Southwest Gas Capital II. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.11		Certificate of Trust of Southwest Gas Capital III. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.12		Certificate of Trust of Southwest Gas Capital IV. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.13		Trust Agreement of Southwest Gas Capital III. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.14		Trust Agreement of Southwest Gas Capital IV. Incorporated herein by reference to the Registration Statement on Form S-3, No. 333-106419.

4.15		Form of Common Stock Certificate. Incorporated herein by reference to the report on Form 8-K dated July 22, 2003.

4.16		Form of Preferred Trust Security. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.17		Form of Indenture with respect to the 7.70% Junior Subordinated Debentures. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.18		Form of 7.70% Junior Subordinated Debenture. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.19		Form of Amended and Restated Trust Agreement of Southwest Gas Capital II. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.20		Form of Guarantee Agreement with respect to the Preferred Trust Securities. Incorporated herein by reference to the report on Form 8-K dated August 20, 2003.

4.21		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 the report on Form 10-Q for the quarter ended September 30, 2004.

4.22		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 the report on Form 10-K for the year ended December 31, 2004.


4.23		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 the report on Form 10-Q for the quarter ended September 30, 2005.

4.24		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 the report on Form 10-Q for the quarter ended September 30, 2006.

4.25		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 percent 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 the report on Form 10-K for the year ended December 31, 1993.

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 the report on Form 10-Q for the quarter ended September 30, 1996.

10.03*		Southwest Gas Corporation Supplemental Retirement Plan, amended and restated as of March 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999.

10.04*		Southwest Gas Corporation Board of Directors Retirement Plan, amended and restated as of March 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999.

10.05		Financing Agreement between the Company and Clark County, Nevada, dated as of October 1, 1999. Incorporated herein by reference to the report on Form 10-K for the year ended December 31, 1999.

10.06*		Amended Form of Employment Agreement with Company Officers. Incorporated herein by reference to the reports on Form 10-Q for the quarters ended September 30, 1998, September 30, 2000, and September 30, 2001, and the reports on Form 8-K dated September 21, 2004 and August 1, 2006.

10.07*		Amended Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to the reports on Form 10-Q for the quarters ended September 30, 1998, September 30, 2000, and September 30, 2001, and the reports on Form 8-K dated September 21, 2004 and August 1, 2006.

10.08*		Southwest Gas Corporation Management Incentive Plan, amended and restated January 1, 2002. Incorporated herein by reference to the Proxy Statement dated April 2, 2002.

10.09*		Southwest Gas Corporation 2002 Stock Incentive Plan. Incorporated herein by reference to the Proxy Statement dated April 2, 2002.

10.10*		Southwest Gas Corporation Executive Deferral Plan, amended and restated as of November 19, 2002. Incorporated herein by reference to the Report on Form 10-K for the year ended December 31, 2002.


10.11*		Southwest Gas Corporation Directors Deferral Plan, amended and restated as of November 19, 2002. Incorporated herein by reference to the Report on Form 10-K for the year ended December 31, 2002.

10.12		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 the report on Form 10-Q for the quarter ended September 30, 2003.

10.13*		Form of Executive Option Grant under 2002 Stock Incentive Plan. Incorporated herein by reference to the report on Form 10-Q for the quarter ended September 30, 2004.

10.14		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 the report on Form 10-K for the year ended December 31, 2004.

10.15		$300 million Five-Year Credit Facility. Incorporated herein by reference to the report on Form 10-Q for the quarter ended June 30, 2005. First Amendment to $300 million Five-Year Credit Facility. Incorporated herein by reference to the report on Form 10-Q for the quarter ended June 30, 2006.

10.16		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 the report on Form 10-Q for the quarter ended June 30, 2005.

10.17		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 the report on Form 10-Q for the quarter ended September 30, 2005.

10.18		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 the report on Form 10-Q for the quarter ended September 30, 2006.

10.19*		Amendment to Employment and Change in Control Agreements.

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

13.01		Portions of 2006 Annual Report 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.

*	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, 2007	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/ GEORGE C. BIEHL (George C. Biehl)	Director, Executive Vice President, Chief Financial Officer, and Corporate Secretary	February 28, 2007

/s/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	February 28, 2007

/s/ STEPHEN C. COMER (Stephen C. Comer)	Director	February 28, 2007

/s/ RICHARD M. GARDNER (Richard M. Gardner)	Director	February 28, 2007

/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Chairman of the Board of Directors	February 28, 2007

/s/ JAMES J. KROPID (James J. Kropid)	Director	February 28, 2007

/s/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director	February 28, 2007

/s/ ANNE L. MARIUCCI (Anne L. Mariucci)	Director	February 28, 2007

/s/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Director	February 28, 2007

/s/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director and Chief Executive Officer	February 28, 2007

/s/ CAROLYN M. SPARKS (Carolyn M. Sparks)	Director	February 28, 2007

/s/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	February 28, 2007

/s/ ROY R. CENTRELLA (Roy R. Centrella)	Vice President, Controller, and Chief Accounting Officer	February 28, 2007

EXHIBIT INDEX


Exhibit Number		Description of Document
10.19		Amendment to Employment and Change in Control Agreements.

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

13.01		Portions of 2006 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.

Amendment to Employement and Change in Control Agreements

EXHIBIT 10.19

SIGNIFICANT TERMS OF EMPLOYMENT AND CHANGE IN CONTROL AGREEMENTS

BY INDIVIDUAL OFFICER

(The form of agreements was filed as an exhibit to the Form 10-Q for the period ended September 30, 2000. The list filed as part of that exhibit has been updated to include the following Officer.)


	Minimum annual base salary	Incentive compensation percentage	Additional SERP points	Severance benefits maximum months	Change in control lump-sum salary benefit
John P. Hester	$175,000	75%	10 points	18 months	24 months

Computation of Ratios of Earnings to Fixed Charges

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)


	For the Year Ended December 31,
	2006		2005		2004		2003		2002
Continuing operations
1. Fixed charges:
A) Interest expense	$	92,878	$	87,687	$	84,138	$	78,724	$	79,586
B) Amortization		3,467		3,700		3,059		2,752		2,278
C) Interest portion of rentals		6,412		6,333		6,779		6,665		8,846
D) Preferred securities distributions		—		—		—		4,015		5,475

Total fixed charges	$	102,757	$	97,720	$	93,976	$	92,156	$	96,185

2. Earnings (as defined):
E) Pretax income from continuing operations	$	128,357	$	68,435	$	87,012	$	55,384	$	65,382
Fixed Charges (1. above)		102,757		97,720		93,976		92,156		96,185

Total earnings as defined	$	231,114	$	166,155	$	180,988	$	147,540	$	161,567

3. Ratio of earnings to fixed charges		2.25		1.70		1.93		1.60		1.68

Portions of 2006 Annual Report to Shareholders incorporated by Reference

Exhibit 13.01

Southwest Gas Corporation

Consolidated Selected Financial Statistics


Year Ended December 31,	2006			2005			2004			2003			2002
(Thousands of dollars, except per share amounts)
Operating revenues	$	2,024,758		$	1,714,283		$	1,477,060		$	1,231,004		$	1,320,909
Operating expenses		1,815,576			1,563,635			1,307,293			1,095,899			1,174,410

Operating income	$	209,182		$	150,648		$	169,767		$	135,105		$	146,499

Net income	$	83,860		$	43,823		$	56,775		$	38,502		$	43,965

Total assets at year end	$	3,484,965		$	3,228,426		$	2,938,116		$	2,608,106		$	2,432,928

Capitalization at year end
Common equity	$	901,425		$	751,135		$	705,676		$	630,467		$	596,167
Mandatorily redeemable preferred trust securities		—			—			—			—			60,000
Subordinated debentures		100,000			100,000			100,000			100,000			—
Long-term debt		1,286,354			1,224,898			1,162,936			1,121,164			1,092,148

	$	2,287,779		$	2,076,033		$	1,968,612		$	1,851,631		$	1,748,315

Common stock data
Common equity percentage of capitalization		39.4	%		36.2	%		35.8	%		34.0	%		34.1	%
Return on average common equity		10.3	%		5.9	%		8.5	%		6.3	%		7.5	%
Earnings per share	$	2.07		$	1.15		$	1.61		$	1.14		$	1.33
Diluted earnings per share	$	2.05		$	1.14		$	1.60		$	1.13		$	1.32
Dividends declared per share	$	0.82		$	0.82		$	0.82		$	0.82		$	0.82
Payout ratio		40	%		71	%		51	%		72	%		62	%
Book value per share at year end	$	21.58		$	19.10		$	19.18		$	18.42		$	17.91
Market value per share at year end	$	38.37		$	26.40		$	25.40		$	22.45		$	23.45
Market value per share to book value per share		178	%		138	%		132	%		122	%		131	%
Common shares outstanding at year end (000)		41,770			39,328			36,794			34,232			33,289
Number of common shareholders at year end		23,610			23,571			23,743			22,616			22,119
Ratio of earnings to fixed charges		2.25			1.70			1.93			1.60			1.68

Southwest Gas Corporation

Natural Gas Operations


Year Ended December 31,	2006			2005			2004			2003			2002
(Thousands of dollars)
Sales	$	1,671,093		$	1,401,329		$	1,211,019		$	984,966		$	1,069,917
Transportation		56,301			53,928			51,033			49,387			45,983

Operating revenue		1,727,394			1,455,257			1,262,052			1,034,353			1,115,900
Net cost of gas sold		1,033,988			828,131			645,766			482,503			563,379

Operating margin		693,406			627,126			616,286			551,850			552,521
Expenses
Operations and maintenance		320,803			314,437			290,800			266,862			264,188
Depreciation and amortization		146,654			137,981			130,515			120,791			115,175
Taxes other than income taxes		34,994			39,040			37,669			35,910			34,565

Operating income	$	190,955		$	135,668		$	157,302		$	128,287		$	138,593

Contribution to consolidated net income	$	71,473		$	33,670		$	48,354		$	34,211		$	39,228

Total assets at year end	$	3,352,074		$	3,103,804		$	2,843,199		$	2,528,332		$	2,345,407

Net gas plant at year end	$	2,668,104		$	2,489,147		$	2,335,992		$	2,175,736		$	2,034,459

Construction expenditures and property additions	$	305,914		$	258,547		$	274,748		$	228,288		$	263,576

Cash flow, net
From operating activities	$	248,884		$	214,036		$	124,135		$	187,122		$	281,329
From investing activities		(277,980	)		(254,120	)		(272,458	)		(249,300	)		(243,373	)
From financing activities		20,350			57,763			143,086			60,815			(49,187	)

Net change in cash	$	(8,746	)	$	17,679		$	(5,237	)	$	(1,363	)	$	(11,231	)

Total throughput (thousands of therms)
Residential		677,605			650,465			667,174			593,048			588,215
Small commercial		309,856			300,072			303,844			279,154			280,271
Large commercial		128,255			111,839			104,899			100,422			121,500
Industrial/Other		149,243			156,542			163,856			157,305			224,055
Transportation		1,175,238			1,273,964			1,258,265			1,336,901			1,325,149

Total throughput		2,440,197			2,492,882			2,498,038			2,466,830			2,539,190

Weighted average cost of gas purchased ($/therm)	$	0.79		$	0.71		$	0.57		$	0.46		$	0.38
Customers at year end		1,784,000			1,713,000			1,613,000			1,531,000			1,455,000
Employees at year end		2,525			2,590			2,548			2,550			2,546
Degree days—actual		1,826			1,735			1,953			1,772			1,912
Degree days—ten-year average		1,961			1,956			1,913			1,931			1,963

Southwest Gas Corporation

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

Overview

The following discussion of Southwest Gas Corporation and subsidiaries (the “Company”) includes information related to the Company’s two business segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, transporting, and distributing natural gas 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.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and are covered in greater detail in later sections of management’s discussion and analysis. As reflected in the table below, the natural gas operations segment accounted for an average of 83 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

Consolidated Results of Operations


Year ended December 31,	2006		2005		2004
(Thousands of dollars, except per share amounts)

Contribution to net income
Natural gas operations	$	71,473	$	33,670	$	48,354
Construction services		12,387		10,153		8,421

Consolidated	$	83,860	$	43,823	$	56,775

Basic earnings per share
Natural gas operations	$	1.76	$	0.88	$	1.37
Construction services		0.31		0.27		0.24

Consolidated	$	2.07	$	1.15	$	1.61

The main factors contributing to the increase in results of operations during 2006 include:

•

higher operating margin resulting from the Arizona general rate increase;

•

continued customer growth;

•

a nonrecurring property tax settlement;

•

increased contribution to net income from NPL; and

•

2005 included a $10 million pretax charge related to an injuries and damages case (see Insurance Coverage for additional information).

Partially offsetting the above positive factors was a 2.4 million increase in average shares outstanding between 2005 and 2006.

Principal Factors Affecting Operating Margin

Southwest’s operating revenues are recognized 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 three principal

factors affecting operating margin are general rate relief, weather, and customer growth.

General Rate Relief. 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.

The following events highlight the impact of general rate relief on operating margin during 2006:

•

In February 2006, the Arizona Corporation Commission (“ACC”) rendered a general rate decision that increased rates in Arizona by $49.3 million annually effective March 2006. During 2006, general rate relief in Arizona provided a $35 million increase in operating margin.

Southwest Gas Corporation

•

In June 2006, the California Public Utilities Commission (“CPUC”) approved the Company’s 2006 attrition year filing, granting annualized rate relief of $3 million, effective April 13, 2006, of which $2 million was recognized in 2006.

Weather. Weather is a significant driver of natural gas volumes used by residential and small commercial customers and is the main reason for volatility in margin. Space heating-related volumes are the primary component of billings for these customer classes and are concentrated in the months of November to April for the majority of the Company’s customers. Variances in temperatures from normal levels, especially in Arizona where rates remain leveraged, have a significant impact on the margin and associated net income of the Company. Differences in heating demand, caused primarily by weather variations between 2006 and 2005, accounted for a $3 million increase in operating margin. Temperatures during both years were warmer than normal.

Customer Growth. As of December 31, 2006, Southwest had 1,784,000 residential, commercial, industrial, and other natural gas customers, of which 965,000 customers were located in Arizona, 642,000 in Nevada, and 177,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2006, Southwest added 71,000 customers, a four percent increase, of which 35,000 customers were added in Arizona, 29,000 in Nevada, and 7,000 in California. These additions are largely attributed to population growth in the service areas. Based on current commitments from builders, customer growth is expected to be over four percent in 2007. During 2006, 54 percent of operating margin was earned in Arizona, 36 percent in Nevada, and 10 percent in California. During this same period, Southwest earned 85 percent of operating margin from residential and small commercial customers, 6 percent from other sales customers, and 9 percent from transportation customers. These general patterns are expected to continue.

Incremental margin ($26 million in 2006) has accompanied this customer growth, but the costs associated with creating and maintaining the infrastructure needed to accommodate these customers have also been significant. The timing of including these costs in rates is often delayed (regulatory lag) and can result in a reduction of current-period earnings.

Management has attempted to mitigate the regulatory lag associated with growth by collecting contributions and advances from home builders and by being judicious in its staffing levels through the effective use of technology. Exemplifying this in recent years has been Southwest’s expanded use of electronic meter reading technology. This technology eliminates the need to gain physical access to meters in order to obtain monthly meter readings, thereby reducing the time associated with each meter read while improving their accuracy. By the end of 2006, over 40 percent of Southwest customers’ meters were being read electronically. Reductions in staffing levels associated with these efficiencies have been accomplished through normal attrition. Some of

these experienced employees have been redeployed to expand service and construction capabilities. Over the next few years, Southwest will continue to invest in electronic meter reading technology to achieve additional efficiencies.

During the past decade, while adding nearly 692,000 customers, Southwest only increased staffing levels by 105. During this same period, Southwest’s customer to employee ratio has climbed from 451/1 to 706/1, an increase of over 50 percent. It has accomplished this without sacrificing service quality. Additional examples of technological improvements over the last few years include electronic order routing, an electronic mapping system and a work management system.

Customer growth requires significant capital outlays for new transmission and distribution plant and results in higher service costs associated with operating and maintaining such facilities. The following financing activities supported continued construction during 2006:

•

During 2006, the Company issued 2.4 million shares of common stock through its various stock plans, receiving over $70 million in proceeds.

•

In September 2006, the Company issued $56 million in Clark County, Nevada 4.75% Industrial Development Revenue Bonds (“IDRBs”) Series 2006A. The proceeds from the IDRBs were used by Southwest to expand and upgrade facilities in Clark County, Nevada.

•

During 2006, Southwest partially offset capital outlays by collecting approximately $48.6 million in net advances and contributions from customers and third-party contractors.

The results of the natural gas operations segment and the overall results of the Company are heavily dependent upon the three components noted previously (general rate relief, weather, and customer growth). Significant changes in these components (primarily weather) have contributed to somewhat volatile earnings historically. Management continues to work with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such a rate structure is in place in California and progress has been made in Nevada. Southwest continues to pursue rate design changes in Arizona.

Property Tax Settlement

In April 2006, a settlement was reached regarding property tax valuation disputes in Arizona for tax years 2001-2005. A decrease to property tax expense of $3.7 million and an accrual of $746,000 of interest income was recorded. This entry resulted in nonrecurring after-tax income of approximately $0.07 per share in 2006.

Natural Gas Price Volatility

Southwest has experienced price volatility over the past five years, as the weighted-average delivered cost of natural gas

Southwest Gas Corporation

has ranged from a low of 38 cents per therm in 2002 to a high of 79 cents per therm in 2006. Price volatility is expected to continue throughout 2007. Sustained high prices can result in increased under-collected purchased gas adjustment (“PGA”) balances and thereby temporarily reduce operating cash flows until rate relief is granted to recover the higher costs. During 2006, Southwest was able to increase gas cost recovery rates in all jurisdictions and has reduced uncollected PGA balances by $32 million since December 2005.

Stock-Based Compensation

During the first quarter of 2006, the Company began expensing all stock-based compensation costs. In 2006, gross expense was $4.9 million including $1.5 million for stock options and $3.4 million for performance shares. In 2005, expense related to stock-based compensation (performance shares) was $4.1 million.

2007 California Attrition Order

In October 2006, the Company made its 2007 annual California attrition filing requesting a $2.7 million increase in operating margin. The increase in customer rates was approved to be made effective January 2007. In connection

with this filing, the Company also received approval to change the way operating margin is recognized under the Company’s margin tracker mechanism. The change provides for authorized levels of margin to be recognized in equal monthly amounts throughout the year, rather than on a seasonally adjusted basis. This change will not impact the total amount of margin recognized annually; however it will affect the comparability of 2007 versus 2006 quarterly amounts. As a result, the $2.7 million authorized annual attrition increase to operating margin in 2007, as adjusted for the equalized margin tracker mechanism, is expected to result in the following year-over-year comparative changes (2007 versus 2006): a decrease of $7.7 million during the first quarter, and increases of $2.6 million, $7.4 million and $400,000 in the second, third and fourth quarters, respectively.

Results of Construction Services Operations

The Company’s construction subsidiary, NPL, increased its contribution to consolidated net income by $2.2 million in 2006 when compared to the prior year. The increase was primarily due to overall revenue growth, coupled with an improvement in the number of profitable bid jobs, and a sustained favorable equipment resale market in the current year.

Results of Natural Gas Operations


Year Ended December 31,	2006		2005		2004
(Thousands of dollars)

Gas operating revenues	$	1,727,394	$	1,455,257	$	1,262,052
Net cost of gas sold		1,033,988		828,131		645,766

Operating margin		693,406		627,126		616,286
Operations and maintenance expense		320,803		314,437		290,800
Depreciation and amortization		146,654		137,981		130,515
Taxes other than income taxes		34,994		39,040		37,669

Operating income		190,955		135,668		157,302
Other income (expense)		10,049		5,087		1,611
Net interest deductions		85,567		81,595		78,137
Net interest deductions on subordinated debentures		7,724		7,723		7,724

Income before income taxes		107,713		51,437		73,052
Income tax expense		36,240		17,767		24,698

Contribution to consolidated net income	$	71,473	$	33,670	$	48,354

2006 vs. 2005

Contribution from natural gas operations increased $37.8 million in 2006 compared to 2005. The improvement in contribution was primarily due to higher operating margin resulting from the Arizona general rate increase, a nonrecurring property tax settlement, and improved other income, partially offset by increased operating expenses and financing costs.

Operating margin increased $66 million in 2006 as compared to 2005. During 2006, the Company added 71,000 customers,

an increase of four percent. New customers coupled with additional amounts from existing transportation and non-weather sensitive sales customers contributed $26 million in incremental operating margin. Rate relief in Arizona and California added $37 million. Differences in heating demand caused primarily by weather variations between periods resulted in a $3 million operating margin increase as warmer-than-normal temperatures were experienced during both periods (during 2006, operating margin was negatively impacted by $16 million, while the negative impact in 2005 was $19 million).

Southwest Gas Corporation

Operations and maintenance expense increased $6.4 million, or two percent, between periods reflecting general cost increases and incremental operating costs associated with serving additional customers. Factors contributing to the increase included insurance premiums, uncollectible expenses, employee-related costs, and incremental stock-based compensation costs. Operations and maintenance expense for 2005 included a $10 million nonrecurring provision for an injuries and damages case (see Insurance Coverage below for more information).

Depreciation expense increased $8.7 million, or six percent, as a result of construction activities. Average gas plant in service for 2006 increased $238 million, or seven percent, compared to 2005. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.

General taxes decreased $4 million, or 10 percent, primarily as a result of the nonrecurring property tax settlement (see Property Tax Settlement for additional information) and Arizona legislation signed in June 2006 that reduced property tax rates, retroactive to January 2006.

Other income (expense) increased $5 million compared to 2005. The current period includes a $2 million net increase in interest income primarily associated with the unrecovered balance of deferred purchased gas costs and $1 million of interest income on the property tax settlement discussed above.

Net financing costs increased $4 million primarily due to higher rates on variable-rate debt and an increase in average debt outstanding to help finance growth.

Income tax expense in 2006 includes a nonrecurring $1.7 million state income tax benefit.

2005 vs. 2004

Contribution from natural gas operations decreased $14.7 million in 2005 compared to 2004. The decrease was principally the result of higher operating expenses, including a nonrecurring provision for an injuries and damages case, partially offset by improved, but lower than expected, operating margin.

Operating margin increased approximately $11 million in 2005 as compared to 2004. During 2005, the Company added 81,000 customers (excluding 19,000 customers associated with an acquisition in the South Lake Tahoe area), a growth rate of five percent. New customers contributed $20 million in incremental margin. Differences in heating demand primarily caused by weather variations between periods resulted in a $17 million margin decrease as warmer-than-normal temperatures were experienced during 2005, especially in Arizona. Rate relief in California and Nevada provided $8 million in new operating margin.

Operations and maintenance expense increased $23.6 million, or eight percent, compared to 2004. A significant component of the variance related to a $10 million nonrecurring provision for

an injuries and damages case (see Insurance Coverage below for more information). The increase also reflected general cost increases and incremental costs associated with providing service to a growing customer base. Factors contributing to the increase included higher insurance premiums, uncollectible expenses, employee-related costs, and compliance costs. Operations and maintenance expense for 2004 included $2.3 million in lease payments for an LNG facility which was purchased in December 2004.

Depreciation expense and general taxes increased $8.8 million, or five percent, as a result of construction activities. Average gas plant in service increased $248 million, or eight percent, as compared to 2004. The increase reflected ongoing capital expenditures for the upgrade of existing operating facilities, the expansion of the system to accommodate continued customer growth, and the purchase of the South Lake Tahoe properties.

Other income (expense) increased $3.5 million compared to 2004. Returns on long-term investments improved by approximately $1.2 million during 2005. Other income (expense) for 2005 also included an $800,000 improvement in interest income primarily associated with the unrecovered balance of deferred purchased gas costs and a $900,000 increase in the allowance for equity funds used during construction.

Net financing costs rose $3.5 million, or four percent, between years primarily due to an increase in average debt outstanding to help finance growth and higher rates on variable-rate debt.

Income tax expense in 2004 included $1.6 million of income tax benefits based on an analysis of current and deferred taxes following the completion of general rate cases and the closure of federal tax year 2000.

Rates and Regulatory Proceedings

Arizona General Rate Case. In February 2006, the ACC rendered a decision on the general rate case filed by Southwest in December 2004. The ACC approved a $49.3 million increase in operating revenues, effective March 2006. The decision did not include all of the rate design changes or the conservation tracker Southwest had requested. While the ACC did authorize an increase in the customer charge by $1.70 per month, the rate design approved for commodity sales continues to expose customers, investors and the Company to the risks associated with weather volatility. The ACC did however encourage Southwest to work with the ACC Staff and other interested parties prospectively to seek rate design alternatives that will provide benefits to all affected stakeholders. These collaborative discussions began during the third quarter of 2006 and will continue in the future. Southwest estimates that operating margin in 2006 reflected approximately $35 million of general rate relief in Arizona.

California Attrition Filings. In October 2005, Southwest made its 2006 annual attrition filing requesting a $4.5 million

Southwest Gas Corporation

increase in operating margin. The effective date of new rates was originally anticipated to be January 2006. The Division of Ratepayer Advocates (“DRA”) filed a protest to the attrition filing disagreeing with certain aspects of the Company’s calculation. As a result of the protest, the Energy Division suspended the filing. In December 2005, Southwest filed a motion requesting authorization to establish a memorandum account to track the related revenue shortfall between the existing and proposed rates in the attrition filing. The motion was approved effective April 13, 2006. In June 2006, the CPUC approved the revised 2006 attrition retroactive to the date of the memorandum account in April. Annualized rate relief of $3 million was granted of which approximately $2 million was recognized in 2006. Although the Company filed an application requesting that the memorandum account be made effective January 2006, consistent with the initial annual filing, this petition was denied during the fourth quarter, and as a result, the Company was unable to recover an estimated $1 million in operating margin resulting from the delayed effective date.

In October 2006, the Company made its 2007 annual attrition filing requesting a $2.7 million increase in operating margin. The increase in customer rates was approved to be made effective January 2007. In connection with this filing, the Company also received approval to change the way operating margin is recognized under the Company’s margin tracker mechanism. The change provides for authorized levels of margin to be recognized in equal monthly amounts throughout the year, rather than on a seasonally adjusted basis. This change will not impact the total amount of margin recognized annually; however it will affect the comparability of 2007 versus 2006 quarterly amounts. As a result, the $2.7 million authorized annual attrition increase to operating margin in 2007, as adjusted for the equalized margin tracker mechanism, is expected to result in the following year-over-year comparative changes (2007 versus 2006): a decrease of $7.7 million during the first quarter, and increases of $2.6 million, $7.4 million and $400,000 in the second, third and fourth quarters, respectively.

Nevada Weather Normalization Adjustment Provision. In March 2005, Southwest filed an application requesting the Public Utilities Commission of Nevada (“PUCN”) to approve a weather normalization adjustment provision in advance of the Company’s next general rate case. This filing requested that winter season billing volumes for weather sensitive customers be adjusted to reflect consumption variations that can be attributed to departures from normal weather. In the second quarter of 2005, the PUCN opened an investigation/rulemaking docket to address the issue of weather normalization, and in November 2005, the PUCN requested additional information. A joint report of the Regulatory Operations Staff and Bureau of Consumer Protection was filed in July 2006 recommending approval of a weather normalization adjustment provision. The PUCN subsequently declined to adopt the recommendation, effectively requiring the issue to be considered in future general rate case proceedings.

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. 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). In addition, since Southwest is permitted to accrue interest on PGA balances, the cost of incremental PGA-related short-term borrowings will be largely offset, and there should be no material negative impact to earnings.

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


	2006		2005
Arizona	$	68.4	$	46.8
Northern Nevada		1.1		12.6
Southern Nevada		4.1		39.4
California		3.4		10.6

	$	77.0	$	109.4

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. During the first quarter of 2006, the ACC approved an increase in the pre-established limit from $0.10 to $0.13 per therm. In addition, the ACC approved the implementation of a temporary PGA surcharge of $0.11 per therm effective February 2006 to pass through higher costs of natural gas incurred during 2005. The PGA balance in Arizona has been steadily declining after reaching a high of $95.8 million in April 2006.

Nevada Deferred Energy Adjustment Filing. Nevada Senate Bill No. 238, which became effective in October 2005, provides for quarterly gas cost adjustments calculated on a twelve-month rolling average. Adjustments are subject to an annual prudence review and audit of the natural gas costs incurred. This new quarterly adjustment mechanism was effective in allowing Southwest to minimize the PGA balance by year end 2006.

California Gas Cost Filings. In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments are designed to provide a more timely recovery of gas costs and to send appropriate pricing signals to customers.

Southwest Gas Corporation

Other Filings

El Paso Transmission System. In June 2005, El Paso Natural Gas Company (“El Paso”) filed a general rate case application with the Federal Energy Regulatory Commission (“FERC”). (Southwest is dependent upon El Paso for the transportation of natural gas for virtually all of its Arizona service territories, and through August 2006, part of its southern Nevada service territories.) As part of its application, which is the first since the conversion of full requirements customers like Southwest to contract demand services, El Paso proposed various tariff changes along with new service offerings. The annual increase in gas transportation costs to Southwest was approximately $19.1 million. The new rates became effective January 2006, subject to refund. However, the implementation of new services and certain overrun and imbalance penalty charges proposed in El Paso’s application was phased-in during the period June 2006 through November 2006. In December 2006, El Paso filed a settlement offer with the FERC which would resolve many of the issues raised in the general rate case proceeding. Southwest expects to fully recover any increased costs resulting from a final order or settlement in the case.

Capital Resources and Liquidity

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. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.

2006 Construction Expenditures

Southwest continues to experience high customer growth. This growth has required significant capital outlays for new transmission and distribution plant, to keep up with consumer demand. During the three-year period ended December 31, 2006, total gas plant increased from $3 billion to $3.8 billion, or at an annual rate of seven percent. Customer growth was the primary reason for the plant increase as Southwest added 253,000 net new customers (including 19,000 customers acquired in the South Lake Tahoe area) during the three-year period.

During 2006, construction expenditures for the natural gas operations segment were $306 million. Approximately 76 percent of these expenditures represented new construction and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant. Cash flows from operating activities of Southwest (net of dividends) provided $215 million of the required capital resources pertaining to total capital expenditures in 2006. The remainder was provided from external financing activities and existing credit facilities.

2006 Financing Activity

The Company has a universal shelf registration statement providing for the issuance and sale of registered securities, which may consist of secured debt, unsecured debt, preferred stock, or common stock. At December 31, 2006, the Company had $95 million in securities available for issuance under the universal shelf registration statement.

In March 2006, the Company entered into a Sales Agency Financing Agreement with BNY Capital Markets, Inc. relating to the issuance and sale of up to $45 million aggregate amount of shares of the Company’s common stock, from time to time over a three-year period (“Equity Shelf Program”). Sales of the shares are made at market prices prevailing at the time of sale. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are used for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves. During 2006, approximately 947,000 shares were issued in at-the-market offerings through the Equity Shelf Program at an average price of $29.87 per share with gross proceeds of $28.3 million, agent commissions of $283,000, and net proceeds of $28 million.

During 2006, the Company issued approximately 1.5 million additional shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), Employee Investment Plan, Management Incentive Plan, and Stock Incentive Plan. In addition, in 2006, Southwest offset capital outlays by collecting approximately $48.6 million in net advances and contributions from third-party contractors.

In September 2006, the Company issued $56 million in Clark County, Nevada 4.75% IDRBs Series 2006A pursuant to a financing agreement and indenture. The IDRBs were issued at a discount of 0.625% and are due September 1, 2036. The net proceeds from the IDRBs were used by Southwest to expand and upgrade facilities in Clark County, Nevada.

2007 Construction Expenditures and Financing

Southwest estimates construction expenditures during the three-year period ending December 31, 2009 will be approximately $880 million. Of this amount, approximately $337 million are expected to be incurred in 2007. During the three-year period, cash flow from operating activities (net of dividends) is estimated to fund over 90 percent of the gas operations’ total construction expenditures, assuming timely recovery of currently deferred PGA balances. Southwest also has $43 million in long-term debt maturities over the three-year period. Maturities would increase to $50.5 million if an existing bondholder exercises a discretionary put option in 2007. The Company expects to raise $100 million to $125 million from its various common stock programs. Any remaining cash requirements are expected to be provided by existing credit facilities and/or other external financing

Southwest Gas Corporation

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 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.

Contractual Obligations

Obligations under long-term debt, gas purchase obligations and significant non-cancelable operating leases at December 31, 2006 were as follows (millions of dollars):


	Payments due by period
	Total		2007		2008-2009		2010-2011		Thereafter
Contractual Obligations
Subordinated debentures to Southwest Gas Capital II (Note 5) (a)	$	383	$	8	$	15	$	15	$	345
Long-term debt (Note 6) (a)		2,414		102		183		471		1,658
Operating leases (Note 2)		32		5		9		5		13
Gas purchase obligations (b)		519		422		97		—		—
Pipeline capacity (c)		667		105		195		189		178
Other commitments		17		6		6		2		3

Total	$	4,032	$	648	$	505	$	682	$	2,197

(a)	Includes scheduled principal and interest payments over the life of the debt.

(b)	Includes fixed-price and variable-rate gas purchase contracts covering approximately 140 million dekatherms. Fixed-price contracts range in price from $6 to $11 per dekatherm. Variable-price contracts reflect minimum contractual obligations.

(c)

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. 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.

Estimated funding for pension and other postretirement benefits during calendar year 2007 is $24 million.

Liquidity

Liquidity refers to the ability of an enterprise to generate adequate amounts of cash to meet its cash requirements. Several general factors that could significantly affect liquidity in future years include inflation, growth in Southwest’s service territories, changes in the ratemaking policies of regulatory commissions, interest rates, variability of natural gas prices, changes in income tax laws, and the level of Company earnings. Of these factors natural gas prices have had the most significant impact on Company liquidity.

Over the past five years the weighted-average delivered cost of natural gas has ranged from a low of 38 cents per therm in 2002 to a high of 79 cents per therm in 2006. Price volatility is expected to continue throughout 2007. Southwest periodically enters into fixed-price term contracts to mitigate price volatility. About half of Southwest’s annual normal weather supply needs are secured using short duration contracts (one year or less). For the 2006/2007 heating season, fixed price contracts ranged in price from $6 to $11 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. Southwest does not currently utilize other stand-alone derivative financial instruments for speculative purposes, or for hedging. During 2007, Southwest

intends to supplement its current volatility mitigation program with stand-alone derivative instruments. The combination of fixed-price contracts and derivative instruments should increase flexibility for Southwest and increase supplier diversification. The costs of such derivative financial instruments are expected to be recovered from customers.

The rate schedules in Southwest’s service territories contain PGA clauses which permit adjustments to rates as the cost of purchased gas changes. The PGA mechanism allows Southwest to request to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service.

On an interim basis, Southwest generally 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, 2006, the combined balances in PGA accounts totaled an under-collection of $77 million versus an under-collection of $109 million at December 31, 2005. See PGA Filings for more information on recent regulatory filings. Southwest has the ability to draw on its $300 million credit facility to temporarily finance under-collected PGA balances.

Southwest Gas Corporation

This facility runs through April 2011. Southwest has designated $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. Southwest currently believes the $150 million designated for working capital purposes is adequate to meet liquidity needs. At December 31, 2006, $147 million was outstanding on the long-term portion and no borrowings were outstanding on the short-term portion of the credit facility.

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. 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. See discussion below for the impact of a recent credit rating change.

Securities 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., the better the rating, the lower the cost to borrow funds).

In May 2006, Moody’s Investors Service, Inc. (“Moody’s”) lowered its rating on the Company’s unsecured long-term debt to Baa3 from Baa2 and changed the outlook for the rating to stable from negative. The change in credit rating will result in an annualized estimated increase of $375,000 in interest expense on existing long-term debt. No debt covenants were affected by the downgrade. Moody’s cited a long-term warming trend in the Company’s service territories, regulatory lag, and weak credit measures as some of the factors behind the downgrade. 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.

The Company’s unsecured long-term debt rating from Fitch, Inc. (“Fitch”) is BBB. 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.

The Company’s unsecured long-term debt rating from Standard and Poor’s Ratings Services (“S&P”) is BBB-. S&P debt ratings range from AAA (highest rating possible) to D

(obligation is in default). The S&P rating of BBB- indicates the debt is regarded as having an adequate capacity to pay interest and repay principal.

A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency.

Inflation

Results of operations are impacted by inflation. Natural gas, labor, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor is a component 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.

Insurance Coverage

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. For the policy year August 2004 to July 2005, the self-insured retention amount associated with general liability claims was $1 million per incident plus payment of the first $10 million in aggregate claims above $1 million in the policy year. In May 2005, a leaking natural gas line was involved in a fire that severely injured an individual. The leak is believed to have been caused by a rock impinging upon a natural gas line that was installed for Southwest Gas and that is owned and operated by the Company. In December 2005, the plaintiffs filed a complaint against the Company claiming $3.4 million in medical bills, $12 million in future medical expenses, and unspecified claims for general and punitive damages. By December 2005, the Company had recorded a total liability related to this incident equal to the Company’s maximum self- insured retention level of $11 million. In the fourth quarter of 2006, the case was settled. The amount of the settlement that exceeded $11 million was covered by insurance. The Company’s current insurance contracts limit the self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million.

Southwest Gas Corporation

Results of Construction Services


Year Ended December 31,	2006		2005		2004
(Thousands of dollars)

Construction revenues	$	297,364	$	259,026	$	215,008
Cost of construction		271,743		237,356		196,792

Gross profit		25,621		21,670		18,216
General and administrative expenses		7,377		6,672		5,742

Operating income		18,244		14,998		12,474
Other income (expense)		4,086		3,009		2,131
Interest expense		1,686		1,009		645

Income before income taxes		20,644		16,998		13,960
Income tax expense		8,257		6,845		5,539

Contribution to consolidated net income	$	12,387	$	10,153	$	8,421

2006 vs. 2005

The 2006 contribution to consolidated net income from construction services increased $2.2 million from 2005. The factors that drove the favorable results include a 15 percent increase in revenues, an improvement in the number of profitable bid jobs, and a favorable equipment resale market.

Revenues increased $38 million due primarily to an increased workload under several existing contracts and an improvement in the amount and profitability of new bid work. Gross profit increased approximately $4 million, or 18 percent, as a direct result of the increase in revenues. The construction revenues above include NPL contracts with Southwest totaling $80.6 million in 2006, $71.8 million in 2005, and $61.6 million in 2004. NPL accounts for the services provided to Southwest at contractual (market) prices.

General and administrative costs increased $705,000 due primarily to incremental costs associated with growth including labor and other administrative expenses. Other income increased $1.1 million as a result of an increase in gains on sale of equipment. Interest expense increased $677,000 due to additional long-term borrowing for the purchase of new equipment and higher interest rates.

Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including interest rates, employment levels, job growth, and

local and federal tax rates. The slow-down in construction activities observed in regional and national markets at the end of 2006, if sustained, could negatively impact the amount of work received under existing blanket contracts, the amount of bid work, and the equipment resale market in 2007.

2005 vs. 2004

The 2005 contribution to consolidated net income from construction services increased $1.7 million from 2004. The increase was primarily due to overall revenue growth, coupled with an improvement in the number of profitable bid jobs and a favorable equipment resale market in 2005.

Revenues and gross profit for 2005 reflect an increased workload under existing contracts and an increase in the quantity and profitability of bid work. Favorable working conditions in several operating areas facilitated additional construction activity.

General and administrative costs increased $930,000 due primarily to the depreciation expense related to the implementation of new computer systems and compliance costs. Other income (expense) increased $878,000 as a result of an increase in gains on sale of equipment. Interest expense rose $364,000 due to additional long-term borrowing for the purchase of new equipment and higher interest rates.

Southwest Gas Corporation

Recently Issued Accounting Pronouncements

Below is a listing of recently issued accounting pronouncements by the Financial Accounting Standards Board (“FASB”). See Note 1—Summary of Significant Accounting Policies for more information regarding these accounting pronouncements and their potential impact on the Company’s financial position and results of operations.


Title	Month of Issue	Effective Date

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140.”	February 2006	January 2007

SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140.”	March 2006	January 2007

FIN No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.”	June 2006	January 2007

SFAS No. 157, “Fair Value Measurements.”	September 2006	January 2008

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 critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1—Summary of Significant Accounting Policies.

Regulatory Accounting

Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated enterprises (including SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”) 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.

Unbilled 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, revenues for natural gas that has been delivered but not yet billed are accrued. This unbilled revenue is estimated each month based on daily sales volumes, applicable rates, 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 unbilled revenue estimates.

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

Southwest Gas Corporation

statement tax provisions and adjusts the tax provisions when necessary as additional information is obtained. A change in the regulatory treatment or significant changes in tax-related estimates, assumptions, or enacted tax rates 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 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.

Due to an increase in market interest rates for high-quality fixed income investments, the Company raised the discount rate to 6.00% at December 31, 2006 from 5.75% at December 31, 2005. The weighted-average rate of compensation increase was raised to 3.75% from 3.30%. The Company maintained its asset return assumption for 2007 at 8.50%. These offsetting changes will not result in a significant change in pension expense for 2007. Should interest rates rise in 2007, future pension expense and projected benefit obligations could decrease. Conversely, declining interest rates would put upward pressure on future pension expense and projected benefit obligations.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)”, which requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in their balance sheets. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in accumulated other comprehensive income under stockholders’ equity, net of tax, until they are amortized as a component of net periodic benefit cost. SFAS No. 158 does not change how net periodic pension and postretirement costs are accounted for and reported in the income statement. The Company adopted the provisions of SFAS No. 158 effective December 31, 2006.

In accordance with SFAS No. 71, 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 losses and prior service credits 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. See Note 9—Pension and Other Postretirement Benefits for plan assumptions and further discussion of the impact of adopting SFAS No. 158.

Management believes that regulation and the effects of regulatory accounting have the most significant impact on the financial statements. When Southwest files rate cases, capital assets, costs, and gas purchasing practices are subject to review, and disallowances can occur. Regulatory disallowances in the past have not been frequent but have on occasion been significant to the operating results of the Company.

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, 2006 were included as exhibits to the 2006 Annual Report on Form 10-K which was filed with the SEC. The Company is also required to file an annual CEO certification regarding corporate governance listing standards compliance with the New York Stock Exchange (“NYSE”). The most recent annual CEO certification, dated May 10, 2006, was filed with the NYSE in May 2006.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the 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, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. In particular, statements regarding customer growth, estimated construction expenditures, the sources and amounts of financing, customer mix and revenue patterns, efficiencies resulting from new technology, construction services contribution, ability to receive more effective rate designs, the expected results of the projected impact in 2007 due to changes in the margin tracker mechanism, sufficiency of working

Southwest Gas Corporation

capital and ability to raise funds and receive external financing, and statements regarding future gas prices, future PGA balances, the effects of recent accounting pronouncements, and the timing and results of future rate approvals and guidelines 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, the impact of weather variations on customer usage, customer growth rates, changes in natural gas prices, our ability to recover costs through our PGA mechanism, 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 accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing, 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 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

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


	2006				2005				Dividends Declared
	High		Low		High		Low		2006		2005
First quarter	$	29.04	$	26.09	$	26.13	$	23.66	$	0.205	$	0.205
Second quarter		31.43		26.46		26.35		23.53		0.205		0.205
Third quarter		34.19		30.70		28.07		25.00		0.205		0.205
Fourth quarter		39.37		32.80		27.86		25.12		0.205		0.205

									$	0.820	$	0.820

The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its

respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend was 20.5 cents per share throughout 2006. The dividend of 20.5 cents per share has been paid quarterly since September 1994. In February 2007, the Board of Directors increased the quarterly dividend payout to 21.5 cents per share, effective with the June 2007 payment.

Southwest Gas Corporation

Consolidated Balance Sheets


	December 31,
	2006			2005
(Thousands of dollars, except par value)

ASSETS
Utility plant:
Gas plant	$	3,763,310		$	3,516,587
Less: accumulated depreciation		(1,175,600	)		(1,083,900	)
Acquisition adjustments, net		1,992			2,173
Construction work in progress		78,402			54,287

Net utility plant (Note 2)		2,668,104			2,489,147

Other property and investments		136,242			118,094

Current assets:
Cash and cash equivalents		18,786			29,603
Accounts receivable, net of allowances (Note 3)		225,928			198,081
Accrued utility revenue		73,300			68,400
Deferred purchased gas costs (Note 4)		77,007			109,415
Prepaids and other current assets (Note 4)		106,603			137,161

Total current assets		501,624			542,660

Deferred charges and other assets (Note 4)		178,995			78,525

Total assets	$	3,484,965		$	3,228,426

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized–45,000,000 shares; issued and outstanding–41,770,291 and 39,328,291 shares) (Note 10)	$	43,400		$	40,958
Additional paid-in capital		698,258			628,248
Accumulated other comprehensive income (loss), net (Note 9)		(13,666	)		(41,645	)
Retained earnings		173,433			123,574

Total equity		901,425			751,135
Subordinated debentures due to Southwest Gas Capital II (Note 5)		100,000			100,000
Long-term debt, less current maturities (Note 6)		1,286,354			1,224,898

Total capitalization		2,287,779			2,076,033

Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)		27,545			83,215
Short-term debt (Note 7)		—			24,000
Accounts payable		265,739			259,476
Customer deposits		64,151			57,552
Accrued general taxes		45,895			40,526
Accrued interest		21,362			22,472
Deferred income taxes (Note 11)		15,471			68,166
Other current liabilities		55,901			65,546

Total current liabilities		496,064			620,953

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 11)		308,493			234,739
Taxes payable		5,951			7,551
Accumulated removal costs (Note 4)		125,000			105,000
Other deferred credits (Note 9)		261,678			184,150

Total deferred income taxes and other credits		701,122			531,440

Total capitalization and liabilities	$	3,484,965		$	3,228,426

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Consolidated Statements Of Income


Year Ended December 31,	2006			2005			2004
(In thousands, except per share amounts)

Operating revenues:
Gas operating revenues	$	1,727,394		$	1,455,257		$	1,262,052
Construction revenues		297,364			259,026			215,008

Total operating revenues		2,024,758			1,714,283			1,477,060

Operating expenses:
Net cost of gas sold		1,033,988			828,131			645,766
Operations and maintenance		320,803			314,437			290,800
Depreciation and amortization		168,964			156,253			146,018
Taxes other than income taxes		34,994			39,040			37,669
Construction expenses		256,827			225,774			187,040

Total operating expenses		1,815,576			1,563,635			1,307,293

Operating income		209,182			150,648			169,767

Other income and (expenses):
Net interest deductions		(87,253	)		(82,604	)		(78,782	)
Net interest deductions on subordinated debentures (Note 5)		(7,724	)		(7,723	)		(7,724	)
Other income (deductions)		14,152			8,114			3,751

Total other income and (expenses)		(80,825	)		(82,213	)		(82,755	)

Income before income taxes		128,357			68,435			87,012
Income tax expense (Note 11)		44,497			24,612			30,237

Net income	$	83,860		$	43,823		$	56,775

Basic earnings per share (Note 13)	$	2.07		$	1.15		$	1.61

Diluted earnings per share (Note 13)	$	2.05		$	1.14		$	1.60

Average number of common shares outstanding		40,566			38,132			35,204
Average shares outstanding (assuming dilution)		40,975			38,467			35,488

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Consolidated Statements Of Cash Flows


Year Ended December 31,	2006			2005			2004
(Thousands of dollars)

CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	83,860		$	43,823		$	56,775
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		168,964			156,253			146,018
Deferred income taxes		3,909			(5,514	)		38,001
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(27,847	)		(20,216	)		(49,307	)
Accrued utility revenue		(4,900	)		982			(1,500	)
Deferred purchased gas costs		32,408			(25,865	)		(72,925	)
Accounts payable		6,263			92,021			55,758
Accrued taxes		3,198			5,716			3,027
Other current assets and liabilities		24,156			(23,000	)		(25,406	)
Other		(8,657	)		13,424			1,050

Net cash provided by operating activities		281,354			237,624			151,491

CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(345,325	)		(294,369	)		(302,688	)
Other		33,199			1,985			6,106

Net cash used in investing activities		(312,126	)		(292,384	)		(296,582	)

CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		72,452			64,136			58,687
Dividends paid		(33,500	)		(31,228	)		(28,836	)
Issuance of long-term debt, net		92,400			145,256			147,135
Retirement of long-term debt		(84,397	)		(31,442	)		(83,437	)
Temporary changes in long-term debt		(3,000	)		—			—
Change in short-term debt		(24,000	)		(76,000	)		48,000

Net cash provided by financing activities		19,955			70,722			141,549

Change in cash and cash equivalents		(10,817	)		15,962			(3,542	)
Cash at beginning of period		29,603			13,641			17,183

Cash at end of period	$	18,786		$	29,603		$	13,641

Supplemental information:
Interest paid, net of amounts capitalized	$	92,533		$	86,465		$	80,433

Income taxes paid (received), net	$	39,682		$	5,977		$	(12,640	)

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Consolidated Statements Of Stockholders’ Equity And

Comprehensive Income


	Common Stock				Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total			Comprehensive Income (Loss)
	Shares		Amount		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total			Comprehensive Income (Loss)
(In thousands, except per share amounts)

DECEMBER 31, 2003	34,232		$	35,862	$	510,521	$	—		$	84,084		$	630,467
Common stock issuances	2,562			2,562		56,125								58,687
Net income											56,775			56,775		$	56,775
Additional minimum pension liability adjustment, net of $6.5 million of tax (Note 9)								(10,892	)					(10,892	)		(10,892	)

Dividends declared
Common: $0.82 per share											(29,361	)		(29,361	)

2004 Comprehensive Income																$	45,883


DECEMBER 31, 2004	36,794			38,424		566,646		(10,892	)		111,498			705,676
Common stock issuances	2,534			2,534		61,602								64,136
Net income											43,823			43,823		$	43,823
Additional minimum pension liability adjustment, net of $19 million of tax (Note 9)								(30,753	)					(30,753	)		(30,753	)

Dividends declared
Common: $0.82 per share											(31,747	)		(31,747	)

2005 Comprehensive Income																$	13,070


DECEMBER 31, 2005	39,328			40,958		628,248		(41,645	)		123,574			751,135
Common stock issuances	2,442			2,442		70,010								72,452
Net income											83,860			83,860		$	83,860
Additional minimum pension liability adjustment, net of $20.3 million of tax (Note 9)								33,047						33,047			33,047
Net adjustment to adopt SFAS No. 158, net of $3.1 million of tax (Note 9)								(5,068	)					(5,068	)

Dividends declared
Common: $0.82 per share											(34,001	)		(34,001	)

2006 Comprehensive Income																$	116,907


DECEMBER 31, 2006	41,770	*	$	43,400	$	698,258	$	(13,666	)	$	173,433		$	901,425

At December 31, 2006, 1.3 million common shares were registered and available for issuance under provisions of the Employee Investment Plan and the Dividend Reinvestment and Stock Purchase Plan. In addition, 1 million common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10). During 2006, approximately 947,000 shares were issued in at-the-market offerings through the Equity Shelf Program with gross proceeds of $28.3 million, agent commissions of $283,000, and net proceeds of $28 million.

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Notes to Consolidated Financial Statements

Note 1 Summary of Significant Accounting Policies

Nature of Operations. Southwest Gas Corporation (the “Company”) is composed 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 to 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. Northern Pipeline Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

Basis of Presentation. The Company follows generally accepted accounting principles (“GAAP”) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with 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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries, except for Southwest Gas Capital II (see Note 5). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

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 purchased maturity of three months or less.

Accumulated Removal Costs. In accordance with approved regulatory practices, the depreciation expense for Southwest includes 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 $125 million and $105 million, as of December 31, 2006 and 2005, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheet.

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.

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.

Construction Revenues. The majority of the 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.

Southwest Gas Corporation

Note 1 Summary of Significant Accounting Policies (Continued)

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 salvage value, removal costs, 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. Costs related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets.

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 Company capitalized $2.8 million in 2006, $2 million in 2005, and $808,000 in 2004 of AFUDC related to natural gas utility operations. 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. The debt portion of AFUDC was $1.4 million, $1.1 million and $691,000 for 2006, 2005 and 2004, respectively. 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.

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 and performance shares). 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.


	2006	2005	2004
(In thousands)
Average basic shares	40,566	38,132	35,204
Effect of dilutive securities:
Stock options	195	146	111
Performance shares	214	189	173

Average diluted shares	40,975	38,467	35,488

Derivatives. In managing its gas supply portfolios, Southwest uses fixed-price and variable-rate arrangements which qualify as derivative instruments as defined under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133). However, such contracts qualify for the normal purchases and normal sales exception under SFAS No. 133 or have no significant market

value. The Company does not currently utilize other stand-alone derivative financial instruments for speculative purposes or for hedging.

Recently Issued Accounting Pronouncements. In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation and clarifies several other related issues. The provisions of SFAS No. 155 are effective for the Company for all financial instruments acquired or issued after January 1, 2007. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.

In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets—an amendment of FASB Statement No. 140.” SFAS No. 156 addresses the recognition and measurement of separately recognized servicing assets and liabilities and provides an approach to simplify efforts to obtain hedge-like (offset) accounting. The provisions of SFAS No. 156 are effective for the Company for the recognition and initial measurement of servicing assets and liabilities acquired or issued after January 1, 2007. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.

In June 2006, the FASB issued Financial Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes,” and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN No. 48 is effective for the Company beginning January 1, 2007. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. The provisions of SFAS No. 157 are effective for the Company beginning January 1, 2008. The Company is evaluating what impact, if any, this standard might have on its financial position or results of operations.

Stock-Based Compensation. At December 31, 2006, the Company had two stock-based compensation plans which are described more fully in Note 10—Stock-Based Compensation. Prior to January 1, 2006, these plans were

Southwest Gas Corporation

Note 1 Summary of Significant Accounting Policies (Continued)

accounted for in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payment”, using the modified prospective transition method. Accordingly, financial information for prior periods has not been restated. The adoption of SFAS No. 123 (revised 2004) did not have a material impact on the Company’s financial position, results of operations, or cash flows. Under the modified prospective transition method, expense is recognized for any new awards

granted after the effective date and for the unvested portion of awards granted prior to the effective date. Total stock-based compensation expense recognized in the consolidated statements of income for the year ended December 31, 2006 was $3.3 million (net of related tax benefits of $1.6 million). The pro forma effects of recognizing the estimated fair value of stock-based compensation for periods prior to the adoption of SFAS No. 123 (revised 2004) are presented below (thousands of dollars, except per share amounts):


	2005			2004
Net income, as reported	$	43,823		$	56,775
Add: Stock-based employee compensation expense included in reported net income, net of related tax benefits		2,469			1,825
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax benefits		(2,620	)		(1,958	)

Pro forma net income	$	43,672		$	56,642

Earnings per share:
Basic—as reported	$	1.15		$	1.61
Basic—pro forma		1.15			1.61

Diluted—as reported		1.14			1.60
Diluted—pro forma		1.14			1.60

Note 2 Utility Plant

Net utility plant as of December 31, 2006 and 2005 was as follows (thousands of dollars):


December 31,	2006			2005
Gas plant:
Storage	$	17,545		$	17,357
Transmission		243,989			239,872
Distribution		3,153,399			2,917,959
General		219,527			213,906
Other		128,850			127,493

		3,763,310			3,516,587
Less: accumulated depreciation		(1,175,600	)		(1,083,900	)
Acquisition adjustments, net		1,992			2,173
Construction work in progress		78,402			54,287

Net utility plant	$	2,668,104		$	2,489,147

Depreciation and amortization expense on gas plant was $145 million in 2006, $137 million in 2005, and $128 million in 2004.

Southwest Gas Corporation

Note 2 Utility Plant (Continued)

Operating Leases and Rentals. Southwest leases a portion of its corporate headquarters office complex in Las Vegas, and its administrative offices in Phoenix. The leases provide for current terms which expire in 2017 and 2009, respectively, with optional renewal terms available at the expiration dates. The rental payments for the corporate headquarters office complex are $2 million in each of the years 2007 through 2011 and $12.2 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.5 million for each of the years 2007 and 2008, and $1 million in 2009 when the lease expires. 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. Rentals included in operating expenses for all operating leases were $19.2 million in 2006, $19 million in 2005, and $20.3 million in 2004. These amounts include NPL lease expenses of

approximately $11.5 million in 2006, $11.5 million in 2005, and $9.8 million in 2004 for various short-term operating leases of equipment and temporary office sites.

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, 2006 (thousands of dollars):


Year Ending December 31,
2007	$	5,378
2008		4,868
2009		4,010
2010		2,568
2011		2,433
Thereafter		12,890

Total minimum lease payments	$	32,147

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. At December 31, 2006, the gas utility customer accounts receivable balance was $182 million. Approximately 54 percent of the gas utility customers were in Arizona, 36 percent in Nevada, and 10 percent in California. 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. Provisions for uncollectible accounts are recorded monthly, as needed, and are included in the ratemaking process as a cost of service. Activity in the allowance for uncollectibles is summarized as follows (thousands of dollars):


	Allowance for Uncollectibles
Balance, December 31, 2003	$	2,246
Additions charged to expense		2,586
Accounts written off, less recoveries		(2,860	)

Balance, December 31, 2004		1,972
Additions charged to expense		3,787
Accounts written off, less recoveries		(3,458	)

Balance, December 31, 2005		2,301
Additions charged to expense		5,805
Accounts written off, less recoveries		(5,085	)

Balance, December 31, 2006	$	3,021

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 generally accepted accounting principles applicable to rate-regulated enterprises, principally SFAS No. 71, and reflect the effects of the ratemaking process. SFAS

No. 71 allows for the deferral as regulatory assets, costs that otherwise would be expensed if it is probable future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

Southwest Gas Corporation

Note 4 Regulatory Assets and Liabilities (Continued)

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


December 31,	2006			2005
Regulatory assets:
Accrued pension and other postretirement benefit costs * (Note 9)	$	101,402		$	—
Deferred purchased gas costs		77,007			109,415
Accrued purchased gas costs **		40,500			75,300
SFAS No. 109—income taxes, net *		1,846			2,447
Unamortized premium on reacquired debt *		17,676			18,386
Other		30,099			28,236

		268,530			233,784
Regulatory liabilities:
Accumulated removal costs		(125,000	)		(105,000	)
Other ***		(1,111	)		(821	)

Net regulatory assets (liabilities)	$	142,419		$	127,963

*	Included in Deferred charges and other assets on the Consolidated Balance Sheet.

**	Included in Prepaids and other current assets on the Consolidated Balance Sheet.

***	Included in Other deferred credits on the Consolidated Balance Sheet.

Other regulatory assets include deferred costs associated with rate cases, regulatory studies, margin and interest-tracking accounts, and state mandated public purpose

programs (including low income and conservation programs), as well as amounts associated with accrued absence time and deferred post-retirement benefits other than pensions.

Note 5 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, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the distribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures are redeemable at the option of the Company after August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest.

In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Trust Securities. As of December 31, 2006, 4.1 million Preferred Trust Securities were outstanding.

The Company has the right to defer payments of interest on the Subordinated Debentures by extending the interest payment period at any time for up to 20 consecutive quarters

Southwest Gas Corporation

Note 5 Preferred Trust Securities and Subordinated Debentures (Continued)

(each, an “Extension Period”). If interest payments are so deferred, distributions to Preferred Trust Securities holders will also be deferred. During such Extension Period, distributions will continue to accrue with interest thereon (to the extent permitted by applicable law) at an annual rate of 7.70% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Debentures. If the Company exercises the right to extend an interest payment period, the Company shall not during such Extension Period (i) declare or pay dividends on, or make a distribution with respect to, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, or (ii) make any payment of interest, principal, or premium, if any, on or repay, repurchase, or redeem any debt securities issued by the Company that rank equal with or junior to the Subordinated Debentures; provided, however, that restriction (i) above does not apply to any stock dividends paid by the Company where

the dividend stock is the same as that on which the dividend is being paid. The Company has no present intention of exercising its right to extend the interest payment period on the Subordinated Debentures.

Although the Company owns 100 percent of the common voting securities of Trust II, under Interpretation No. 46 “Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51”, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. As a result, the $103.1 million Subordinated Debentures are shown on the balance sheet of the Company, net of the $3.1 million Common Securities, as Subordinated debentures due to Southwest Gas Capital II. Payments and amortizations associated with the Subordinated Debentures are classified on the consolidated statements of income as Net interest deductions on subordinated debentures.

Southwest Gas Corporation

Note 6 Long-Term Debt


December 31,	2006					2005
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
7¹/2% Series, due 2006	$	—		$	—	$	75,000		$	76,155
Notes, 8.375%, due 2011		200,000			221,200		200,000			225,720
Notes, 7.625%, due 2012		200,000			217,600		200,000			222,040
8% Series, due 2026		75,000			88,748		75,000			90,525
Medium-term notes, 6.89% series, due 2007		17,500			17,654		17,500			17,971
Medium-term notes, 6.27% series, due 2008		25,000			25,263		25,000			25,600
Medium-term notes, 7.59% series, due 2017		25,000			28,155		25,000			28,573
Medium-term notes, 7.78% series, due 2022		25,000			28,645		25,000			29,088
Medium-term notes, 7.92% series, due 2027		25,000			29,398		25,000			30,000
Medium-term notes, 6.76% series, due 2027		7,500			7,832		7,500			7,976
Unamortized discount		(4,021	)		—		(4,657	)		—

		595,979					670,343

Revolving credit facility and commercial paper		147,000			147,000		150,000			150,000

Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2003 Series B, due 2038		50,000			50,000		50,000			50,000
Fixed-rate bonds:
6.10% 1999 Series A, due 2038		12,410			13,093		12,410			13,068
5.95% 1999 Series C, due 2038		14,320			15,136		14,320			15,057
5.55% 1999 Series D, due 2038		8,270			8,696		8,270			8,593
5.45% 2003 Series C, due 2038		30,000			30,705		30,000			30,264
5.25% 2003 Series D, due 2038		20,000			20,836		20,000			20,400
5.80% 2003 Series E, due 2038		15,000			15,629		15,000			15,218
5.25% 2004 Series A, due 2034		65,000			67,210		65,000			65,878
5.00% 2004 Series B, due 2033		75,000			76,688		75,000			75,000
4.85% 2005 Series A, due 2035 net of $24.6 million held in trust in 2005		100,000			101,050		75,366			73,030
4.75% 2006 Series A, due 2036		56,000			56,213		—			—
Unamortized discount		(4,697	)		—		(4,159	)		—

		541,303					461,207

Other		29,617			—		26,563			—

		1,313,899					1,308,113
Less: current maturities		(27,545	)				(83,215	)

Long-term debt, less current maturities	$	1,286,354				$	1,224,898

Southwest Gas Corporation

Note 6 Long-Term Debt (Continued)

In April 2006, the Company amended its $300 million credit facility. The facility was originally scheduled to expire in April 2010 and was extended to April 2011. The Company will continue to use $150 million of the $300 million as long-term debt 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. The applicable margin, unused commitment fee, and utilization fee associated with the amended credit facility are lower than those of the previous facility. At December 31, 2006, no borrowings were outstanding on the short-term portion of the credit facility and $147 million was outstanding on the long-term portion.

In September 2006, the Company issued $56 million in Clark County, Nevada 4.75% industrial development revenue bonds (“IDRBs”) Series 2006A pursuant to a financing agreement and indenture. The IDRBs were issued at a discount of 0.625% and are due September 1, 2036. The proceeds from the IDRBs were used by Southwest to expand and upgrade facilities in Clark County, Nevada.

The Company’s Revolving Credit Facility, letters of credit, and certain bond insurance policies contain financial covenants, the most restrictive of which require a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $475 million adjusted for equity issuances after May 10, 2002. If the Company was not in compliance with these covenants, an event of default would

occur, which if not cured could cause the amounts outstanding to become due and payable. This would also trigger cross-default provisions in substantially all other outstanding indebtedness of the Company. At December 31, 2006, the Company was in compliance with the applicable covenants.

The effective interest rates on the 2003 Series A and B variable-rate IDRBs were 5.14 percent and 4.09 percent, respectively, at December 31, 2006 and 4.64 percent and 3.84 percent, respectively, at December 31, 2005. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 5.03 percent and 4.55 percent at December 31, 2006 and 2005, respectively.

The fair value of the revolving credit facility and the variable-rate IDRBs approximates carrying value. Market values for the debentures and fixed-rate IDRBs were determined based on dealer quotes using trading records for December 31, 2006 and 2005, as applicable, and other secondary sources which are customarily consulted for data of this kind.

Estimated maturities of long-term debt for the next five years are $27.5 million, $34.1 million, $6.6 million, $1.4 million, and $347 million, respectively.

The $7.5 million medium-term notes, 6.76% series, due 2027 contain a put feature at the discretion of the bondholder on one date only in 2007. If the bondholder does not exercise the put on that date, the notes mature in 2027. If the bondholder exercises the put, the maturities of long-term debt for 2007 will total $35 million.

Note 7 Short-Term Debt

As discussed in Note 6, Southwest has a $300 million five-year credit facility, effective April 2006, of which $150 million has been designated by management for working capital purposes (and related outstanding amounts are designated as short-term debt). No short-term borrowings were

outstanding on the credit facility at December 31, 2006. Short-term borrowings on the credit facility were $24 million at December 31, 2005. The weighted-average interest rate on these borrowings was 5.08 percent at December 31, 2005.

Note 8 Commitments and Contingencies

Legal and Regulatory Proceedings. The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In May 2005, a leaking natural gas line was involved in a fire that severely injured an individual. By December 2005, the Company had recorded a total liability related to this incident equal to the Company’s maximum self-insured retention level for the policy year August 2004 to July 2005 of $11 million. In the fourth quarter of 2006, the case was settled. The amount of the settlement that exceeded $11 million was covered by insurance. The Company’s current insurance contracts limit

the self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million.

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 subject will have a material adverse impact on its financial position or results of operations.

Southwest Gas Corporation

Note 9 Pension and Other Postretirement Benefits

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.

In September 2006, the FASB issued SFAS No. 158, which requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in their balance sheets. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in accumulated other comprehensive income under stockholders’ equity, net of tax, until they are amortized as a component of

net periodic benefit cost. SFAS No. 158 does not change how net periodic pension and postretirement costs are accounted for and reported in the income statement. The Company adopted the provisions of SFAS No. 158 effective December 31, 2006.

In accordance with SFAS No. 71, 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. The following table discloses the incremental effect of applying the provisions of SFAS No. 158 (and SFAS No. 71) to individual line items in the balance sheet as of December 31, 2006.


	Before Application of SFAS No. 158 *			SFAS No. 158 Adjustments			SFAS No. 71 Regulatory Adjustments		Adjusted Balance **
(Thousands of dollars)
Assets
Deferred charges and other assets	$	101,712		$	—		$	77,283	$	178,995
Total assets		3,407,682			—			77,283		3,484,965

Capitalization and Liabilities
Accumulated other comprehensive income (loss), net		(8,598	)		(52,983	)		47,915		(13,666	)
Total equity		906,493			(52,983	)		47,915		901,425
Total capitalization		2,292,847			(52,983	)		47,915		2,287,779
Current liabilities:
Deferred income taxes		16,383			(912	)		—		15,471
Other current liabilities		53,501			2,400			—		55,901
Total current liabilities		494,576			1,488			—		496,064
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits		310,686			(31,561	)		29,368		308,493
Other deferred credits		178,622			83,056			—		261,678
Total deferred income taxes and other credits		620,259			51,495			29,368		701,122
Total capitalization and liabilities	$	3,407,682		$	—		$	77,283	$	3,484,965

*	Balances before application of SFAS No. 158 include the effects of 2006 plan experience and changes in actuarial assumptions on the additional minimum liability, coupled with the regulatory impacts of SFAS No. 71.

**	At December 31, 2006, the combined net funded status of the three plans reflected a liability of $155 million. Of this amount, approximately $101 million was offset with a regulatory asset.

The table below discloses net amounts recognized in accumulated other comprehensive income as a result of adopting the provisions of SFAS No. 158 (as impacted by SFAS No. 71) as of December 31, 2006. Tax amounts are calculated using a 38 percent rate.


	Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Adjustments to adopt SFAS No. 158:
Net actuarial loss, net of $44.9 million of tax	$	(73,323	)	$	(62,464	)	$	(8,045	)	$	(2,814	)
Net transition obligation, net of $2 million of tax		(3,225	)		—			—			(3,225	)
Prior service credit, net of $9,000 of tax		14			14			—			—
Reversal of additional minimum pension liability, net of $14.4 million of tax		23,551			16,432			7,119			—
Estimated amounts recoverable through rates, net of $29.4 million of tax		47,915			41,876			—			6,039

Total amounts recognized in accumulated other comprehensive income	$	(5,068	)	$	(4,142	)	$	(926	)	$	—

Southwest Gas Corporation

Note 9 Pension and Other Postretirement Benefits (Continued)

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 preserve 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. Rate of 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		58 to 70
Debt securities		32 to 38
Other		up to 5

The Company’s pension costs for these plans are affected by the amount 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.

SFAS No. 87 Employer’s Accounting for Pensions 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 currently available 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. The resulting rate is then rounded to the nearest 25 basis points.

Due to an increase in market interest rates for high-quality fixed-income investments, the Company raised the discount rate to 6.00% at December 31, 2006 from 5.75% at December 31, 2005. The weighted-average rate of compensation increase was raised to 3.75% from 3.30%. The Company maintained its asset return assumption for 2007 at 8.50%. These offsetting changes will not result in a significant change in pension expense for 2007.

Note 9 Pension and Other Postretirement Benefits (Continued)

The following tables set forth the retirement plan, SERP, and PBOP funded status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.


	2006
	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)	$	473,418		$	34,123		$	37,553
Service cost		16,284			211			854
Interest cost		26,805			1,893			2,118
Actuarial loss (gain)		(4,806	)		(207	)		(297	)
Benefits paid		(15,898	)		(2,363	)		(1,121	)

Benefit obligation at end of year (PBO/PBO/APBO)		495,803			33,657			39,107


Change in plan assets
Market value of plan assets at beginning of year		338,618			—			20,979
Actual return on plan assets		42,733			—			2,742
Employer contributions		23,253			2,363			1,107
Benefits paid		(15,898	)		(2,363	)		—

Market value of plan assets at end of year		388,706			—			24,828

Funded status at year end	$	(107,097	)	$	(33,657	)	$	(14,279	)


Weighted-average assumptions (benefit obligation)
Discount rate		6.00	%		6.00	%		6.00	%
Weighted-average rate of compensation increase		3.75	%		3.75	%		3.75	%

Asset Allocation
Equity securities		63	%					77	%
Debt securities		32	%					16	%
Other		5	%					7	%

Total		100	%		N/A			100	%

Southwest Gas Corporation

Note 9 Pension and Other Postretirement Benefits (Continued)


	2005
	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)	$	428,116		$	31,385		$	35,988
Service cost		15,787			223			837
Interest cost		25,327			1,811			2,115
Actuarial loss (gain)		17,842			2,963			103
Benefits paid		(13,654	)		(2,259	)		(1,490	)

Benefit obligation at end of year (PBO/PBO/APBO)		473,418			34,123			37,553


Change in plan assets
Market value of plan assets at beginning of year		318,664			—			18,750
Actual return on plan assets		15,988			—			1,102
Employer contributions		17,620			2,259			1,127
Benefits paid		(13,654	)		(2,259	)		—

Market value of plan assets at end of year		338,618			—			20,979

Funded status		(134,800	)		(34,123	)		(16,574	)
Unrecognized net actuarial loss (gain)		123,028			14,428			5,954
Unrecognized transition obligation (2012)		—			—			6,069
Unrecognized prior service cost		(34	)		9			—

Prepaid (accrued) benefit cost	$	(11,806	)	$	(19,686	)	$	(4,551	)

Accrued benefit liability	$	(66,082	)	$	(32,580	)	$	(4,551	)
Additional minimum pension liability adjustment		54,276			12,894			—

	$	(11,806	)	$	(19,686	)	$	(4,551	)


Weighted-average assumptions (benefit obligation)
Discount rate		5.75	%		5.75	%		5.75	%
Weighted-average rate of compensation increase		3.30	%		3.30	%		3.30	%

Asset Allocation
Equity securities		61	%					71	%
Debt securities		30	%					15	%
Other		9	%					14	%

Total		100	%		N/A			100	%

Estimated funding for the plans above during calendar year 2007 is approximately $24 million. The accumulated benefit obligation for the retirement plan was $422 million and $405 million, and for the SERP was $32.2 million and $32.6 million at December 31, 2006 and 2005, respectively.

Pension benefits expected to be paid for each of the next five years beginning with 2007 are the following: $16.8 million, $18 million, $19.2 million, $20.6 million, and $22.2 million. Pension benefits expected to be paid during 2012 to 2016 total $138 million. Retiree welfare benefits expected to be paid for each of the next five years beginning with 2007 are the following: $1.4 million, $1.5 million, $1.6 million, $1.7 million, and $1.8 million. Retiree welfare benefits expected to be paid during 2012 to 2016 total $10.5 million. SERP benefits

expected to be paid for each of the next five years beginning with 2007 are the following: $2.4 million, $2.5 million, $2.5 million, $2.5 million, and $2.5 million. SERP benefits expected to be paid during 2012 to 2016 total $12.6 million. No assurance can be made that actual funding and benefits paid will match our estimates.

For PBOP measurement purposes, the per capita cost of covered health care benefits is assumed to increase five percent annually. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. The assumed annual rate of increase noted above applies to the benefit obligations of pre-1989 retirees only.

Southwest Gas Corporation

Note 9 Pension and Other Postretirement Benefits (Continued)

Components of net periodic benefit cost:


	Qualified Retirement Plan									SERP									PBOP
	2006			2005			2004			2006			2005			2004			2006			2005			2004
(Thousands of dollars)
Service cost	$	16,284		$	15,787		$	13,790		$	211		$	223		$	211		$	854		$	837		$	722
Interest cost		26,805			25,327			23,659			1,893			1,811			1,745			2,118			2,115			2,180
Expected return on plan assets		(30,608	)		(29,553	)		(28,067	)		—			—			—			(1,817	)		(1,675	)		(1,426	)
Amortization of prior service costs (credits)		(11	)		(11	)		54			9			116			140			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			867			867
Amortization of net loss		5,352			2,453			—			1,244			912			639			168			136			213

Net periodic benefit cost	$	17,822		$	14,003		$	9,436		$	3,357		$	3,062		$	2,735		$	2,190		$	2,280		$	2,556

Weighted-average assumptions (net benefit cost)
Discount rate		5.75	%		6.00	%		6.50	%		5.75	%		6.00	%		6.50	%		5.75	%		6.00	%		6.50	%
Expected return on plan assets		8.50	%		8.75	%		8.75	%		8.50	%		8.75	%		8.75	%		8.50	%		8.75	%		8.75	%
Weighted-average rate of compensation increase		3.30	%		4.00	%		4.25	%		3.30	%		4.00	%		4.25	%		3.30	%		4.00	%		4.25	%

The estimated net loss that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year is $5 million for the qualified retirement plan and $1.1 million for the SERP. The estimated transition obligation for the PBOP that will be amortized from regulatory assets into net periodic benefit cost over the next year is $870,000. The estimated prior service costs (credits) for the qualified retirement plan and SERP and the estimated net loss for the PBOP that will be amortized over the next year are not significant.

The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is three percent of an employee’s annual compensation. The cost of the plan was

$3.6 million in 2006, $3.5 million in 2005, and $3.5 million in 2004. NPL has a separate plan, the cost and liability for which are not significant.

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

Southwest Gas Corporation

Note 10 Stock-Based Compensation

At December 31, 2006, the Company had two stock-based compensation plans: a stock option plan and a performance share stock plan. Prior to January 1, 2006, these plans were accounted for in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payment”, using the modified prospective transition method. Accordingly, financial information for prior periods has not been restated. The adoption of SFAS No. 123 (revised 2004) did not have a material impact on the Company’s financial condition, results of operations, or cash flows. Under the modified prospective transition method, expense is recognized for any new awards granted after the effective date and for the unvested portion of awards granted prior to the effective date.

Under the option plan, the Company may grant 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. 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 options vest 40 percent at the end of year one and 30 percent at the end of years two and three. The grant date fair value of the options was estimated using the Black-Scholes option pricing model in 2006 and 2005 and the extended binomial option pricing model in 2004. The following assumptions were used in the valuation calculation:


	2006		2005		2004
Dividend yield	2.48 to 2.82	%	3.14 to 3.28	%	3.50	%
Risk-free interest rate range	4.91 to 5.06	%	3.88 to 4.09	%	1.66 to 3.23	%
Expected volatility range	15	%	18	%	13 to 20	%
Expected life	6 years		6 years		1 to 3 years

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


	2006				2005				2004
	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	1,475		$	23.70	1,646		$	22.46	1,502		$	21.83
Granted during the year	252			32.60	347			26.00	403			23.36
Exercised during the year	(749	)		23.30	(510	)		21.28	(254	)		20.21
Forfeited during the year	(6	)		26.81	(8	)		22.41	(5	)		21.83
Expired during the year	(15	)		28.09	—			—	—			—

Outstanding at year end	957		$	26.26	1,475		$	23.70	1,646		$	22.46

Exercisable at year end	413		$	23.31	813		$	23.06	1,010		$	22.36

Southwest Gas Corporation

Note 10 Stock-Based Compensation (Continued)

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 options was $11.6 million, $4.3 million, and $5.3 million at December 31, 2006, December 31, 2005, and December 31, 2004, respectively. The aggregate intrinsic value of exercisable options was $6.2 million, $3 million, and $3.6 million at December 31, 2006, December 31, 2005, and December 31, 2004, respectively. The aggregate intrinsic value of exercised options was $11.3 million, $2.6 million, and $1.3 million during 2006, 2005, and 2004, respectively. The market value of Southwest Gas stock was $38.37, $26.40, and

$25.40 at December 31, 2006, December 31, 2005, and December 31, 2004, respectively.

The weighted-average remaining contractual life for outstanding options was 7.7 years for 2006. The weighted-average remaining contractual life for exercisable options was 6.4 years for 2006. The weighted-average grant-date fair value of options granted was $5.92 for 2006, $4.18 for 2005, and $1.65 for 2004. The following table summarizes information about stock options outstanding at December 31, 2006 (thousands of options):


	Options Outstanding				Options Exercisable
Range of Exercise Price	Number outstanding	Weighted- average remaining contractual life	Weighted- average exercise price		Number exercisable	Weighted- average exercise price
$15.00 to $19.13	26	2.7 Years	$	18.13	26	$	18.13
$20.49 to $26.10	664	7.4 Years	$	24.12	368	$	23.36
$28.75 to $33.07	267	9.0 Years	$	32.38	19	$	29.14

As of December 31, 2006, there was $1.5 million of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a period of 3 years. The total fair value of options vested was $1 million, $609,000, and $917,000 during 2006, 2005, and 2004,

respectively. The Company received $17.5 million in cash from the exercise of options during 2006 and a corresponding tax benefit of $2.6 million which was recorded in additional paid-in capital. The following table summarizes the status of the Company’s nonvested options as of December 31, 2006 (thousands of options):


	Number of options		Weighted- average grant date fair value
Nonvested at the beginning of the year	662		$	3.00
Granted	252		$	5.92
Vested	(364	)	$	2.80
Forfeited	(6	)	$	4.15

Nonvested at December 31, 2006	544		$	4.47

In addition to the option 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 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 following table summarizes the activity of this plan (thousands of shares):


Year Ended December 31,	2006			2005			2004
Nonvested performance shares at beginning of year		357			316			381
Performance shares granted (including dividends)		95			143			156
Performance shares forfeited		—			(6	)		—
Shares vested and issued*		(133	)		(96	)		(221	)

Nonvested performance shares at end of year		319			357			316

Average grant date fair value of awards granted this year	$	26.97		$	24.71		$	22.70

*	Includes shares converted for taxes and retiree payouts.

Southwest Gas Corporation

Note 11 Income Taxes

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


Year Ended December 31,	2006		2005		2004
Current:
Federal	$	29,916	$	553	$	(225	)
State		4,830		2,218		(1,186	)

		34,746		2,771		(1,411	)

Deferred:
Federal		9,385		21,301		28,607
State		366		540		3,041

		9,751		21,841		31,648

Total income tax expense	$	44,497	$	24,612	$	30,237

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


Year Ended December 31,	2006			2005			2004
Deferred federal and state:
Property-related items	$	28,372		$	(3,143	)	$	(3,165	)
Purchased gas cost adjustments		(22,188	)		28,094			34,923
Employee benefits		(3,223	)		2,232			240
Injuries and damages reserves		4,543			(4,072	)		190
All other deferred		3,115			(402	)		328

Total deferred federal and state		10,619			22,709			32,516
Deferred ITC, net		(868	)		(868	)		(868	)

Total deferred income tax expense	$	9,751		$	21,841		$	31,648

The consolidated effective income tax rate for the period ended December 31, 2006 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,	2006		2005		2004
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Net state taxes	2.5		2.7		2.8
Property-related items	0.6		1.1		0.8
Effect of closed tax years and resolved issues	(1.3	)	—		(1.8	)
Tax credits	(0.7	)	(1.3	)	(1.0	)
Corporate owned life insurance	(0.9	)	(1.6	)	(0.7	)
All other differences	(0.5	)	0.1		(0.3	)

Consolidated effective income tax rate	34.7	%	36.0	%	34.8	%

Southwest Gas Corporation

Note 11 Income Taxes (Continued)

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


December 31,	2006		2005
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	6,427	$	6,964
Employee benefits		36,542		50,468
Alternative minimum tax		36,820		28,903
Net operating losses & credits		—		37,976
Other		4,549		10,510
Valuation allowance		—		—

		84,338		134,821

Deferred tax liabilities:
Property-related items, including accelerated depreciation		330,308		337,234
Regulatory balancing accounts		46,207		68,395
Property-related items previously flowed through		8,272		9,411
Unamortized ITC		10,330		11,198
Debt-related costs		5,681		6,292
Other		7,504		5,196

		408,302		437,726

Net deferred tax liabilities	$	323,964	$	302,905

Current	$	15,471	$	68,166
Noncurrent		308,493		234,739

Net deferred tax liabilities	$	323,964	$	302,905

Southwest Gas Corporation

Note 12 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, transporting, and distributing natural gas. Revenues are generated from the sale and transportation of natural gas. The construction services segment is engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

The accounting policies of the reported segments are the same as those described within Note 1—Summary of Significant

Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2006 and 2005, accounts receivable for these services totaled $9.2 million and $8.2 million, respectively, which were not eliminated during consolidation.

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, 2006 is as follows (thousands of dollars):


2006	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,727,394	$	216,753				$	1,944,147
Intersegment sales		—		80,611					80,611

Total	$	1,727,394	$	297,364				$	2,024,758

Interest expense	$	93,291	$	1,686				$	94,977

Depreciation and amortization	$	146,654	$	22,310				$	168,964

Income tax expense	$	36,240	$	8,257				$	44,497

Segment income	$	71,473	$	12,387				$	83,860

Segment assets	$	3,352,074	$	136,654	$	(3,763	)	$	3,484,965

Capital expenditures	$	305,914	$	39,411				$	345,325


2005	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,455,257	$	187,249				$	1,642,506
Intersegment sales		—		71,777					71,777

Total	$	1,455,257	$	259,026				$	1,714,283

Interest expense	$	89,318	$	1,009				$	90,327

Depreciation and amortization	$	137,981	$	18,272				$	156,253

Income tax expense	$	17,767	$	6,845				$	24,612

Segment income	$	33,670	$	10,153				$	43,823

Segment assets	$	3,103,804	$	128,181	$	(3,559	)	$	3,228,426

Capital expenditures	$	258,547	$	35,822				$	294,369


2004	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,262,052	$	153,392				$	1,415,444
Intersegment sales		—		61,616					61,616

Total	$	1,262,052	$	215,008				$	1,477,060

Interest expense	$	85,861	$	645				$	86,506

Depreciation and amortization	$	130,515	$	15,503				$	146,018

Income tax expense	$	24,698	$	5,539				$	30,237

Segment income	$	48,354	$	8,421				$	56,775

Segment assets	$	2,843,199	$	99,120	$	(4,203	)	$	2,938,116

Capital expenditures	$	274,748	$	27,940				$	302,688

(a)

Construction services segment assets include deferred tax assets of $3 million and income taxes payable of $758,000 in 2006, which were netted against gas operations segment deferred tax liabilities and income taxes receivable, net during consolidation and deferred tax assets of $3.6 million and $4.2 million in 2005 and 2004, respectively, which were netted against gas operations segment deferred tax liabilities during consolidation.

Southwest Gas Corporation

Note 13 Quarterly Financial Data (Unaudited)


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

2006
Operating revenues	$	676,941	$	430,902		$	351,800		$	565,115
Operating income (loss)		89,325		25,236			3,197			91,424
Net income (loss)		44,180		3,709			(10,736	)		46,707
Basic earnings (loss) per common share*		1.12		0.09			(0.26	)		1.12
Diluted earnings (loss) per common share*		1.11		0.09			(0.26	)		1.11

2005
Operating revenues	$	542,880	$	361,130		$	313,278		$	496,995
Operating income (loss)		72,849		14,935			(5,459	)		68,323
Net income (loss)		32,829		(2,817	)		(16,444	)		30,255
Basic earnings (loss) per common share*		0.88		(0.07	)		(0.43	)		0.77
Diluted earnings (loss) per common share*		0.88		(0.07	)		(0.43	)		0.76

2004
Operating revenues	$	473,400	$	278,697		$	264,467		$	460,496
Operating income (loss)		85,802		5,954			(9,017	)		87,028
Net income (loss)		41,044		(8,362	)		(16,353	)		40,446
Basic earnings (loss) per common share*		1.19		(0.24	)		(0.46	)		1.12
Diluted earnings (loss) per common share*		1.18		(0.24	)		(0.46	)		1.11

*	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

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, 2006. Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 28, 2007

Southwest Gas Corporation

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Corporation

We have completed integrated audits of Southwest Gas Corporation’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of stockholders’ equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 and Note 9 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation and defined benefit postretirement plans in 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria

established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

/s/ PRICEWATERHOUSECOOPERS LLP

Los Angeles, California

February 28, 2007

List of Subsidiaries of Southwest Corporation

Exhibit 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2006


SUBSIDIARY NAME		STATE OF INCORPORATION OR ORGANIZATION TYPE

Paiute Pipeline Company		Nevada

Northern Pipeline Construction Co.		Nevada

Southwest Gas Transmission Company		Partnership between Southwest Gas Corporation and Utility Financial Corp.

Southwest Gas Capital II, III, IV		Delaware

Utility Financial Corp.		Nevada

Black Mountain Gas Company		Minnesota

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 (Nos. 333-134040 and 333-106419) and Form S-8 (Nos. 333-126736, 333-106762 and 333-31223) of Southwest Gas Corporation of our report dated February 28, 2007 relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is incorporated in this Annual Report on Form 10-K.

PricewaterhouseCoopers LLP

Los Angeles, California

February 28, 2007

Section 302 Certifications

Exhibit 31.01

Certification on Form 10-K

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.

Certification on Form 10-K

I, George C. Biehl, 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.

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, 2006 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.

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, 2006 as filed with the Securities and Exchange Commission (the “Report”), I, George C. Biehl, Executive Vice President, Chief Financial Officer and Corporate Secretary 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.

Date: February 28, 2007

/S/ JEFFREY W. SHAW

Jeffrey W. Shaw

Chief Executive Officer

Southwest Gas Corporation