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Southwest Gas Corporation Form 10-K for period ending 12/31/2005

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, 2005

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 x 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 x

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 x No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 x		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 x

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

$976,113,313 as of June 30, 2005

The number of shares outstanding of common stock:

Common Stock, $1 Par Value, 39,557,464 shares as of March 1, 2006

DOCUMENTS INCORPORATED BY REFERENCE


Description		Part Into Which Incorporated
Annual Report to Shareholders for the Year Ended December 31, 2005		Parts I, II, and IV
2006 Proxy Statement		Part III

TABLE OF CONTENTS


		PAGE
	PART 1
Item 1.	BUSINESS	1

	Natural Gas Operations	1

	General Description	1

	Rates and Regulation	2

	Demand for Natural Gas	3

	Natural Gas Supply	3

	Competition	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 AND EXECUTIVE OFFICERS OF THE REGISTRANT	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	15

Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	15

	PART IV

Item 15.	EXHIBITS AND 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 and transporter 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 11 of the Notes to Consolidated Financial Statements, which is included in the 2005 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, 2005, Southwest purchased, transported, and distributed natural gas to 1,713,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. There were 100,000 customers added to the system during 2005 (including 19,000 customers associated with the purchase of the South Lake Tahoe natural gas distribution properties of Avista Corporation (“Avista”) in April 2005).

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, 2005	86%	5%	9%
December 31, 2004	86%	5%	9%
December 31, 2003	84%	6%	10%

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

Transportation of customer-secured gas to end-users accounted for 51 percent of total system throughput in 2005. Customers who utilized this service transported 127 million dekatherms in 2005, 126 million dekatherms in 2004, and 134 million dekatherms in 2003. 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). In April 2005, Southwest purchased the Avista natural gas distribution properties in South Lake Tahoe. Prior to this acquisition, Avista also was an LDC transporting on the Paiute system.

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, preferred securities distributions, 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 (“PGA”) 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 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. Previously, the Nevada Administrative Code required at least an annual filing to adjust for changes in purchased gas costs. Nevada Senate Bill No. 238, effective October 2005, provides for quarterly gas cost adjustments, calculated on a twelve-month rolling average. These adjustments will be 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 anticipates filing its first quarterly adjustment in mid-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 and deferred energy filings is included in the Rates and Regulatory Proceedings section of Management’s Discussion and Analysis (“MD&A”) in the 2005 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 2005	Pending

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 curtailment 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 2005, Southwest acquired gas supplies from 53 suppliers. Southwest constantly 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 insure 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 71 cents per therm in 2005. During 2005, prices increased to record levels, particularly following the occurrences of Hurricanes Katrina and Rita during the third quarter, which caused supply interruptions and damaged natural gas production facilities in the U.S. Gulf of Mexico. Increased demand from recently constructed natural gas-fueled electric generating plants has also affected the price of natural gas. Prices are generally expected to remain high through 2006. 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 normal weather supply needs for the 2005/2006 heating season were secured using short duration contracts (generally less than one year) which were put in place in 2004 and 2005 at fixed prices ranging from $5 to $9 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. At the end of 2005, prices for these supplies were generally higher than those in the Company’s existing fixed-price contracts.

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 arrangements noted above, but does not currently utilize other stand-alone derivative financial instruments for speculative purposes or for hedging. A hedging program utilizing stand-alone derivative instruments to mitigate price volatility is planned starting in 2006. The costs of such derivative financial instruments would be pursued as part of the PGA mechanisms upon approval by Southwest’s regulatory commissions for recovery from customers in each jurisdiction. None of the Company’s 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 continually 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 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 will extend capacity during winter months and provide greater flexibility in meeting monthly requirements. Rates under the new contract are not expected to differ significantly from those currently paid.

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, 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, 2005, the natural gas operations segment had 2,590 regular full-time equivalent employees. In March 2005, non-exempt employees in the Central Arizona Division of the Company voted to no longer be represented by any labor organization. On March 21, 2005, the Company received notification that the United States of America National Labor Relations Board had certified the voting results. As a result, none of the employees in the Company’s natural gas operations segment are now represented by a union. 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.

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 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 2005, approximately 92 percent of revenue was earned under unit-price contracts. As of December 31, 2005, 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 2005, NPL served 46 major customers, with Southwest accounting for approximately 28 percent of NPL revenues. With the exception of two other customers that in total accounted for approximately 25 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, 2005, NPL had 2,350 regular full-time equivalent employees. Employment peaked in November 2005 when there were 2,489 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.

Operations are conducted from 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 purchased gas adjustment clauses which permit us to file for rate adjustments to recover increases in the cost of purchased gas. Increases in the cost of purchased gas have no direct impact on our profit margins, but do affect cash flows and can therefore impact the amount of our capital resources. We have used short-term borrowings in the past to temporarily finance increases in purchased gas costs, and we expect to do so during 2006, 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 may reduce cash flow and earnings.

Governmental policies and regulatory actions can reduce our earnings.

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 will 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 2005, we added 81,000 customers (excluding 19,000 customers associated with the acquisition of the South Lake Tahoe gas distribution properties of Avista in April 2005), a five percent growth rate. Over the past ten years, customer growth has averaged five percent per year. This growth has required large amounts of capital to finance the investment in new transmission and distribution plant. In 2005, our natural gas construction expenditures totaled $259 million. Approximately 77 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 inadequate, and are expected to continue to be inadequate, 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 an 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. 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. The direction of interest rates is uncertain. 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. For the policy year August 2004 to July 2005, the self-insured retention amount associated with general liability claims increased from $1 million per incident to $1 million per incident plus payment of the first $10 million in aggregate claims above $1 million in the policy year. For the policy year August 2005 to July 2006, we entered into insurance contracts that limit our 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. See Item 3. Legal Proceedings in this report for information on an existing claim.

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

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, 2005 was $3.6 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.

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

With respect to the right-of-way grants, Southwest has had continuous and uninterrupted possession and use of all such rights-of-way, and the associated gas mains and service lines, commencing with the initial stages of 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

In May 2005, a leaking natural gas line was involved in a fire in a residence in Tucson, Arizona. An individual was severely injured. 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. A lawsuit was filed against the Company in December 2005 in the Superior Court for the State of Arizona, in and for the County of Pima (Case No. C20057063), in which $3.4 million in medical bills are claimed, $12 million in future medical expenses are claimed, and unspecified claims are made for general damages and punitive damages. Plaintiffs have claimed relief under theories of negligence, negligence per se, strict liability and loss of consortium and punitive damages. The Company has answered the complaint and denied liability. The complaint was amended in February 2006 to identify the parties to the litigation as Arnold Valenzuela, a single man, and Arturo and Julia Valenzuela, husband and wife, plaintiffs, and the Company as the sole defendant. If the Company was deemed fully or partially responsible, the Company estimates its exposure could be as much as $11 million (the maximum self-insured retention amount under its insurance policies). As of December 31, 2005, the Company has recorded an $11 million liability related to this incident.

The Company is named as a defendant in various other 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 future 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 AND EXECUTIVE OFFICERS OF THE REGISTRANT, 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 March 1, 2006, there were 23,049 holders of record of common stock, and the market price of the common stock was $28.77. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2005 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 2004 and 2005. The dividend of 20.5 cents per share has been paid quarterly since September 1994.

Item 6. SELECTED FINANCIAL DATA

Information required by this item is included in the 2005 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 2005 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 normal weather gas supply needs for the 2005/2006 heating season were secured using short duration fixed-price term contracts designed to mitigate price volatility. Fixed-price contracts for the 2005/2006 heating season range in price from approximately $5 to $9 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, which are subject to market fluctuations. At the end of 2005, prices for these supplies were generally higher than those in the Company’s existing fixed-price contracts. 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 contracts, for speculative purposes or for hedging. A hedging program utilizing stand-alone derivative instruments to mitigate price volatility is planned starting in 2006. 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 average 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 addition, Southwest filed an application in March 2005 requesting the PUCN to approve a weather normalization adjustment provision. In Arizona, Southwest’s requests for weather mitigation provisions 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 IDRBs are tracked and recovered from ratepayers through an interest balancing account. As of December 31, 2005 and 2004, the Company had $224 million and $250 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 $2.2 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 2005 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, 2005, 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 2005 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 60.

The Attestation Report of the Registered Public Accounting Firm required to be reported herein is incorporated by reference to the information reported in the 2005 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 61.

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 AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) Identification of Directors. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive 2006 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, 2005 are as follows:


Name	Age	Position	Period Position Held
Jeffrey W . Shaw	47	Chief Executive Officer	2004-Present
		President	2003-2004
		Senior Vice President/Gas Resources and Pricing	2002-2003
		Senior Vice President/Finance and Treasurer	2001-2002
James P. Kane	59	President	2004-Present
		Executive Vice President/Operations	2001-2004
George C. Biehl	58	Executive Vice President/Chief Financial Officer and
		Corporate Secretary	2001-Present
Edward A. Janov	51	Senior Vice President/Finance	2004-Present
		Vice President/Finance	2003-2004
		Vice President/Finance and Treasurer	2002-2003
		Vice President/Chief Accounting Officer	2001-2002
		Vice President/Controller and Chief Accounting Officer	2001
James F. Lowman	59	Senior Vice President/Operations	2005-Present *
		Senior Vice President/Central Arizona Division	2001-2005
Christina A. Palacios	60	Senior Vice President/Central Arizona Division	2005-Present
		Senior Vice President/Southern Arizona Division	2004-2005
		Vice President/Southern Arizona Division	2001-2004
Thomas R. Sheets	55	Senior Vice President/Legal Affairs and General Counsel	2001-Present
Dudley J. Sondeno	53	Senior Vice President/Chief Knowledge and
		Technology Officer	2001-Present
Roy R. Centrella	48	Vice President/Controller and Chief Accounting Officer	2002-Present
		Controller	2001-2002
		Assistant Controller	2001
Kenneth J. Kenny	43	Vice President/Treasurer	2005-Present
		Treasurer	2003-2005
		Assistant Treasurer/Director Financial Services	2001-2003

*	James F. Lowman will retire effective March 31, 2006.

(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 2006 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 2006 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 2006 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 2005, all but five reports were timely filed. Purchases of Company common stock by Terrence L. Wright, Director, consisting of 2,750 shares on December 22, 2005, were reported on January 6, 2006. The exercise of options and subsequent sale of Company common stock by Christina A. Palacios, Senior Vice President/Central Arizona Division, consisting of 1,300 options/shares on July 6, 2004 and 8,700 options/shares on July 7, 2004, were reported on March 22, 2005.

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 and Benefits” in the definitive 2006 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 2006 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 2006 Proxy Statement, which by this reference is incorporated herein.

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

At December 31, 2005, 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	1,475	$	23.70	280
Equity compensation plans not approved by security holders	—		—	—

Total	1,475	$	23.70	280

Pursuant to the terms of the management incentive plan, the Company may issue restricted stock in the form of 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	357	$	23.29	—
Equity compensation plans not approved by security holders	—		—	—

Total	357	$	23.29	—

Additional information regarding the two equity compensation plans is included in Note 9 of the Notes to Consolidated Financial Statements in the 2005 Annual Report to Shareholders.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

Item 14. PRINCIPAL ACCOUNTANT 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 2006 Proxy Statement, which by this reference is incorporated herein.

PART IV

Item 15. EXHIBITS AND 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 2005 Annual Report to Shareholders under the following captions:


Consolidated Balance Sheets		36
Consolidated Statements of Income		38
Consolidated Statements of Cash Flows		39
Consolidated Statements of Stockholders' Equity and Comprehensive Income		40
Notes to Consolidated Financial Statements		41
Management's Report on Internal Control Over Financial Reporting		60
Report of Independent Registered Public Accounting Firm		61

(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 April 22, 2004, between Southwest Gas Corporation and BNY Capital Markets, Inc. Incorporated herein by reference to the report on Form 8-K dated May 17, 2004.

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 10-Q for the quarter ended June 30, 2004.

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		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, September 30, 2001 and September 30, 2005, and the report on Form 8-K dated September 21, 2004.

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 September 30, 2001, and September 30, 2005, and the report on Form 8-K dated September 21, 2004.

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.

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.

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

13.01		Portions of 2005 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: March 9, 2006	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	March 9, 2006

/s/ THOMAS E. CHESTNUT (Thomas E. Chestnut)	Director	March 9, 2006

/s/ MANUEL J. CORTEZ (Manuel J. Cortez)	Director	March 9, 2006

/s/ RICHARD M. GARDNER (Richard M. Gardner)	Director	March 9, 2006

/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.)	Director	March 9, 2006

/s/ THOMAS Y. HARTLEY (Thomas Y. Hartley)	Chairman of the Board of Directors	March 9, 2006

/s/ JAMES J. KROPID (James J. Kropid)	Director	March 9, 2006

/s/ MICHAEL O. MAFFIE (Michael O. Maffie)	Director	March 9, 2006

/s/ MICHAEL J. MELARKEY (Michael J. Melarkey)	Director	March 9, 2006

/s/ JEFFREY W. SHAW (Jeffrey W. Shaw)	Director and Chief Executive Officer	March 9, 2006

/s/ CAROLYN M. SPARKS (Carolyn M. Sparks)	Director	March 9, 2006

/s/ TERRENCE L. WRIGHT (Terrence L. Wright)	Director	March 9, 2006

/s/ ROY R. CENTRELLA (Roy R. Centrella)	Vice President, Controller, and Chief Accounting Officer	March 9, 2006

EXHIBIT INDEX


Exhibit Number		Description of Document
12.01		Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation.

13.01		Portions of 2005 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.

Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corp.

Exhibit 12.01

SOUTHWEST GAS CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Thousands of dollars)


	For the Year Ended December 31,
	2005		2004		2003		2002		2001
Continuing operations
1. Fixed charges:
A) Interest expense	$	87,687	$	84,138	$	78,724	$	79,586	$	80,139
B) Amortization		3,700		3,059		2,752		2,278		1,886
C) Interest portion of rentals		6,333		6,779		6,665		8,846		9,346
D) Preferred securities distributions		—		—		4,015		5,475		5,475

Total fixed charges	$	97,720	$	93,976	$	92,156	$	96,185	$	96,846

2. Earnings (as defined):
E) Pretax income from continuing operations	$	68,435	$	87,012	$	55,384	$	65,382	$	56,741
Fixed Charges (1. above)		97,720		93,976		92,156		96,185		96,846

Total earnings as defined	$	166,155	$	180,988	$	147,540	$	161,567	$	153,587

3. Ratio of earnings to fixed charges		1.70		1.93		1.60		1.68		1.59

Portions of 2005 Annual Report incorporated by reference to the Form 10-K

Exhibit 13.01

Consolidated Selected Financial Statistics


Year Ended December 31,		2005			2004			2003			2002			2001
(Thousands of dollars, except per share amounts)
Operating revenues	$	1,714,283		$	1,477,060		$	1,231,004		$	1,320,909		$	1,396,688
Operating expenses		1,563,635			1,307,293			1,095,899			1,174,410			1,262,705

Operating income	$	150,648		$	169,767		$	135,105		$	146,499		$	133,983

Net income	$	43,823		$	56,775		$	38,502		$	43,965		$	37,156

Total assets at year end	$	3,228,426		$	2,938,116		$	2,608,106		$	2,432,928		$	2,369,612

Capitalization at year end
Common equity	$	751,135		$	705,676		$	630,467		$	596,167		$	561,200
Mandatorily redeemable preferred trust securities		–			–			–			60,000			60,000
Subordinated debentures		100,000			100,000			100,000			–			–
Long-term debt		1,224,898			1,162,936			1,121,164			1,092,148			796,351

	$	2,076,033		$	1,968,612		$	1,851,631		$	1,748,315		$	1,417,551

Common stock data
Return on average common equity		5.9	%		8.5	%		6.3	%		7.5	%		6.8	%
Earnings per share	$	1.15		$	1.61		$	1.14		$	1.33		$	1.16
Diluted earnings per share	$	1.14		$	1.60		$	1.13		$	1.32		$	1.15
Dividends paid per share	$	0.82		$	0.82		$	0.82		$	0.82		$	0.82
Payout ratio		71	%		51	%		72	%		62	%		71	%
Book value per share at year end	$	19.10		$	19.18		$	18.42		$	17.91		$	17.27
Market value per share at year end	$	26.40		$	25.40		$	22.45		$	23.45		$	22.35
Market value per share to book value per share		138	%		132	%		122	%		131	%		129	%
Common shares outstanding at year end (000)		39,328			36,794			34,232			33,289			32,493
Number of common shareholders at year end		23,571			23,743			22,616			22,119			23,243
Ratio of earnings to fixed charges		1.70			1.93			1.60			1.68			1.59

Natural Gas Operations


Year Ended December 31,		2005			2004			2003			2002			2001
(Thousands of dollars)
Sales	$	1,401,329		$	1,211,019		$	984,966		$	1,069,917		$	1,149,918
Transportation		53,928			51,033			49,387			45,983			43,184

Operating revenue		1,455,257			1,262,052			1,034,353			1,115,900			1,193,102
Net cost of gas sold		828,131			645,766			482,503			563,379			677,547

Operating margin		627,126			616,286			551,850			552,521			515,555
Expenses
Operations and maintenance		314,437			290,800			266,862			264,188			253,026
Depreciation and amortization		137,981			130,515			120,791			115,175			104,498
Taxes other than income taxes		39,040			37,669			35,910			34,565			32,780

Operating income	$	135,668		$	157,302		$	128,287		$	138,593		$	125,251

Contribution to consolidated net income	$	33,670		$	48,354		$	34,211		$	39,228		$	32,626

Total assets at year end	$	3,103,804		$	2,843,199		$	2,528,332		$	2,345,407		$	2,289,111

Net gas plant at year end	$	2,489,147		$	2,335,992		$	2,175,736		$	2,034,459		$	1,825,571

Construction expenditures and property additions	$	258,547		$	274,748		$	228,288		$	263,576		$	248,352

Cash flow, net
From operating activities	$	214,036		$	124,135		$	187,122		$	281,329		$	103,848
From investing activities		(254,120	)		(272,458	)		(249,300	)		(243,373	)		(246,462	)
From financing activities		57,763			143,086			60,815			(49,187	)		154,727

Net change in cash	$	17,679		$	(5,237	)	$	(1,363	)	$	(11,231	)	$	12,113

Total throughput (thousands of therms)
Residential		650,465			667,174			593,048			588,215			589,943
Small commercial		300,072			303,844			279,154			280,271			279,965
Large commercial		111,839			104,899			100,422			121,500			107,583
Industrial/Other		156,542			163,856			157,305			224,055			283,772
Transportation		1,273,964			1,258,265			1,336,901			1,325,149			1,268,203

Total throughput		2,492,882			2,498,038			2,466,830			2,539,190			2,529,466

Weighted average cost of gas purchased ($/therm)	$	0.71		$	0.57		$	0.46		$	0.38		$	0.55
Customers at year end		1,713,000			1,613,000			1,531,000			1,455,000			1,397,000
Employees at year end		2,590			2,548			2,550			2,546			2,507
Degree days – actual		1,735			1,953			1,772			1,912			1,963
Degree days – ten-year average		1,956			1,913			1,931			1,963			1,970

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

Executive Summary

The following discussion of Southwest Gas Corporation and subsidiaries (the “Company”) includes information related to regulated natural gas transmission and distribution activities and non-regulated activities.

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 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 and transporter 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.

Consolidated Results of Operations


Year ended December 31,		2005		2004		2003
(Thousands of dollars, except per share amounts)
Contribution to net income
Natural gas operations	$	33,670	$	48,354	$	34,211
Construction services		10,153		8,421		4,291

Net income	$	43,823	$	56,775	$	38,502

Basic earnings per share
Natural gas operations	$	0.88	$	1.37	$	1.01
Construction services		0.27		0.24		0.13

Consolidated	$	1.15	$	1.61	$	1.14

Consolidated results of operations declined in 2005 compared to 2004. There were two principal factors contributing to the decline. The gas distribution segment experienced much warmer-than-normal temperatures during 2005 which unfavorably impacted operating margin between periods and operating expenses in 2005 included a $10 million nonrecurring charge related to an injuries and damages incident (more fully described in Capital Resources and Liquidity – Insurance Coverage below). These unfavorable variances were partly offset by an improved contribution from the Company’s construction services segment.

See separate discussions at Results of Natural Gas Operations and Results of Construction Services. Average shares outstanding increased by 2.9 million between 2005 and 2004, and 1.4 million between 2004 and 2003, primarily resulting from at-the-market offerings through the Equity Shelf Program and continuing issuances under the Company’s various stock plans. The Equity Shelf Program was fully issued as of September 30, 2005. See separate discussion at Capital Resources and Liquidity.

As reflected in the table above, the natural gas operations segment accounted for an average of 84 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

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. General rate relief in California and Nevada provided an $8 million increase in margin during 2005 when compared to 2004. Of equal importance, improvements in rate design have mitigated the impacts of weather and conservation on margin volatility for nearly half of Southwest’s business. (See the section on Rates and Regulatory Proceedings for additional information). 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.

In February 2006, the Arizona Corporation Commission (“ACC”) rendered a decision that increased rates in Arizona by $49.3 million. See the section on Rates and Regulatory Proceedings for additional information.

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 during these months, have a significant impact on the margin and associated net income of the Company. Warm temperatures in 2005, compared with the more normal temperatures experienced in 2004, resulted in a $17 million decrease in margin between years. Much of this variance occurred in the Company’s Arizona service territories where rates are highly leveraged and, therefore, operating margin is highly susceptible to variances in usage due to weather.

Customer Growth. As of December 31, 2005, Southwest had 1,713,000 residential, commercial, industrial, and other natural gas customers, of which 930,000 customers were located in Arizona, 613,000 in Nevada, and 170,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2005, Southwest added 81,000 customers (excluding 19,000 customers associated with the acquisition of the South Lake Tahoe gas distribution properties of Avista Corporation (“Avista”) in April 2005), a five percent increase, of which 40,000 customers were added in Arizona, 34,000 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, excluding acquisitions, is expected to be approximately five percent in 2006. During 2005, 52 percent of operating margin was earned in Arizona, 37 percent in Nevada, and 11 percent in California. During this same period, Southwest earned 86 percent of operating margin from residential and small commercial customers, 5 percent from other sales customers, and 9 percent from transportation customers. These general patterns are expected to continue.

Customer growth, excluding acquisitions, has averaged five percent annually over the past ten years and five percent annually during the past three years. Incremental margin ($20 million in 2005) has accompanied this customer growth, but the costs associated with creating and maintaining the infrastructure needed to accommodate these customers also have been significant. The timing of including these costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings.

Management has attempted to mitigate the regulatory lag associated with growth by being judicious in its staffing levels through the effective use of technology. During the past decade, while adding nearly 684,000 customers, Southwest only increased staffing levels by 210. During this same period, Southwest’s customer to

employee ratio has climbed from 432/1 to 661/1, one of the best in the industry. It has accomplished this without sacrificing service quality. Examples of technological improvements over the last few years include electronic order routing, an electronic mapping system and, most recently, a work management system. Over the next few years, Southwest plans to expand the use of electronic meter reading technology to achieve additional efficiencies.

Management has also attempted to mitigate the regulatory lag associated with growth by seizing strategic growth opportunities. For example, in April 2005, the Company purchased the natural gas distribution properties of Avista in South Lake Tahoe, California, adding approximately 19,000 customers. Southwest already served the North Lake Tahoe area in Nevada, and was therefore able to efficiently assimilate the acquired property into its operations.

Customer growth requires significant capital outlays for new transmission and distribution plant. Necessary financing of activities supporting continued construction occurred during 2005. Industrial Development Revenue Bonds (“IDRBs”) are periodically issued by municipalities in the Company’s service territories on behalf of the Company to fund specific development projects. In October 2005, the Company issued $100 million in Clark County, Nevada IDRBs. The net proceeds from the 4.85% tax-exempt bonds are being used to expand and upgrade facilities in southern Nevada. The Company also issued 2.5 million shares of common stock through its various stock plans receiving $64.1 million in net proceeds in 2005. The Company expanded its $250 million credit facility to $300 million in April 2005. (See the section on 2005 Financing Activity for additional information.) In addition, in 2005, Southwest offset capital outlays by collecting approximately $25.6 million in net advances and contributions from 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. 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. While progress has been made in Nevada and California, in Arizona, where 54 percent of the Company’s customer base resides, the ACC has been slow to assist Company efforts to improve rate design.

Natural Gas Costs

In 2005, the net cost of gas sold increased 28 percent from the prior year due to higher natural gas prices. The price of natural gas has increased dramatically over the past several years. Since December 2004, prices have increased to record levels, particularly following the occurrences of Hurricanes Katrina and Rita during the third quarter of 2005 which caused supply interruptions and damaged natural gas production facilities in the U.S. Gulf of Mexico. Increased demand from recently constructed natural gas-fueled electric generating plants has also affected the price of natural gas. Natural gas prices are expected to remain high through 2006. Sustained high prices can result in increased under-collected PGA balances and thereby temporarily reduce operating cash flows until rate relief is granted to recover the higher costs. See the section on PGA Filings for additional information.

Results of Construction Services Operations

The Company’s construction subsidiary, NPL, increased its contribution to consolidated net income by $1.7 million in 2005 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 favorable equipment resale market in the current year.

The convergence of favorable factors that resulted in the 2005 increase in contribution from construction services may not be repeatable in future periods. The amount of work received under existing blanket contracts, the amount of bid work, and the equipment resale market vary from year-to-year.

Results of Natural Gas Operations


Year Ended December 31,		2005		2004		2003
(Thousands of dollars)
Gas operating revenues	$	1,455,257	$	1,262,052	$	1,034,353
Net cost of gas sold		828,131		645,766		482,503

Operating margin		627,126		616,286		551,850
Operations and maintenance expense		314,437		290,800		266,862
Depreciation and amortization		137,981		130,515		120,791
Taxes other than income taxes		39,040		37,669		35,910

Operating income		135,668		157,302		128,287
Other income (expense)		5,087		1,611		2,955
Net interest deductions		81,595		78,137		76,251
Net interest deductions on subordinated debentures		7,723		7,724		2,680
Preferred securities distributions		–		–		4,180

Income before income taxes		51,437		73,052		48,131
Income tax expense		17,767		24,698		13,920

Contribution to consolidated net income	$	33,670	$	48,354	$	34,211

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 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 where rates are highly leveraged, making operating margin highly susceptible to variances in usage due to weather. 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 reflects 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. The prior period 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 reflects 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. The current period also includes 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.

2004 vs. 2003

Contribution from natural gas operations increased $14.1 million in 2004 compared to 2003. The improvement was principally the result of higher operating margin partially offset by increased operating costs.

Operating margin increased $64 million in 2004 as compared to 2003. A record 82,000 customers were added during 2004, a growth rate of five percent. New customers contributed $21 million in incremental margin. A return to more normal temperatures in 2004 from the warm temperatures experienced in 2003 resulted in a $25 million increase in margin between years. Rate relief in California and Nevada provided $18 million.

Operations and maintenance expense increased $23.9 million, or nine percent, compared to 2003. The increase reflected general increases in labor and maintenance costs along with incremental operating expenses associated with serving additional customers. Additional factors included increases in insurance premiums, employee-related costs, and costs to develop energy efficient technology.

Depreciation expense and general taxes increased $11.5 million, or seven percent, as a result of construction activities. Average gas plant in service increased $249 million, or nine percent, as compared to 2003. The increase reflected ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.

Net financing costs rose $2.8 million, or three percent, between years primarily due to an increase in average debt outstanding to help finance growth, partially offset by a reduction in interest costs associated with the purchased gas adjustment (“PGA”) account balance.

During 2004, Southwest recognized $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. In 2003, Southwest recognized $2 million of income tax benefits associated with plant-related items.

Rates and Regulatory Proceedings

Arizona General Rate Case. In December 2004, Southwest filed a general rate application with the ACC for its Arizona rate jurisdiction. The application sought authorization to increase operating revenues by $70.8 million, and was subsequently reduced by Southwest to $66.9 million. The request was the result of increases in fixed operating costs and investment in infrastructure to serve new customers, coupled with a rate structure that has hindered Southwest’s ability to earn the return authorized by the ACC. The Company asked the ACC to restructure residential rates to separate the recovery of fixed operating costs from the volume of gas it sells and also proposed revising rates to shift a portion of the recovery of its fixed operating costs away from cold weather consumption. Southwest also requested a conservation tracker to mitigate margin volatility due to weather and other usage variations. In July 2005, the two primary intervening parties in the case, the ACC Staff and the Residential Utility Consumer Office (“RUCO”), filed testimony in the case. Both parties separately advocated revenue increases which approximated two-thirds of the amount filed for, although their positions on a number of matters differed. In addition, neither party supported all of Southwest’s proposed rate design changes or the balancing account mechanism. The hearing process was completed in October 2005. In February 2006, the ACC approved a $49.3 million increase in operating revenues, effective March 2006. The decision did not include 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 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.

California Attrition Filing. In October 2005, Southwest made its annual attrition filing requesting a $4.5 million increase in operating margin. The effective date of new rates was originally anticipated to be January 2006. The Office of Rate Payer Advocates (“ORA”) filed a protest to the attrition filing disagreeing with 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 Company expects a California Public Utilities Commission (“CPUC”) decision resolving this matter in the second quarter of 2006.

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 to be submitted by May 2006. Southwest expects the PUCN to issue guidelines during 2006 regarding the methodology to be used in any future mechanisms, which the Company could propose in its next general rate application.

FERC Jurisdiction. As a condition of the leased Liquified Natural Gas (“LNG”) facilities acquisition and settlement in 2004, Paiute filed a general rate case with the Federal Energy Regulatory Commission (“FERC”) in January 2005 to reestablish its transportation and storage rates. During the course of the negotiation of the LNG settlement, Paiute was able to secure long-term customer commitments for the full capacity of the LNG storage facility, based upon its representations to the storage customers that its storage service rates would be reduced by approximately 26 percent as a result of Paiute’s negotiated purchase price for the previously leased LNG facilities. In November 2005, the FERC approved an uncontested settlement that resolved all rate case related issues. The settlement rates were developed based on a pre-tax rate of return of 12.29%, which provides a return on equity of 11.80% based on a hypothetical capital structure with 45 percent equity. Under the settlement, Paiute’s authorized firm transportation revenue, including incrementally priced facilities, will decrease by approximately $300,000 per year and storage revenues will be reduced by approximately 28 percent, or $2.2 million per year. The new storage and transportation rates were implemented in March and August 2005, respectively, subject to refund. As a result of the rate case, in 2005 Paiute accrued $1.7 million for refunds to customers. These amounts were refunded in February 2006.

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


		2005		2004
Arizona	$	46.8	$	15.3
Northern Nevada		12.6		13.1
Southern Nevada		39.4		41.9
California		10.6		11.8

	$	109.4	$	82.1

Arizona PGA Filings. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. 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 to pass through higher costs of natural gas incurred during 2005. These changes will facilitate the recovery of the 2005 end-of-year under-recovered gas cost balance.

Nevada Deferred Energy Adjustment Filing. In May 2005, the Company made an annual filing for its southern and northern Nevada rate jurisdictions, pursuant to temporary regulations adopted by the PUCN during the same month. These regulations replaced the PGA provisions in the Company’s Nevada Gas Tariff. The PUCN issued an order in October 2005 approving a $62.3 million annual increase in southern Nevada and a $16 million annual increase in northern Nevada effective November 2005. The increases are based on projected gas costs and will amortize the current under-collected Nevada PGA balances.

The temporary regulations above will be affected by another purchased gas related proceeding, prompted by Nevada Senate Bill No. 238. Senate Bill No. 238, which became effective in October 2005, provides for quarterly gas cost adjustments calculated on a twelve-month rolling average. These adjustments will be 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 anticipates filing its first quarterly adjustment in mid-2006.

California Gas Incentive Mechanism. 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. As part of the CPUC’s decision in the Company’s last general rate case, Southwest was encouraged to propose a Gas Cost Incentive Mechanism (“GCIM”). A GCIM is designed to provide greater incentive to reduce gas costs than exists under traditional regulation, encourage reasonable risk taking, and reduce administrative burden.

In November 2004, the Company filed for a GCIM using attributes similar to those used by other California utilities. The plan provides for savings or penalties for gas costs incurred as compared to a predetermined range surrounding an established benchmark. Any savings or penalties outside the range, neither of which are expected to be significant, would then be shared on an annual basis by ratepayers and shareholders based upon an authorized percentage. The CPUC approved the GCIM, as proposed, effective May 2005. The Company made its first filing under the GCIM in January 2006. As expected, the amount of shared savings contained in the filing was not significant.

Other Filings

El Paso Transmission System. In June 2005, El Paso Natural Gas Company (“El Paso”) filed a general rate case application with the FERC. (Southwest is dependent upon El Paso for the transportation of natural gas for virtually all of its Arizona service territories and 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. It is estimated that the impact of the proposed rate increase will be an annual increase in gas transportation costs to Southwest of as much as $44 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 has been deferred to April 2006. It is anticipated that any additional costs to Southwest resulting from El Paso’s filing will be collected from customers through the PGA mechanism.

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.

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, 2005, total gas plant increased from $2.8 billion to $3.5 billion, or at an annual rate of eight percent. Customer growth was the primary reason for the plant increase as Southwest added 258,000 net new customers (including 19,000 customers acquired in the South Lake Tahoe area) during the three-year period.

During 2005, construction expenditures for the natural gas operations segment were $259 million (excluding the $15.2 million South Lake Tahoe acquisition in April 2005). Approximately 77 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 $183 million of the required capital resources pertaining to total capital expenditures in 2005. The remainder was provided from external financing activities and existing credit facilities. Operating cash flows in 2005 were negatively impacted by natural gas prices as under-collected PGA balances have increased from $82.1 million at December 31, 2004 to $109.4 million at December 31, 2005. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances.

Asset Purchases

In April 2005, the Company purchased the natural gas distribution properties of Avista in South Lake Tahoe, California, which included approximately 19,000 customers. The cash purchase price for the properties was $15.2 million, net of post-closing adjustments. The properties were integrated into the northern Nevada operations of Southwest, which include contiguous gas properties in the Lake Tahoe Basin. Southwest assumed the rates in effect at the time of closing the purchase. The purchase price was financed using existing credit facilities.

2005 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. In May 2004, $60 million of the available capacity was designated for issuance as common stock under an equity shelf program, (the “2004 Equity Shelf Program”). During 2005, approximately 1 million shares were issued under the 2004 Equity Shelf Program with gross proceeds of $25.9 million, agent commissions of $258,000, and net proceeds of $25.6 million. The 2004 Equity Shelf Program was fully issued as of September 30, 2005. At December 31, 2005, the Company had $140 million in securities available for issuance under the universal shelf registration statement.

During 2005, the Company issued approximately 1.5 million additional shares through its Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), Employees’ Investment Plan, Management Incentive Plan, and Stock Incentive Plan. In July 2005, the Company registered 750,000 additional shares of common stock with the SEC for issuance under the Employees’ Investment Plan.

In October 2005, the Company issued $100 million (unregistered securities) in Clark County, Nevada, 4.85% Series 2005A IDRBs. The IDRBs were issued at a discount of 0.75% and are due October 2035. At December 31, 2005, $24.6 million in proceeds from the new IDRBs remained in trust. The proceeds from the IDRBs are being used by Southwest to expand and upgrade facilities in Clark County, Nevada.

2006 Construction Expenditures and Financing

Southwest estimates construction expenditures during the three-year period ending December 31, 2008 will be approximately $778 million. Of this amount, approximately $284 million are expected to be incurred in 2006. 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 $117 million in long-term debt maturities over the three-year period. The Company expects to raise $75 million to $100 million from its various common stock programs. IDRB funds held in trust will provide $24.6 million. The remaining cash requirements are expected to be provided by other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest 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.

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. To date, the Company has not incurred any increased financing costs as a result of these covenants.

Contractual Obligations

Obligations under long-term debt, gas purchase obligations and significant non-cancelable operating leases at December 31, 2005 were as follows (millions of dollars):


		Payments due by period
Contractual Obligations		Total		2006		2007-2008		2009-2010		Thereafter
Short-term debt (Note 7)	$	24	$	24	$	–	$	–	$	–
Subordinated debentures to Southwest Gas Capital II (Note 5) ^(a)		391		8		15		15		353
Long-term debt (Note 6) ^(a)		2,324		154		191		283		1,696
Operating leases (Note 2)		37		6		10		6		15
Gas purchase obligations ^(b)		593		411		182		–		–
Pipeline capacity ^(c)		693		98		197		185		213
Other commitments		18		6		6		3		3

Total	$	4,080	$	707	$	601	$	492	$	2,280

(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 119 million dekatherms. Fixed price contracts range in price from $4.46 to $10.44 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 2006 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 capital resources and liquidity in future years include inflation, growth in Southwest’s service territories, changes in income tax laws, changes in the ratemaking policies of regulatory commissions, interest rates, variability of natural gas prices, and the level of Company earnings.

The price of natural gas has increased dramatically over the past several years. Since December 2004, prices have increased to record levels, particularly following the occurrences of Hurricanes Katrina and Rita during the third quarter of 2005 which caused supply interruptions and damaged natural gas production facilities in the U.S. Gulf of Mexico, and in December 2005 after the first substantial cold weather hit the United States. Increased demand from recently constructed natural gas-fueled electric generating plants has also affected the price of natural gas. Prices are generally expected to remain high through 2006.

Southwest periodically enters into fixed-price term contracts to mitigate price volatility. About half of Southwest’s normal weather supply needs for the 2005/2006 heating season were secured using short duration contracts (generally less than one year) which were put in place in 2004 and 2005 at fixed prices ranging from approximately $5 to $9 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, which is subject to market fluctuations. At the end of 2005, prices for these supplies were generally higher on average than those in the Company’s existing fixed-price contracts. Southwest does not currently utilize other stand-alone derivative financial instruments for speculative purposes, or for hedging. A hedging program utilizing stand-alone derivative instruments to mitigate price volatility is planned starting in 2006. The costs of such derivative financial instruments would be pursued for recovery from customers as part of the PGA mechanisms in each jurisdiction.

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, 2005, the combined balances in PGA accounts totaled an under-collection of $109 million versus an under-collection of $82 million at December 31, 2004. See PGA Filings for more information on recent regulatory filings. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances. Based on current and forecasted gas prices, Southwest expects its PGA balances to increase during the winter season as average purchase prices will likely exceed recovery rates.

PGA changes affect cash flows but have no direct impact on profit margin. 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. 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).

Effective April 2005, the Company replaced its $250 million credit facility, scheduled to expire in May 2007, with a $300 million facility that expires in April 2010. Of the $300 million, $150 million is available for working capital purposes and $150 million is designated long-term debt. 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 on the new credit facility is lower than the applicable margin of the previous facility. The Company currently believes the $150 million designated for working capital purposes is adequate to meet anticipated liquidity needs. At December 31, 2005, $24 million was outstanding on the short-term portion of the credit facility and $150 million was outstanding on the long-term portion.

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 2005. The dividend of 20.5 cents per share has been paid quarterly since September 1994.

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).

Since January 1997, Moody’s Investors Service, Inc. (“Moody’s”) has rated Company unsecured long-term debt at Baa2. Moody’s debt ratings range from Aaa (best quality) to C (lowest quality). Moody’s applies a Baa2 rating to obligations which are considered medium grade obligations (i.e., they are neither highly protected nor poorly secured).

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 increased from $1 million per incident to $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. The Company recorded a $1 million liability related to this incident during the third quarter of 2005 based on preliminary information available at the time. 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. The Company has answered the complaint and denied liability. If the Company was deemed fully or partially responsible, the Company estimates its exposure could be as much as $11 million (the maximum noted above). In December 2005, the Company increased the reserves related to this incident by $10 million, bringing the total liability to the Company’s maximum self-insured retention level of $11 million.

For the policy year August 2005 to July 2006, the Company entered into insurance contracts that limit the Company’s self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million.

Results of Construction Services


Year Ended December 31,		2005		2004		2003
(Thousands of dollars)
Construction revenues	$	259,026	$	215,008	$	196,651
Cost of construction		237,356		196,792		184,290

Gross profit		21,670		18,216		12,361
General and administrative expenses		6,672		5,742		5,543

Operating income		14,998		12,474		6,818
Other income (expense)		3,009		2,131		1,290
Interest expense		1,009		645		855

Income before income taxes		16,998		13,960		7,253
Income tax expense		6,845		5,539		2,962

Contribution to consolidated net income	$	10,153	$	8,421	$	4,291

2005 vs. 2004

The 2005 contribution to consolidated net income from construction services increased $1.7 million from 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 favorable equipment resale market in the current year.

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. The construction revenues above include NPL contracts with Southwest totaling $71.8 million in 2005, $61.6 million in 2004, and $58.9 million in 2003. NPL accounts for the services provided to Southwest at contractual (market) prices.

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.

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 convergence of favorable factors that resulted in the increase in contribution from construction services may not be repeatable in the future. The amount of work received under existing blanket contracts, the amount of bid work, and the equipment resale market vary from year-to-year.

2004 vs. 2003

The 2004 contribution to consolidated net income from construction services increased $4.1 million from 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 favorable equipment resale market in the current year. The improvement between years also reflects the impact of an unfavorable settlement of a $1.3 million insurance claim in 2003.

Revenues and gross profit for 2004 reflected 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.

Recently Issued Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 151, “Inventory Costs.” SFAS No. 151 addresses the accounting for abnormal amounts of idle facility expense, freight handling costs and spoilage and will no longer allow companies to capitalize such inventory costs on their balance sheets when the production defect rate varies significantly from the expected rate. The provisions of SFAS No. 151 are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. 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 December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” SFAS No. 153 is an amendment of Accounting Principles Board Opinion (“APB”) No. 29, “Accounting for Nonmonetary Transactions.” SFAS No. 153 addresses the accounting for exchanges of similar productive assets and eliminates the exception to the fair-value principle for such exchanges, which previously had been accounted for based on the book value of the asset surrendered with no gain recognition. Under SFAS No. 153, using certain criteria, the gain would be recognized currently and not deferred. The provisions of SFAS No. 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company adopted the standard on July 1, 2005. The adoption did not have a material impact on the financial position or results of operations of the Company.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 is a replacement of APB Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle, and requires retrospective application for voluntary changes in accounting principle unless it is impracticable to do so. The provisions of SFAS No. 154 are effective for accounting changes made in fiscal years beginning after December 15, 2005. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.

Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is designed to clarify when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

Southwest has certain conditional legal obligations related to portions of its system that are subject to limited-duration easements and rights-of-way agreements. However, Southwest has traditionally been able to renew its easements and rights-of-way without having to retire, abandon, or remove facilities, and anticipates no serious difficulties in obtaining future renewals. Southwest does not have any other material legal obligations associated with the abandonment or retirement of its tangible, long-lived assets. The Company adopted the provisions of FIN 47 on December 31, 2005. The adoption did not have a material impact on the financial position or results of operations of the Company.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS No. 123 (revised 2004) is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123 (revised 2004) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. This statement eliminates the alternative to use APB No. 25 and the intrinsic value method of accounting. SFAS No. 123 (revised 2004) requires entities to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards (with limited exceptions). The provisions of the statement (as amended by the SEC) are effective for the Company beginning January 2006. In 2006, compensation expense is expected to increase by an amount consistent with historical disclosures of pro-forma stock-based employee compensation expense. In conjunction with the adoption of SFAS No. 123 (revised 2004), beginning January 2006, the Company will no longer expense new awards granted to retirement-eligible employees over the anticipated vesting period, but will expense such awards immediately. This change is expected to result in increased compensation expense of approximately $1 million in 2006 due to the acceleration of expense recognition for awards to retirement eligible employees. Thereafter, the impact is not expected to be significant. For more information regarding the effect the original SFAS No. 123 would have had on historical results of operations, see Note 1 – Summary of Significant Accounting Policies, Stock-Based Compensation.

In February 2006, the 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 all financial instruments acquired or issued in the first fiscal year beginning after September 15, 2006. The Company has not evaluated what impact, if any, this standard will have on its financial position or results of operations.

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). Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets.

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 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

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 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 of 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.

Due to a decline in market interest rates for high-quality fixed income investments, the Company lowered the discount rate to 5.75% at December 31, 2005, from 6.0% at December 31, 2004. The Company also lowered its asset return assumption for 2006 from 8.75% to 8.50%. These changes will result in a $3.5 million increase in pension expense for 2006. The reduction in the discount rate, differences between actual and expected return on

plan assets, and other plan experience, resulted in the accumulated benefit obligations of the retirement plan and the supplemental retirement plan exceeding the related plan assets at the measurement date of December 31, 2005. Accordingly, the Company’s balance sheet includes a minimum pension liability of $67.2 million, with a corresponding accumulated other comprehensive loss, net of tax, recognized in stockholders’ equity. Should interest rates rise in 2006, the accumulated other comprehensive loss could be reduced or eliminated and pension cost reduced. Conversely, declining interest rates would put upward pressure on pension expense and cause the other comprehensive loss to increase. See Note 9 – Employee Benefits for plan assumptions and further discussion.

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, 2005 were included as exhibits to the 2005 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 CEO certification, dated May 17, 2005, was filed with the NYSE in May 2005.

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 the Company’s anticipated liability relating to a May 2005 accident, customer growth, customer mix and revenue patterns, efficiencies resulting from new technology, construction services contribution, ability to receive more effective rate designs, sufficiency of working 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 or through our DRSPP. 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, 2005.

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


	2005				2004				Dividends Paid
	High		Low		High		Low		2005		2004
First quarter	$	26.13	$	23.66	$	24.05	$	22.39	$	0.205	$	0.205
Second quarter		26.35		23.53		24.20		21.50		0.205		0.205
Third quarter		28.07		25.00		24.46		22.70		0.205		0.205
Fourth quarter		27.86		25.12		26.15		23.45		0.205		0.205

									$	0.820	$	0.820

Southwest Gas Corporation

Consolidated Balance Sheets


	December 31,
		2005			2004
(Thousands of dollars, except par value)
Assets
Utility plant:
Gas plant	$	3,516,587		$	3,287,591
Less: accumulated depreciation		(1,083,900	)		(985,919	)
Acquisition adjustments, net		2,173			2,353
Construction work in progress		54,287			31,967

Net utility plant (Note 2)		2,489,147			2,335,992

Other property and investments		118,094			99,879

Current assets:
Cash and cash equivalents		29,603			13,641
Accounts receivable, net of allowances (Note 3)		198,081			176,090
Accrued utility revenue		68,400			68,200
Deferred purchased gas costs (Note 4)		109,415			82,076
Prepaids and other current assets (Note 4)		137,161			91,986

Total current assets		542,660			431,993

Deferred charges and other assets (Note 4)		78,525			70,252

Total assets	$	3,228,426		$	2,938,116

Southwest Gas Corporation

Consolidated Balance Sheets – (continued)


		December 31,
		2005			2004
(Thousands of dollars, except par value)
Capitalization and Liabilities
Capitalization:
Common stock, $1 par (authorized – 45,000,000 shares; issued and outstanding – 39,328,291 and 36,794,343 shares)	$	40,958		$	38,424
Additional paid-in capital		628,248			566,646
Accumulated other comprehensive income (loss), net (Note 9)		(41,645	)		(10,892	)
Retained earnings		123,574			111,498

Total equity		751,135			705,676
Subordinated debentures due to Southwest Gas Capital II (Note 5)		100,000			100,000
Long-term debt, less current maturities (Note 6)		1,224,898			1,162,936

Total capitalization		2,076,033			1,968,612

Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)		83,215			29,821
Short-term debt (Note 7)		24,000			100,000
Accounts payable		259,476			165,872
Customer deposits		57,552			50,194
Accrued general taxes		40,526			38,189
Accrued interest		22,472			22,425
Deferred income taxes (Note 10)		68,166			26,676
Other current liabilities		65,546			49,854

Total current liabilities		620,953			483,031

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 10)		234,739			281,743
Taxes payable		7,551			3,965
Accumulated removal costs (Note 4)		105,000			84,000
Other deferred credits (Note 9)		184,150			116,765

Total deferred income taxes and other credits		531,440			486,473

Total capitalization and liabilities	$	3,228,426		$	2,938,116

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Consolidated Statements of Income


		Year Ended December 31,
		2005			2004			2003
(In thousands, except per share amounts)
Operating revenues:
Gas operating revenues	$	1,455,257		$	1,262,052		$	1,034,353
Construction revenues		259,026			215,008			196,651

Total operating revenues		1,714,283			1,477,060			1,231,004

Operating expenses:
Net cost of gas sold		828,131			645,766			482,503
Operations and maintenance		314,437			290,800			266,862
Depreciation and amortization		156,253			146,018			136,439
Taxes other than income taxes		39,040			37,669			35,910
Construction expenses		225,774			187,040			174,185

Total operating expenses		1,563,635			1,307,293			1,095,899

Operating income		150,648			169,767			135,105

Other income and (expenses):
Net interest deductions		(82,604	)		(78,782	)		(77,106	)
Net interest deductions on subordinated debentures (Note 5)		(7,723	)		(7,724	)		(2,680	)
Preferred securities distributions (Note 5)		–			–			(4,180	)
Other income (deductions)		8,114			3,751			4,245

Total other income and (expenses)		(82,213	)		(82,755	)		(79,721	)

Income before income taxes		68,435			87,012			55,384
Income tax expense (Note 10)		24,612			30,237			16,882

Net income	$	43,823		$	56,775		$	38,502

Basic earnings per share (Note 12)	$	1.15		$	1.61		$	1.14

Diluted earnings per share (Note 12)	$	1.14		$	1.60		$	1.13

Average number of common shares outstanding		38,132			35,204			33,760
Average shares outstanding (assuming dilution)		38,467			35,488			34,041

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation

Consolidated Statements of Cash Flows


		Year Ended December 31,
		2005			2004			2003
(Thousands of dollars)
Cash Flow from Operating Activities:
Net income	$	43,823		$	56,775		$	38,502
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		156,253			146,018			136,439
Deferred income taxes		(5,514	)		38,001			44,144
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(20,216	)		(49,307	)		4,416
Accrued utility revenue		982			(1,500	)		(1,627	)
Deferred purchased gas costs		(25,865	)		(72,925	)		(35,981	)
Accounts payable		92,021			55,758			21,586
Accrued taxes		5,716			3,027			(386	)
Other current assets and liabilities		(23,000	)		(25,406	)		1,692
Other		13,424			1,050			(1,009	)

Net cash provided by operating activities		237,624			151,491			207,776

Cash Flow From Investing Activities:
Construction expenditures and property additions		(294,369	)		(302,688	)		(240,671	)
Other		1,985			6,106			(18,215	)

Net cash used in investing activities		(292,384	)		(296,582	)		(258,886	)

Cash Flow From Financing Activities:
Issuance of common stock, net		64,136			58,687			21,290
Dividends paid		(31,228	)		(28,836	)		(27,685	)
Issuance of subordinated debentures, net		–			–			96,312
Issuance of long-term debt, net		145,256			147,135			159,997
Retirement of long-term debt, net		(31,442	)		(83,437	)		(140,013	)
Retirement of preferred securities		–			–			(60,000	)
Change in short-term debt		(76,000	)		48,000			(1,000	)

Net cash provided by financing activities		70,722			141,549			48,901

Change in cash and cash equivalents		15,962			(3,542	)		(2,209	)
Cash at beginning of period		13,641			17,183			19,392

Cash at end of period	$	29,603		$	13,641		$	17,183

Supplemental information:
Interest paid, net of amounts capitalized	$	86,465		$	80,433		$	78,561

Income taxes paid (received), net	$	5,977		$	(12,640	)	$	(26,733	)

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, 2002	33,289		$	34,919	$	487,788	$	–		$	73,460		$	596,167
Common stock issuances	943			943		20,347								21,290
Net income											38,502			38,502		$	38,502
Other						2,386								2,386
Dividends declared
Common: $0.82 per share											(27,878	)		(27,878	)

2003 Comprehensive Income																	38,502


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

At December 31, 2005, 923,000 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, 1.8 million common shares are registered for issuance upon the exercise of options granted or to be granted under the Stock Incentive Plan (see Note 9). During 2005, approximately 1 million shares were issued in at-the-market offerings through the Equity Shelf Program with gross proceeds of $25.9 million, agent commissions of $258,000, and net proceeds of $25.6 million.

The accompanying notes are an integral part of these statements.

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 purchases, transports, and distributes 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 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 maturity of three months or less, but exclude funds held in trust from the issuance of industrial development revenue bonds (“IDRBs”).

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 $105 million and $84 million, as of December 31, 2005 and 2004, 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. 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.

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.

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 million in 2005, $808,000 in 2004, and $2.6 million in 2003 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 $1.1 million, $691,000 and $1.5 million for 2005, 2004 and 2003, 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.


	2005	2004	2003
(In thousands)
Average basic shares	38,132	35,204	33,760
Effect of dilutive securities:
Stock options	146	111	73
Performance shares	189	173	208

Average diluted shares	38,467	35,488	34,041

Derivatives. In managing its gas supply portfolios, Southwest uses fixed-price 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. The Company does not currently utilize other stand-alone derivative financial instruments for speculative purposes or for hedging.

Reclassifications. Certain reclassifications have been made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation.

Recently Issued Accounting Pronouncements. In November 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 151, “Inventory Costs.” SFAS No. 151 addresses the accounting for abnormal amounts of idle facility expense, freight handling costs and spoilage and will no longer allow companies to capitalize such inventory costs on their balance sheets when the production defect rate varies significantly from the expected rate. The provisions of SFAS No. 151 are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. 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 December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” SFAS No. 153 is an amendment of Accounting Principles Board Opinion (“APB”) No. 29, “Accounting for Nonmonetary Transactions.” SFAS No. 153 addresses the accounting for exchanges of similar productive assets and eliminates the exception to the fair-value principle for such exchanges, which previously had been accounted for based on the book value of the asset surrendered with no gain recognition. Under SFAS No. 153, using certain criteria, the gain would be recognized currently and not deferred. The provisions of SFAS No. 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company adopted this standard on July 1, 2005. The adoption did not have a material impact on the financial position or results of operations of the Company.

In March 2005, the FASB issued Interpretation No. 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations.” FIN 47 is an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations.” FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is designed to clarify when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS No. 123 (revised 2004) is a revision of SFAS 123, “Accounting for Stock Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123 (revised 2004) establishes standards for the

accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. This statement eliminates the alternative to use APB No. 25 and the intrinsic value method of accounting. SFAS No 123 (revised 2004) requires entities to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards (with limited exceptions). The provisions of the statement (as amended by the SEC) are effective for the Company beginning January 2006. In 2006, compensation expense is expected to increase by an amount consistent with historical disclosures of pro-forma stock-based employee compensation expense. In conjunction with the adoption of SFAS No. 123 (revised 2004), beginning January 2006, the Company will no longer expense new awards granted to retirement-eligible employees over the stated vesting period, but will expense such awards immediately. This change is expected to result in increased compensation expense of approximately $1 million in 2006 due to the acceleration of expense recognition for awards to retirement eligible employees. Thereafter, the impact is not expected to be significant. The table below illustrates the effect SFAS No. 123 would have had on historical net income and earnings per share. The Company expects a similar impact to its results of operations upon the adoption of SFAS 123 (revised 2004).

Stock-Based Compensation. At December 31, 2005, the Company had two stock-based compensation plans, which are described more fully in Note 9 – Employee Benefits. These plans have been accounted for in accordance with APB No. 25. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123 to its stock-based employee compensation (thousands of dollars, except per share amounts):


		2005			2004			2003
Net income, as reported	$	43,823		$	56,775		$	38,502
Add: Stock-based employee compensation expense included in reported net income, net of related tax benefits		2,469			1,825			2,438
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	)		(2,920	)

Pro forma net income	$	43,672		$	56,642		$	38,020

Earnings per share:
Basic – as reported	$	1.15		$	1.61		$	1.14
Basic – pro forma		1.15			1.61			1.13
Diluted – as reported		1.14			1.60			1.13
Diluted – pro forma		1.14			1.60			1.12

Note 2 – Utility Plant

Net utility plant as of December 31, 2005 and 2004 was as follows (thousands of dollars):


December 31,		2005			2004
Gas plant:
Storage	$	17,357		$	17,189
Transmission		239,872			233,841
Distribution		2,917,959			2,706,089
General		213,906			206,837
Other		127,493			123,635

		3,516,587			3,287,591
Less: accumulated depreciation		(1,083,900	)		(985,919	)
Acquisition adjustments, net		2,173			2,353
Construction work in progress		54,287			31,967

Net utility plant	$	2,489,147		$	2,335,992

Depreciation and amortization expense on gas plant was $137 million in 2005, $128 million in 2004, and $118 million in 2003.

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 2006 through 2010 and $14.3 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.5 million for each of the years 2006 through 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 million in 2005, $20.3 million in 2004, and $20 million in 2003. These amounts include NPL lease expenses of approximately $11.5 million in 2005, $9.8 million in 2004, and $9.6 million in 2003 for various short-term operating leases of equipment and temporary office sites.

The Company previously leased a LNG facility and approximately 61 miles of transmission main on its northern Nevada system. In December 2004, Paiute, a wholly owned interstate pipeline subsidiary of the Company, purchased the LNG facilities and associated transmission main.

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, 2005 (thousands of dollars):


Year Ending December 31,
2006	$	5,504
2007		4,996
2008		4,605
2009		3,793
2010		2,456
Thereafter		15,214

Total minimum lease payments	$	36,568

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, 2005, the gas utility customer accounts receivable balance was $151 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, 2002	$	1,825
Additions charged to expense		2,523
Accounts written off, less recoveries		(2,102	)

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

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”). Company 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.

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


December 31,		2005			2004
Regulatory assets:
Deferred purchased gas costs	$	109,415		$	82,076
Accrued purchased gas costs *		75,300			35,600
SFAS No. 109 – income taxes, net		2,447			3,074
Unamortized premium on reacquired debt		18,386			19,229
Other		28,236			28,655

		233,784			168,634
Regulatory liabilities:
Accumulated removal costs		(105,000	)		(84,000	)
Other		(821	)		(730	)

Net regulatory assets (liabilities)	$	127,963		$	83,904

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

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

Note 5 – Preferred Securities and Subordinated Debentures

In October 1995, Southwest Gas Capital I (the “Trust”), a consolidated wholly owned subsidiary of the Company, issued $60 million of 9.125% Trust Originated Preferred Securities (the “Preferred Securities”). In connection with the Trust issuance of the Preferred Securities and the related purchase by the Company of all of the trust common securities, the Company issued to the Trust $61.8 million principal amount of its 9.125% Subordinated Deferrable Interest Notes, due 2025.

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, 2005, 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 (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.

A portion of the net proceeds from the issuance of the Preferred Trust Securities was used to complete the redemption of the 9.125% Trust Originated Preferred Securities effective September 2003 at a redemption price of $25 per Preferred Security, totaling $60 million plus accrued interest of $1.3 million.

In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities. FIN 46 explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. Trust II, the issuer of the preferred trust securities, meets the definition of a variable interest entity.

Although the Company owns 100 percent of the common voting securities of Trust II, under FIN 46, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. The adoption of FIN 46 results in the Company reflecting a liability to Trust II (which under the prior accounting treatment would have been eliminated in consolidation) instead of to the holders of the preferred trust securities. As a result, payments and amortizations associated with the liability are classified on the consolidated statements of income as Net interest deductions on subordinated debentures. The preferred securities distributions category contains carrying costs of the original Preferred Securities. 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.

Note 6 – Long-Term Debt


	2005					2004
December 31,		Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
7¹/2% Series, due 2006	$	75,000		$	76,155	$	75,000		$	79,523
Notes, 8.375%, due 2011		200,000			225,720		200,000			239,800
Notes, 7.625%, due 2012		200,000			222,040		200,000			234,500
8% Series, due 2026		75,000			90,525		75,000			92,858
Medium-term notes, 7.75% series, due 2005		–			–		25,000			25,840
Medium-term notes, 6.89% series, due 2007		17,500			17,971		17,500			18,848
Medium-term notes, 6.27% series, due 2008		25,000			25,600		25,000			26,830
Medium-term notes, 7.59% series, due 2017		25,000			28,573		25,000			30,050
Medium-term notes, 7.78% series, due 2022		25,000			29,088		25,000			30,663
Medium-term notes, 7.92% series, due 2027		25,000			30,000		25,000			30,790
Medium-term notes, 6.76% series, due 2027		7,500			7,976		7,500			8,175
Unamortized discount		(4,657	)		–		(5,330	)		–

		670,343					694,670

Revolving credit facility and commercial paper		150,000			150,000		100,000			100,000

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			13,068		12,410			14,023
5.95% 1999 Series C, due 2038		14,320			15,057		14,320			15,895
5.55% 1999 Series D, due 2038		8,270			8,593		8,270			8,725
5.45% 2003 Series C, due 2038		30,000			30,264		30,000			31,350
5.25% / 3.35% 2003 Series D, due 2038		20,000			20,400		20,000			20,776
5.80% 2003 Series E, due 2038		15,000			15,218		15,000			15,975
5.25% 2004 Series A, due 2034		65,000			65,878		65,000			66,625
5.00% 2004 Series B, due 2033		75,000			75,000		75,000			76,125
4.85% 2005 Series A, due 2035 net of $24,634 held in trust		75,366			73,030		–			–
Unamortized discount		(4,159	)		–		(2,918	)		–

		461,207					387,082

Other		26,563			–		11,005			–

		1,308,113					1,192,757
Less: current maturities		(83,215	)				(29,821	)

Long-term debt, less current maturities	$	1,224,898				$	1,162,936

applicable margin of the previous facility. At December 31, 2005, $24 million was outstanding on the short-term portion of the credit facility and $150 million was outstanding on the long-term portion.

In June 2005, a $50.1 million letter of credit, which supports the Clark County, Nevada $50 million Industrial Development Revenue Bonds (“IDRBs”) 2003 Series A, due 2038, was renewed for a five-year period expiring in June 2010.

In June 2005, a $55.3 million letter of credit, which supports the City of Big Bear $50 million tax-exempt Series A IDRBs, due 2028, was renewed for a five-year period expiring in June 2010.

In July 2005, the Company amended its Financing Agreement dated March 1, 2003 with Clark County, Nevada associated with $50 million in 2003 Series B IDRBs. The amendment was executed in connection with the use of an insurance policy with Ambac Assurance Corporation to secure payment in the remarketing of the IDRBs. Previously, payment of the principal was secured with a letter of credit.

In October 2005, the Company issued $100 million in Clark County, Nevada, 4.85% 2005 Series A IDRBs. The IDRBs were issued at a discount of 0.75% and are due October 2035. At December 31, 2005, $24.6 million in proceeds from the issuance of the IDRB’s remained in trust. The proceeds from the IDRBs are being 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 January 1, 2004. 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, 2005, the Company was in compliance with the applicable covenants.

The effective interest rates on the 2003 Series A and B variable-rate IDRBs were 4.64 percent and 3.84 percent, respectively at December 31, 2005 and 3.44 percent and 3.44 percent, respectively at December 31, 2004. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 4.55 percent and 3.46 percent at December 31, 2005 and 2004, 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, 2005 and 2004, 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 $83.2 million, $25.3 million, $31.6 million, $4 million, and $150 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 $32.8 million.

Note 7 – Short-Term Debt

As discussed in Note 6, Southwest has a new $300 million five-year credit facility, effective April 2005, of which $150 million is for working capital purposes (and related outstanding amounts will be designated as short-term debt). Short-term borrowings on the credit facility were $24 million and $95 million at December 31, 2005 and 2004, respectively. The weighted-average interest rates on these borrowings were 5.08 percent and 3.37 percent at December 31, 2005 and 2004, respectively.

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 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 increased from $1 million

per incident to $1 million per incident plus payment of the first $10 million in aggregate claims above $1 million in the policy year. For the policy year August 2005 to July 2006, the Company entered into insurance contracts that limit the Company’s self-insured retention to $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million. 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. A complaint was filed against the Company in December 2005 in which the plaintiffs have claimed $3.4 million in medical bills, $12 million in future medical expenses, and made unspecified claims for general and punitive damages. The Company has answered the complaint and denied liability. If the Company was deemed fully or partially responsible, the Company estimates its exposure could be as much as $11 million (the maximum noted above). As of December 31, 2005, the Company has recorded an $11 million liability related to this incident.

The Company is a defendant in other 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 future results of operations.

Note 9 – Employee Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees and a separate unfunded supplemental retirement plan 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.

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 of 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 considers highly-rated

corporate bonds and considers other measures of interest rates for high quality fixed income investments which match the duration of the liabilities. A rate is chosen based on an evaluation of these measures, rounded to the nearest 25 basis points.

Due to a decline in market interest rates for high-quality fixed income investments, the Company lowered the discount rate to 5.75% at December 31, 2005 from 6.00% at December 31, 2004. The Company also lowered its asset return assumption for 2006 from 8.75% to 8.50%. These changes will result in an increase in pension expense of approximately $3.5 million for 2006. The reduction in the discount rate, coupled with other plan experience, resulted in the accumulated benefit obligations of the retirement plan and the supplemental retirement plan exceeding the related plan assets at the measurement date of December 31, 2005. Accordingly, the Company’s balance sheet includes a minimum pension liability of $67.2 million, with a corresponding accumulated other comprehensive loss, net of tax, recognized in stockholders’ equity.

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


	Qualified Retirement Plan						PBOP
		2005			2004			2005			2004
(Thousands of dollars)
Change in benefit obligations
Benefit obligation for service rendered to date at beginning of year (PBO/APBO)	$	428,116		$	369,094		$	35,988		$	34,367
Service cost		15,787			13,790			837			722
Interest cost		25,327			23,659			2,115			2,180
Actuarial loss (gain)		17,842			31,773			103			369
Benefits paid		(13,654	)		(10,200	)		(1,490	)		(1,650	)

Benefit obligation at end of year (PBO/APBO)	$	473,418		$	428,116		$	37,553		$	35,988

Change in plan assets
Market value of plan assets at beginning of year	$	318,664		$	293,436		$	18,750		$	15,854
Actual return on plan assets		15,988			22,425			1,102			1,653
Employer contributions		17,620			13,003			1,127			1,243
Benefits paid		(13,654	)		(10,200	)		–			–

Market value of plan assets at end of year	$	338,618		$	318,664		$	20,979		$	18,750

Funded status	$	(134,800	)	$	(109,452	)	$	(16,574	)	$	(17,238	)
Unrecognized net actuarial loss (gain)		123,028			94,074			5,954			5,685
Unrecognized transition obligation (2004/2012)		–			–			6,069			6,935
Unrecognized prior service cost		(34	)		(45	)		–			–

Prepaid (accrued) benefit cost	$	(11,806	)	$	(15,423	)	$	(4,551	)	$	(4,618	)

Accrued benefit liability	$	(66,082	)	$	(22,269	)	$	(4,551	)	$	(4,618	)
Additional minimum pension liability adjustment		54,276			6,846			–			–

	$	(11,806	)	$	(15,423	)	$	(4,551	)	$	(4,618	)

Weighted-average assumptions (benefit obligation)
Discount rate		5.75	%		6.00	%		5.75	%		6.00	%
Weighted average rate of compensation increase		3.30	%		4.00	%		3.30	%		4.00	%

Asset Allocation
Equity securities		61	%		64	%		71	%		75	%
Debt securities		30	%		31	%		15	%		17	%
Other		9	%		5	%		14	%		8	%

Total		100	%		100	%		100	%		100	%

The measurement date used to determine pension and other postretirement benefit measurements was December 31, 2005. Estimated funding for the plans above during calendar year 2006 is approximately $24 million. The accumulated benefit obligation for the retirement plan was $405 million and $341 million at December 31, 2005 and 2004, respectively. Pension benefits expected to be paid for each of the next five years beginning with 2006 are the following: $14.5 million, $15.6 million, $16.9 million, $18.5 million, and $20.2 million. Pension benefits expected to be paid during 2011 to 2015 total $134 million. Retiree welfare benefits expected to be paid for each of the next five years beginning with 2006 are the following: $1.4 million, $1.5 million, $1.6 million, $1.6 million, and $1.7 million. Retiree welfare benefits expected to be paid during 2011 to 2015 total $10 million.

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.

Components of net periodic benefit cost:


	Qualified Retirement Plan									PBOP
		2005			2004			2003			2005			2004			2003
(Thousands of dollars)
Service cost	$	15,787		$	13,790		$	12,267		$	837		$	722		$	675
Interest cost		25,327			23,659			21,243			2,115			2,180			2,095
Expected return on plan assets		(29,553	)		(28,067	)		(27,217	)		(1,675	)		(1,426	)		(1,205	)
Amortization of prior service costs		(11	)		54			57			–			–			–
Amortization of unrecognized transition obligation		–			–			795			867			867			867
Amortization of net (gain) loss		2,453			–			–			136			213			257

Net periodic benefit cost	$	14,003		$	9,436		$	7,145		$	2,280		$	2,556		$	2,689

Weighted-average assumptions (net benefit cost)
Discount rate		6.00	%		6.50	%		6.75	%		6.00	%		6.50	%		6.75	%
Expected return on plan assets		8.75	%		8.75	%		8.95	%		8.75	%		8.75	%		8.95	%
Weighted average rate of compensation increase		4.00	%		4.25	%		4.25	%		4.00	%		4.25	%		4.25	%

In addition to the retirement plan, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The plan is noncontributory with defined benefits. Plan costs were $3.1 million in 2005, $2.7 million in 2004, and $2.7 million in 2003. The accumulated benefit obligation of the plan was $32.6 million at December 31, 2005. The minimum pension liability for this plan was $12.9 million at December 31, 2005.

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 $3.5 million in 2005, $3.5 million in 2004, and $3.3 million in 2003. 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 salary. 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.

At December 31, 2005, the Company had two stock-based compensation plans. These plans have been accounted for in accordance with APB Opinion No. 25 “Accounting for Stock Issued to Employees.” In connection

with the stock-based compensation plans, the Company recognized compensation expense of $4.1 million in 2005, $3 million in 2004, and $4.1 million in 2003. In 2006, the Company will adopt SFAS 123 (revised 2004) and will recognize compensation expense for all stock-based compensation plans based on the fair value provisions of the revised standard. (See Note 1 for additional details.)

Under one plan, the Company may grant options to purchase shares of common stock to key employees and outside directors. 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 2005 and the extended binomial option pricing model in 2004 and 2003. The following assumptions were used in the valuation calculation:


	2005	2004	2003
Dividend yield	3.14 to 3.28%	3.50%	3.94%
Risk-free interest rate range	3.88 to 4.09%	1.66 to 3.23%	1.06 to 2.17%
Expected volatility range	18%	13 to 20%	16 to 25%
Expected life	6 years	1 to 3 years	1 to 3 years

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


	2005				2004				2003
	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	1,646		$	22.46	1,502		$	21.83	1,260		$	21.66
Granted during the year	347			26.00	403			23.36	348			21.05
Exercised during the year	(510	)		21.28	(254	)		20.21	(106	)		17.18
Forfeited during the year	(8	)		22.41	(5	)		21.83	–			–
Expired during the year	–			–	–			–	–			–

Outstanding at year end	1,475		$	23.70	1,646		$	22.46	1,502		$	21.83

Exercisable at year end	813		$	23.06	1,010		$	22.36	868		$	21.96

The weighted-average grant-date fair value of options granted was $4.18 for 2005, $1.65 for 2004, and $1.90 for 2003. The following table summarizes information about stock options outstanding at December 31, 2005 (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	55	3.1 Years	$	17.95	55	$	17.95
$20.49 to $ 26.10	1,302	7.7 Years	$	23.47	640	$	22.43
$28.75 to $ 28.94	118	3.5 Years	$	28.91	118	$	28.91

In addition to the option plan, the Company may issue restricted stock in the form of 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 after three years from issuance and are subject to a final adjustment as determined by the Board of Directors. The following table summarizes the activity of this plan (thousands of shares):


Year Ended December 31,		2005			2004			2003
Nonvested performance shares at beginning of year		316			381			345
Performance shares granted		143			156			147
Performance shares forfeited		6			–			–
Shares vested and issued*		(108	)		(221	)		(111	)

Nonvested performance shares at end of year		357			316			381

Average grant date fair value of awards granted this year	$	24.71		$	22.70		$	22.21

*	Includes shares converted for taxes and retiree payouts.

Note 10 – Income Taxes

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


Year Ended December 31,		2005		2004			2003

Current:
Federal	$	553	$	(225	)	$	24
State		2,218		(1,186	)		(4,421	)

		2,771		(1,411	)		(4,397	)

Deferred:
Federal		21,301		28,607			17,274
State		540		3,041			4,005

		21,841		31,648			21,279

Total income tax expense	$	24,612	$	30,237		$	16,882

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


Year Ended December 31,		2005			2004			2003
Deferred federal and state:
Property-related items	$	(3,143	)	$	(3,165	)	$	22,608
Purchased gas cost adjustments		28,094			34,923			1,030
Employee benefits		2,232			240			(1,767	)
Injuries and damages reserves		(4,072	)		190			(1,023	)
All other deferred		(402	)		328			1,299

Total deferred federal and state		22,709			32,516			22,147
Deferred ITC, net		(868	)		(868	)		(868	)

Total deferred income tax expense	$	21,841		$	31,648		$	21,279

The consolidated effective income tax rate for the period ended December 31, 2005 and the two prior periods differs 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,	2005		2004		2003
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Net state taxes	2.7		2.8		2.4
Property-related items	1.1		0.8		1.3
Effect of closed tax years and resolved issues	–		(1.8	)	(3.6	)
Tax credits	(1.3	)	(1.0	)	(1.6	)
Corporate owned life insurance	(1.6	)	(0.7	)	(2.3	)
All other differences	0.1		(0.3	)	(0.7	)

Consolidated effective income tax rate	36.0	%	34.8	%	30.5	%

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


December 31,		2005		2004
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	6,964	$	7,500
Employee benefits		50,468		33,710
Alternative minimum tax		28,903		24,028
Net operating losses & credits		37,976		59,977
Other		10,510		5,607
Valuation allowance		–		–

		134,821		130,822

Deferred tax liabilities:
Property-related items, including accelerated depreciation		337,234		365,242
Regulatory balancing accounts		68,395		40,301
Property-related items previously flowed through		9,411		10,574
Unamortized ITC		11,198		12,065
Debt-related costs		6,292		6,942
Other		5,196		4,117

		437,726		439,241

Net deferred tax liabilities	$	302,905	$	308,419

Current	$	68,166	$	26,676
Noncurrent		234,739		281,743

Net deferred tax liabilities	$	302,905	$	308,419

At December 31, 2005, the Company has a federal net operating loss carryforward of $95.3 million which expires in 2022 to 2023. The Company also has an Arizona net operating loss carryforward of $24.7 million which expires in 2006 to 2009 and a California net operating loss carryforward of $822,000 which expires in 2014.

Note 11 – 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, 2005 and 2004, accounts receivable for these services totaled $8.2 million and $8.3 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, 2005 is as follows (thousands of dollars):


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

2003		Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,034,353	$	137,717				$	1,172,070
Intersegment sales		–		58,934					58,934

Total	$	1,034,353	$	196,651				$	1,231,004

Interest expense	$	78,931	$	855				$	79,786

Depreciation and amortization	$	120,791	$	15,648				$	136,439

Income tax expense	$	13,920	$	2,962				$	16,882

Segment income	$	34,211	$	4,291				$	38,502

Segment assets	$	2,528,332	$	79,774				$	2,608,106

Capital expenditures	$	228,288	$	12,383				$	240,671

(a)	Construction services segment assets include 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.

Note 12 – Quarterly Financial Data (Unaudited)


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

2003
Operating revenues	$	403,285	$	255,852		$	220,162		$	351,705
Operating income (loss)		62,314		11,789			(8,285	)		69,287
Net income (loss)		25,539		(4,104	)		(17,407	)		34,474
Basic earnings (loss) per common share*		0.76		(0.12	)		(0.51	)		1.01
Diluted earnings (loss) per common share*		0.76		(0.12	)		(0.51	)		1.00

*	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.

Note 13 – Acquisition of South Lake Tahoe Natural Gas Distribution Properties

In April 2005, the Company purchased the natural gas distribution properties of Avista Corporation in South Lake Tahoe, California, which included approximately 19,000 customers. The cash purchase price for the properties was $15.2 million, net of post-closing adjustments. The assets acquired and the liabilities assumed at the acquisition date were as follows (thousands of dollars):


Gas plant	$	20,951
Less: accumulated depreciation		(13,158	)

Net utility plant		7,793
Accounts receivable, net of allowances		1,775
Accrued utility revenue		1,182
Deferred purchased gas costs		1,474
Prepaids and other current assets		276
Deferred charges and other assets		4,670

Total assets acquired		17,170

Accounts payable		1,583
Customer deposits		169
Accrued general taxes		207
Accrued interest		2

Total liabilities assumed		1,961

Cash acquisition price	$	15,209

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, 2005. Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

March 9, 2006

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 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements 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, cash flows, and stockholders’ equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 5 to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both debt and equity and variable interest entities as of July 1, 2003.

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, 2005 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, 2005, 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.

PricewaterhouseCoopers LLP

Los Angeles, California

March 9, 2006

List of Subsidiaries of Southwest Gas Corporation

EXHIBIT 21.01

SOUTHWEST GAS CORPORATION

LIST OF SUBSIDIARIES OF THE REGISTRANT

AT DECEMBER 31, 2005


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. 333-118157 and 333-106419) and Form S-8 (Nos. 333-126736, 333-106762 and 333-31223) of Southwest Gas Corporation of our report dated March 9, 2006 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

March 9, 2006

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.

Date: March 9, 2006

/s/ JEFFREY W. SHAW

Jeffrey W. Shaw

Chief Executive Officer

Southwest Gas Corporation

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.

Date: March 9, 2006

/s/ GEORGE C. BIEHL

George C. Biehl

Executive Vice President, Chief Financial Officer and Corporate Secretary

Southwest Gas Corporation

Section 906 Certifications

Exhibit 32.01

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission (the “Report”), I, Jeffrey W. Shaw, the Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)

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

(2)

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

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

Dated: March 9, 2006

/s/ Jeffrey W. Shaw

Jeffrey W. Shaw

Chief Executive Officer

SOUTHWEST GAS CORPORATION

CERTIFICATION

In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2005 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.

Dated: March 9, 2006

/s/ George C. Biehl

George C. Biehl

Executive Vice President, Chief Financial Officer and Corporate Secretary

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