Exhibit 13.01

CONSOLIDATED SELECTED FINANCIAL STATISTICS

Year Ended December 31,	2008			2007			2006			2005			2004
(Thousands of dollars, except per share amounts)
Operating revenues	$	2,144,743		$	2,152,088		$	2,024,758		$	1,714,283		$	1,477,060
Operating expenses		1,936,881			1,929,788			1,811,608			1,563,635			1,307,293
Operating income	$	207,862		$	222,300		$	213,150		$	150,648		$	169,767
Net income	$	60,973		$	83,246		$	83,860		$	43,823		$	56,775
Total assets at year end	$	3,820,384		$	3,670,188		$	3,484,965		$	3,228,426		$	2,938,116
Capitalization at year end
Common equity	$	1,037,841		$	983,673		$	901,425		$	751,135		$	705,676
Subordinated debentures		100,000			100,000			100,000			100,000			100,000
Long-term debt		1,185,474			1,266,067			1,286,354			1,224,898			1,162,936
	$	2,323,315		$	2,349,740		$	2,287,779		$	2,076,033		$	1,968,612
Common stock data
Common equity percentage of capitalization		44.7	%		41.9	%		39.4	%		36.2	%		35.8	%
Return on average common equity		6.0	%		8.8	%		10.3	%		5.9	%		8.5	%
Basic earnings per share	$	1.40		$	1.97		$	2.07		$	1.15		$	1.61
Diluted earnings per share	$	1.39		$	1.95		$	2.05		$	1.14		$	1.60
Dividends declared per share	$	0.90		$	0.86		$	0.82		$	0.82		$	0.82
Payout ratio		64	%		44	%		40	%		71	%		51	%
Book value per share at year end	$	23.48		$	22.98		$	21.58		$	19.10		$	19.18
Market value per share at year end	$	25.22		$	29.77		$	38.37		$	26.40		$	25.40
Market value per share to book value per share		107	%		130	%		178	%		138	%		132	%
Common shares outstanding at year end (000)		44,192			42,806			41,770			39,328			36,794
Number of common shareholders at year end		22,244			22,664			23,610			23,571			23,743
Ratio of earnings to fixed charges		2.01			2.25			2.25			1.70			1.93

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NATURAL GAS OPERATIONS

Year Ended December 31,	2008			2007			2006			2005			2004
(Thousands of dollars)
Sales	$	1,728,924		$	1,754,913		$	1,671,093		$	1,401,329		$	1,211,019
Transportation		62,471			59,853			56,301			53,928			51,033
Operating revenue		1,791,395			1,814,766			1,727,394			1,455,257			1,262,052
Net cost of gas sold		1,055,977			1,086,194			1,033,988			828,131			645,766
Operating margin		735,418			728,572			693,406			627,126			616,286
Expenses
Operations and maintenance		338,660			331,208			320,803			314,437			290,800
Depreciation and amortization		166,337			157,090			146,654			137,981			130,515
Taxes other than income taxes		36,780			37,553			34,994			39,040			37,669
Operating income	$	193,641		$	202,721		$	190,955		$	135,668		$	157,302
Contribution to consolidated net income	$	53,747		$	72,494		$	71,473		$	33,670		$	48,354
Total assets at year end	$	3,680,327		$	3,518,304		$	3,352,074		$	3,103,804		$	2,843,199
Net gas plant at year end	$	2,983,307		$	2,845,300		$	2,668,104		$	2,489,147		$	2,335,992
Construction expenditures and property additions	$	279,254		$	312,412		$	305,914		$	258,547		$	274,748
Cash flow, net
From operating activities	$	261,322		$	320,594		$	253,245		$	214,036		$	124,135
From (used in) investing activities		(237,093	)		(306,396	)		(277,980	)		(254,120	)		(272,458	)
From (used in) financing activities		(34,704	)		(5,347	)		15,989			57,763			143,086
Net change in cash	$	(10,475	)	$	8,851		$	(8,746	)	$	17,679		$	(5,237	)
Total throughput (thousands of therms)
Residential		704,986			698,063			677,605			650,465			667,174
Small commercial		314,555			310,666			309,856			300,072			303,844
Large commercial		125,121			127,561			128,255			111,839			104,899
Industrial/Other		97,702			103,525			149,243			156,542			163,856
Transportation		1,164,190			1,128,422			1,175,238			1,273,964			1,258,265
Total throughput		2,406,554			2,368,237			2,440,197			2,492,882			2,498,038
Weighted average cost of gas purchased ($/therm)	$	0.84		$	0.81		$	0.79		$	0.71		$	0.57
Customers at year end		1,819,000			1,813,000			1,784,000			1,713,000			1,613,000
Employees at year end		2,447			2,538			2,525			2,590			2,548
Customer to employee ratio		743			714			706			661			633
Degree days—actual		1,902			1,850			1,826			1,735			1,953
Degree days—ten-year average		1,893			1,936			1,961			1,956			1,913

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

About Southwest Gas Corporation

Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two business segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services.

Southwest is engaged in the business of purchasing, distributing, and transporting natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.

As of December 31, 2008, Southwest had 1,819,000 residential, commercial, industrial, and other natural gas customers, of which 982,000 customers were located in Arizona, 658,000 in Nevada, and 179,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2008, 55 percent of operating margin was earned in Arizona, 35 percent in Nevada, and 10 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.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting operating margin are general rate relief, weather, conservation and efficiencies, and customer growth. Of these, weather is the primary reason for volatility in margin. Variances in temperatures from normal levels, especially in Arizona where rates remain leveraged, have a significant impact on the margin and associated net income of the Company.

NPL 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. NPL operates in 20 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including the housing market, interest rates, employment levels, job growth, the equipment resale market, and local and federal tax rates.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and are covered in greater detail in later sections of management’s discussion and analysis. The natural gas operations segment accounted for an average of 87 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

Summary Operating Results

Year ended December 31,	2008		2007		2006
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	53,747	$	72,494	$	71,473
Construction services		7,226		10,752		12,387
Consolidated	$	60,973	$	83,246	$	83,860
Average number of common shares outstanding		43,476		42,336		40,566
Basic earnings per share
Consolidated	$	1.40	$	1.97	$	2.07
Natural Gas Operations
Operating margin	$	735,418	$	728,572	$	693,406

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2008 Overview

Consolidated results for 2008 decreased compared to 2007, due to declines in both the gas and construction services segments. Basic earnings per share were $1.40 in 2008 compared to basic earnings per share of $1.97 in 2007.

Gas operations highlights include the following:

• Operating margin increased $6.8 million, or 1 percent, from the prior year

• Net financing costs decreased $3.3 million between 2008 and 2007

• Other income declined $18 million between periods primarily due to a $13.2 million reduction in returns on long-term investments (COLI)

• Southwest’s project to expand its use of electronic meter reading technology was completed

• Annualized Arizona rate relief of $33.5 million was approved effective December 2008

• Settlement was reached in California rate cases

• Southwest took advantage of the current credit market and repurchased $75 million of IDRBs at a net deferred gain of $14 million

• Southwest’s liquidity position remains strong

Construction services highlights include the following:

• Revenues in 2008 increased $16 million in comparison to 2007

• Contribution to consolidated net income declined $3.5 million compared to 2007 primarily due to the slowdown in the new housing market which impacted profit margins

Reduction in Customer Growth. During the twelve months ended December 31, 2008, Southwest completed 33,000 first-time meter sets. These meter sets led to 6,000 net additional active meters during the same time frame (2,000 in Arizona, 3,000 in Nevada, and 1,000 in California). The difference between first-time meter sets and incremental active meters indicates a significant inventory of unoccupied homes, continuing a trend first experienced during 2007. Southwest is projecting continued sluggish net growth (1% or less) for 2009 as high foreclosure rates and difficult economic conditions persist throughout its service territories. Once housing supply and demand come back into balance, Southwest expects to experience a correction in which customer additions exceed first-time meter sets. Although management cannot predict the timing of a turn around, it is likely to occur over an extended (multi-year) time horizon.

Company-Owned Life Insurance (“COLI”). Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $137 million at December 31, 2008. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $47 million at December 31, 2008 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. During 2008, Southwest recognized in Other income (deductions) a net decline in the cash surrender values of its company-owned life insurance policies of $12 million (compared to positive returns of $1.2 million in 2007). Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the changes in the cash surrender value components of COLI policies as they progress towards the ultimate death benefits are also recorded without tax consequences. Currently, the Company intends to hold the COLI policies for their duration and purchase additional policies as necessary.

Liquidity. During 2008, significant attention was paid to companies’ liquidity and credit risks. These risks will likely continue given the current troubled economic environment. The Company has experienced no significant impacts to its liquidity position from the current credit crisis. In September 2008, the Company issued $50 million in Clark County, Nevada variable-rate 2008 Series A Industrial Development Revenue Bonds (“IDRBs”), due 2038. The 2008 Series A IDRBs are supported by a letter of credit with JPMorgan Chase Bank. The proceeds from the 2008 Series A IDRBs were used by the Company to redeem its $50 million 2003 Series B variable-rate IDRBs which were insured by Ambac Assurance Corporation. Earlier in 2008, several weekly repricing auctions for the 2003 Series B IDRBs failed.

Southwest’s liquidity position has remained strong throughout the year for several reasons. First, Southwest has a $300 million credit facility maturing in May 2012, $150 million of which is designated for working capital needs. The facility is composed of eight major banking institutions. Historically, usage of the facility has been low and concentrated in the first half of the winter heating period when gas purchases require temporary financing. Second, falling natural gas prices and beneficial rate mechanisms have resulted in strong purchased gas

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adjustment (“PGA”) cash flows over the last two years. Third, Southwest has no significant debt maturities prior to February 2011. Because of Southwest’s strong liquidity position, in December 2008, Southwest was able to take advantage of the current credit market by repurchasing $75 million of IDRBs at a net deferred gain of $14 million.

Meter Reading Project. In 2006, Southwest initiated a project to expand its use of electronic meter reading technology. This technology eliminates the need to gain physical access to meters in order to obtain monthly meter readings, thereby reducing the time associated with each meter read while improving their accuracy. At December 31, 2008, the electronic meter reading project was complete.

Results of Natural Gas Operations

Year Ended December 31,	2008			2007		2006
(Thousands of dollars)
Gas operating revenues	$	1,791,395		$	1,814,766	$	1,727,394
Net cost of gas sold		1,055,977			1,086,194		1,033,988
Operating margin		735,418			728,572		693,406
Operations and maintenance expense		338,660			331,208		320,803
Depreciation and amortization		166,337			157,090		146,654
Taxes other than income taxes		36,780			37,553		34,994
Operating income		193,641			202,721		190,955
Other income (expense)		(13,469	)		4,850		10,049
Net interest deductions		83,096			86,436		85,567
Net interest deductions on subordinated debentures		7,729			7,727		7,724
Income before income taxes		89,347			113,408		107,713
Income tax expense		35,600			40,914		36,240
Contribution to consolidated net income	$	53,747		$	72,494	$	71,473

2008 vs. 2007

Contribution to consolidated net income from natural gas operations decreased $18.7 million in 2008 compared to 2007. The decline in contribution was primarily caused by lower other income and higher operating expenses partially offset by margin increases and reduced financing costs.

Operating margin increased $7 million, or one percent, between 2008 and 2007. Customer growth accounted for $6 million of the increase and rate relief contributed $4 million. Differences in heating demand caused primarily by weather variations between periods resulted in a $1 million operating margin increase as warmer-than-normal temperatures were experienced during both periods (during 2008, operating margin was negatively impacted by $11 million, while the negative impact in 2007 was $12 million). In both years Southwest experienced extreme warm weather during the fourth quarter which more than offset colder than normal temperatures earlier in the year. Conservation, energy efficiency, and the impact of challenging economic conditions on consumption resulted in a $4 million decline.

Operations and maintenance expense increased $7.5 million, or two percent, principally due to the impact of general cost increases. Labor efficiencies, primarily from the conversion to electronic meter reading and other cost containment efforts, mitigated the increase in operations and maintenance expense.

Depreciation expense increased $9.2 million, or six percent, as a result of additional plant in service. Average gas plant in service for 2008 increased $244 million, or six percent, compared to 2007. This was attributable to the upgrade of existing operating facilities and the expansion of the system to accommodate customer growth.

Other income decreased $18.3 million between 2008 and 2007. This was primarily due to negative returns on long-term investments (COLI) in 2008 ($12 million) compared to positive returns in 2007 ($1.2 million) and a reduction in interest income between years ($2.3 million) primarily due to the full recovery of previously deferred purchased gas cost receivables.

Net financing costs decreased $3.3 million between 2008 and 2007 primarily due to lower average debt outstanding and reduced interest rates associated with Southwest’s commercial credit facility.

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2007 vs. 2006

Contribution to consolidated net income from natural gas operations increased $1 million in 2007 compared to 2006. The improvement in contribution resulted from higher operating margin, partially offset by increased operating expenses and a reduction in other income.

Operating margin increased $35 million between 2006 and 2007. The rate relief component of the increase was $18 million ($15 million in Arizona and $3 million in California). Customer growth contributed $14 million toward the operating margin increase as the Company added a net 29,000 customers during 2007, an increase of about two percent. Differences in heating demand, caused primarily by weather variations, accounted for the remaining $3 million increase in operating margin as warmer-than-normal temperatures were experienced during both years (during 2007 the estimated negative weather-related impact was about $12 million, while the negative impact during 2006 was approximately $15 million). Of note were significantly warmer-than-normal temperatures throughout Southwest service territories in November 2007, with Arizona experiencing its warmest November on record (during the past 113 years).

Operations and maintenance expense increased $10.4 million, or three percent, between years reflecting general cost increases and incremental operating costs associated with serving additional customers. Higher uncollectible expenses also contributed to the increase.

Depreciation expense increased $10.4 million, or seven percent, as a result of additional plant in service. Average gas plant in service for 2007 increased $284 million, or eight percent, compared to 2006. This was attributable to the upgrade of existing operating facilities and the expansion of the system to accommodate customer growth.

General taxes increased $2.6 million primarily as a result of a favorable nonrecurring property tax settlement recognized in April 2006. In addition, on average, property tax rates declined between years, largely offsetting the higher property tax base resulting from plant additions.

Other income decreased $5.2 million as compared to 2006 primarily as a result of a reduction in interest income due to the collection of previously deferred purchased gas costs and reduced returns on long-term investments. The prior year also included $1 million of interest income on the favorable nonrecurring property tax settlement referred to above.

Net financing costs increased $872,000, or one percent, between years primarily due to interest expense associated with deferred PGA balance payables and higher rates on variable-rate debt, partially offset by lower average debt outstanding.

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

Rates and Regulatory Proceedings

General Rate Relief and Rate Design

Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management continues to work with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such a rate structure is in place in California and progress has been made in Nevada, as decoupling legislation and related changes to existing regulations were approved during 2008 which will provide an opportunity for Southwest to file for a decoupling mechanism in the next Nevada general rate case. Southwest continues to pursue rate design changes in Arizona.

Arizona General Rate Case. Southwest filed a general rate application with the Arizona Corporation Commission (“ACC”) in the third quarter of 2007 requesting an increase in authorized operating revenues of $50.2 million. The request was due to increases in Southwest’s operating costs, investments in infrastructure to serve new customers, and the increased costs of capital to fund those investments. The Company requested a return on rate base of 9.45% and a return on equity of 11.25%.

In addition, declining average residential usage has hindered the Company’s ability to earn the returns previously authorized by the ACC. A rate structure that would encourage energy efficiency and also shield the Company and its customers from weather-related volatility was also proposed. A revenue decoupling mechanism that would separate the recovery of fixed costs from volumetric usage and a weather normalization mechanism that would protect customers from higher bills in extreme cold weather and protect the Company from cost under-recoveries in unseasonably warmer weather were both included in the rate design proposal. The Company also requested an increase of $3.10 in the monthly residential basic service charge. Southwest requested the new rates become effective October 2008. Hearings were held in June 2008.

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The ACC issued its Order in this filing, and rates were made effective, in December 2008. The Order provided for a revenue increase of $33.5 million based on an overall rate of return of 8.86% and a 10% return on equity. Rate design changes will allow approximately 46 percent of the revenue increase to be recovered in fixed charges and the remainder from the volumetric margin component of rates. While the ACC did not adopt the decoupling mechanisms, they did acknowledge that Southwest raised valid potential customer benefits and savings associated with these rate design proposals. A recommendation was approved that Southwest provide an empirical study to allow the ACC to consider future proposals. A six-year historical study showing the results of decoupling on customer margin will be submitted in April 2009. The ACC also initiated a separate proceeding in the second half of 2008 which will study the potential benefits of decoupling on conservation.

California General Rate Cases. Southwest filed a general rate application with the California Public Utilities Commission (“CPUC”) in December 2007 requesting an increase in authorized operating revenues of $9.1 million in the Company’s southern California, northern California and South Lake Tahoe rate jurisdictions with a proposed effective date of January 2009. The request was due to increases in Southwest’s operating costs, investments in new infrastructure to serve customers, and the increased costs of capital to fund those investments. As part of the filing, Southwest also requested that the authorized levels of margin revert to being recognized on a seasonally adjusted basis rather than in equal monthly amounts throughout the year to better reflect the seasonal nature of Southwest’s revenue stream. In addition to the margin balancing mechanism that has been in place since the last general rate case, this filing proposed a Post Test Year (“PTY”) ratemaking mechanism for the period 2010 through 2013. The PTY mechanism is designed to recognize the effects of inflation and capital expenditures between general rate cases.

An all-party settlement was approved by the CPUC in November 2008 with rates effective January 2009. In addition, attrition increases were approved to be effective for the years 2010-2013 of 2.95% in southern and northern California and $100,000 per year for the South Lake Tahoe rate jurisdiction. The decision authorized an increase of $2.4 million in southern California, a decrease of $1 million in northern California, and a $1.8 million increase for South Lake Tahoe, with 75 percent of the increase, or $1.4 million implemented in 2009 and the remaining $400,000 deferred to 2010. The settlement provided for a 10.5% return on equity. The return to a seasonal margin methodology will result in significant quarterly swings in reported margin, with an overall state-wide increase of $12.8 million in the first quarter, a decrease of $2 million in the second quarter, a decrease of $9 million in the third quarter, and a $1 million increase for the fourth quarter. The CPUC also authorized lower depreciation rates which will reduce annualized depreciation expense by $3 million.

California Attrition Filings. In October 2007, Southwest made its 2008 annual attrition filing with the CPUC requesting a $2 million increase in operating margin. The increase in customer rates was approved and became effective January 2008.

Nevada General Rate Case. Southwest filed a Notice of Filing in February 2009 and is currently preparing to file a general rate case in the second quarter of 2009 using a test year ended November 2008. The current regulations allow for a period of both certification adjustments (post test period) and pro-forma adjustments up to 210 days subsequent to the original general rate case filing date, which will assist in reducing the regulatory lag effect experienced in the past. Southwest intends to request a decoupling mechanism in conjunction with this filing based on recently established Public Utilities Commission of Nevada (“PUCN”) rules. Management has not yet determined the amount of rate relief to be requested.

FERC General Rate Case. Paiute Pipeline Company, a subsidiary of the Company, filed a general rate case with the Federal Energy Regulatory Commission (“FERC”) in February 2009. The filing fulfills an obligation from the settlement agreement reached in the 2005 Paiute general rate case. The application requests an increase in operating revenues of approximately $4 million. New rates are anticipated to go into effect subject to refund within 180 days of filing.

PGA Filings

The rate schedules in all of Southwest’s service territories contain provisions that permit adjustments to rates as the cost of purchased gas changes. These deferred energy provisions and purchased gas adjustment clauses are collectively referred to as “PGA” clauses. Differences between gas costs recovered from customers and amounts paid for gas by Southwest result in over- and under-collections. At December 31, 2008, over-collections in all three states resulted in a liability of $33.1 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions). 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.

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

	2008			2007
Arizona	$	(9.6	)	$	33.9
Northern Nevada		(1.5	)		(9.2	)
Southern Nevada		(19.9	)		(36.7	)
California		(2.1	)		(0.1	)
	$	(33.1	)	$	(12.1	)

Arizona PGA Filings. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits measured on a twelve-month rolling average. A temporary surcharge was in place from February 2006 through May 2008 to help accelerate the recovery of the previously under-collected balance. A prudence review of gas costs is conducted in conjunction with general rate cases.

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

Nevada Gas Cost Filings. In Nevada, quarterly gas cost changes, that are based on a twelve-month rolling average, are utilized. Annual deferred energy account adjustments are subject to a prudence review and audit of the natural gas costs incurred.

Gas Price Volatility Mitigation

Over the past five years the weighted-average delivered cost of natural gas has ranged from a low of $5.70 per dekatherm in 2004 to a high of $8.40 per dekatherm in 2008. Price volatility is expected to continue throughout 2009. Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and fixed-for-floating swap contracts (“Swaps”) for about half of its annual normal weather supply needs under its volatility mitigation programs. For the 2008/2009 heating season, fixed-price contracts range in price from approximately $6 to $13 per dekatherm. The notional amounts under the Swaps are approximately 6.5 million dekatherms at December 31, 2008. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities, and on the spot market. Prices for these contracts are not known until the month of purchase.

Capital Resources and Liquidity

Cash on hand and cash flows from operations have generally been sufficient over the past two years to provide for net investing activities (primarily construction expenditures and property additions). During the same two-year period, the Company has been able to reduce the net amount of debt outstanding (including short-term borrowings). The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt (including subordinated debentures and short-term borrowings).

To facilitate future financings, the Company has a universal shelf registration statement providing for the issuance and sale of registered securities from time to time, which may consist of secured debt, unsecured debt, preferred stock, or common stock. The number and dollar amount of securities issued under the universal shelf registration statement, which was filed with the SEC and automatically declared effective in December 2008, will be determined at the time of the offerings and presented in the applicable prospectuses.

Cash Flows

Operating Cash Flows. Cash flows provided by consolidated operating activities decreased $51 million in 2008 as compared to 2007. The primary driver of the change was the significant collection of previously deferred purchased gas costs in 2007 (as the deferred PGA balance went from an under-collection of $77 million at December 31, 2006 to a net over-collection of $12 million at December 31, 2007). Operating cash flows were also impacted by a decrease in net income between years, partially offset by higher depreciation and amortization.

In February 2008, the Economic Stimulus Act of 2008 (“Act”) was signed into law. This Act provides a 50 percent bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2008. Southwest estimates the bonus depreciation deduction deferred the payment of approximately $23 million of federal income taxes during 2008 to future periods.

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Investing Cash Flows. Cash used in consolidated investing activities decreased $79 million in 2008 as compared to 2007 primarily due to reductions in construction expenditures and equipment purchases, a result of the new housing market slowdown. Net collections of customer advances decreased approximately $20 million between 2008 and 2007, another consequence of the construction slowdown.

Financing Cash Flows. Cash used in consolidated financing activities increased $46 million during 2008 as compared to 2007. The Company permanently retired approximately $100 million in long-term utility debt. An additional $50 million of IDRBs were also redeemed (and replaced with a new $50 million issuance of IDRBs, see Note 6). Included in long-term debt issuances for 2008 are approximately $49 million borrowed under NPL’s line of credit. An identical amount is included in retirement of long-term debt. Dividends paid increased in 2008 as compared to 2007 as a result of a February 2008 Board of Directors’ decision to increase the quarterly dividend to 22.5 cents per share, effective with the June 2008 payment and due to an increase in the number of shares outstanding.

The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.

2008 Construction Expenditures

Southwest continues to experience customer growth, albeit at a much slower pace than in the recent past. During the three-year period ended December 31, 2008, total gas plant increased from $3.5 billion to $4.3 billion, or at an annual rate of seven percent. Customer growth was the primary reason for the plant increase as the Company set 178,000 meters resulting in 106,000 net new customers during the three-year period.

During 2008, construction expenditures for the natural gas operations segment were $279 million. Approximately 64 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 were $261 million and provided approximately 82 percent of construction expenditures and dividend requirements. Other necessary funding was provided by external financing activities, existing credit facilities, and refundable construction advances.

2008 Financing Activity

In September 2008, the Company issued $50 million in Clark County, Nevada variable-rate 2008 Series A IDRBs, due 2038, supported by a letter of credit with JPMorgan Chase Bank. The proceeds from the 2008 Series A IDRBs were used by the Company to redeem its $50 million 2003 Series B variable-rate IDRBs. From 2003 through September 2008, the Company had utilized an insurance policy from Ambac Assurance Corporation (“Ambac”) to support its $50 million 2003 Series B variable-rate IDRBs. The 2003 Series B were designed to be repriced weekly in an auction market. Since mid-February 2008, the 2003 Series B weekly auctions had failed amid the uncertainty surrounding bond insurers. In June 2008, Standard & Poor’s and Moody’s Investors Service, the two largest ratings companies, downgraded Ambac and assigned a “negative” outlook to the new rating. This resulted in the Company’s 2003 Series B being downgraded from a AAA rating to a AA rating. As a result of the failed auctions and the ratings downgrade, the Company had been required to price the 2003 Series B at a predetermined maximum auction-rate (200 percent of the one-month LIBOR rate at the time of redemption).

In December 2008, the Company announced a tender offer to purchase for cash up to $75 million of the Clark County, Nevada 4.75% 2006 Series A, 5.00% 2004 Series B, and 5.25% 2003 Series D IDRBs. In accordance with the tender offer, the Company purchased $31.2 million of the 4.75% 2006 Series A IDRBs, $43.8 million of the 5.00% 2004 Series B IDRBs, and none of the 5.25% 2003 Series D IDRBs as the $75 million limit set forth in the tender offer had been met. The net gain on the bonds tendered (approximately $14 million after expenses and proportionate elimination of previously deferred issuance costs) was deferred and recorded as a regulatory liability and will be accreted to income over the remaining lives of the IDRBs partially tendered.

During 2008, the Company issued shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (“DRSPP), Employee Investment Plan, and Stock Incentive Plan, raising approximately $35 million. No shares were issued through the Equity Shelf Program (“ESP”) in 2008 and the Company does not anticipate issuing additional shares under this plan (the $16.7 million of remaining capacity under the ESP is expected to expire unused in March 2009). The DRSPP and Employee Investment Plan are expected to be a source of capital in the future, albeit at lower levels.

Additionally in 2008, Southwest partially offset capital outlays by collecting approximately $22 million in net advances and contributions from third-party contractors. At December 31, 2008, the balance of refundable construction advances was approximately $90 million.

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2009 Construction Expenditures and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2011 will be approximately $720 million. Of this amount, approximately $260 million are expected to be incurred in 2009. During the three-year period, cash flows from operating activities of Southwest are estimated to fund over 85 percent of the gas operations total construction expenditures and dividend requirements. Southwest also has $200 million in long-term debt due in 2011. During the three-year period, the Company expects to raise $40 million to $50 million from its various common stock programs. Any cash requirements not met by operating activities are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest 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.

Liquidity

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

On an interim basis, Southwest generally defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2006, the combined balance in PGA accounts totaled an under-collection of $77 million. During 2007, collections and changes in the prices paid for natural gas resulted in the PGA having a net over-collected balance of $12 million at December 31, 2007. At December 31, 2008, the combined balance in the PGA accounts totaled an over-collection of $33 million. See PGA Filings for more information on recent regulatory filings.

In the current challenging capital market environment, the Company has not to date had significant impacts on its financing activities. Limited availability of commercial paper and temporarily higher interest rates on the 2003 Series B $50 million IDRBs (due to the credit rating downgrade of the insurer) are the most significant impacts the Company has experienced. The Company has a $300 million credit facility that expires in May 2012. Southwest has designated $150 million of the $300 million facility as long-term debt and the remaining $150 million for working capital purposes. At December 31, 2008, $150 million was outstanding on the long-term portion and $55 million was outstanding on the short-term portion of the credit facility. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances. This credit facility has been, and is expected to continue to be, adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing. Management believes the Company currently has a solid liquidity position.

Credit Ratings

The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., the better the rating, the lower the cost to borrow funds).

The Company’s unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is Baa3 with a stable outlook. Moody’s applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.

The Company’s unsecured long-term debt rating from Fitch, Inc. (“Fitch”) is BBB. Fitch has assigned a stable outlook to the rating. 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 & Poor’s Ratings Services (“S&P”) is BBB- with a positive outlook. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB- indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal.

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A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency. The foregoing securities ratings are subject to change at any time in the discretion of the applicable ratings agencies. Numerous factors, including many that are not within the Company’s control, are considered by the ratings agencies in connection with assigning securities ratings.

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2008, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.4 billion in additional debt and meet the leverage ratio requirement and has an approximate $600 million cushion in equity relating to the minimum net worth requirement.

Inflation

Inflation can impact the Company’s results of operations. Natural gas, labor, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to the cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor 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.

Off-Balance Sheet Arrangements

All Company debt is recorded on its balance sheets. The Company has long-term operating leases, which are described in Note 2—Utility Plant of the Notes to Consolidated Financial Statements, and included in the Contractual Obligations Table below.

Contractual Obligations

The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statement of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Company’s contractual obligations at December 31, 2008 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2009		2010-2011		2012-2013		Thereafter
Operating activities:
Operating leases (Note 2)	$	26	$	6	$	7	$	5	$	8
Gas purchase obligations		562		442		120		—		—
Pipeline capacity		949		186		338		68		357
Derivatives—Swaps (Note 12)		14		14		—		—		—
Other commitments		17		11		5		1		—
Financing activities:
Subordinated debentures to Southwest Gas Capital II (Note 5)		103		—		—		—		103
Interest on subordinated debentures to Southwest Gas Capital II (Note 5)		268		8		15		15		230
Long-term debt (Note 6)		1,193		8		210		351		624
Interest on long-term debt		804		65		112		64		563
Other		16		—		—		—		16
Total	$	3,952	$	740	$	807	$	504	$	1,901

Obligations for Operating Activities: The table provides a summary of the Company’s obligations associated with operating activities. Operating leases represent multi-year obligations for office rent and certain equipment. Gas purchase obligations include fixed-price and variable-rate gas purchase contracts covering approximately 111 million dekatherms. Fixed-price contracts range in price from approximately $6 to $13 per dekatherm. Variable-price contracts reflect minimum contractual obligations.

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Southwest has pipeline capacity contracts for firm transportation service, both on a short- and long-term basis, with several companies for all of its service territories, some with terms extending to 2044. Southwest also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise. Costs associated with these pipeline capacity contracts are a component of the cost of gas sold and are recovered from customers primarily through the PGA mechanism.

Obligations for Financing Activities: Contractual obligations for financing activities are debt obligations consisting of scheduled principal and interest payments over the life of the debt.

Other: Estimated funding for pension and other postretirement benefits during calendar year 2009 is $23 million. The Company has an insignificant amount of liabilities in connection with the application of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”

Results of Construction Services

Year Ended December 31,	2008		2007		2006
(Thousands of dollars)
Construction revenues	$	353,348	$	337,322	$	297,364
Operating expenses:
Construction expenses		311,745		292,319		252,859
Depreciation and amortization		27,382		25,424		22,310
Operating income		14,221		19,579		22,195
Other income (expense)		63		73		135
Net interest deductions		1,823		2,036		1,686
Income before income taxes		12,461		17,616		20,644
Income tax expense		5,235		6,864		8,257
Contribution to consolidated net income	$	7,226	$	10,752	$	12,387

2008 vs. 2007

The 2008 contribution to consolidated net income from construction services decreased $3.5 million from 2007. The decrease reflects unfavorable weather conditions during the first quarter of 2008 and a reduction in the volume of higher profit new construction work resulting from the general slowdown in the new housing market. Increased costs for fuel and fuel-related products and services also contributed to the decrease.

Revenues increased $16 million due primarily to additional work under two existing blanket contracts and new bid work. The construction revenues above include NPL contracts with Southwest totaling $63.1 million in 2008 and $71.4 million in 2007. NPL accounts for the services provided to Southwest at contractual (market) prices.

Construction expenses rose $19.4 million due primarily to increased costs for labor, direct materials, subcontractors and fuel. Interest expense decreased $213,000 due to a reduction in long-term borrowing.

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 continued slowdown in construction activities observed in regional and national markets during 2008 is expected to negatively impact the amount of work received under existing blanket contracts, the amount of bid work, and the equipment resale market in 2009.

2007 vs. 2006

The 2007 contribution to consolidated net income from construction services decreased $1.6 million from 2006. The decrease reflects higher general and administrative expenses, interest expense, and lower gains on sales of equipment. Unfavorable working conditions due to poor weather during the first quarter of 2007 also contributed to the decrease.

Revenues increased $40 million due primarily to several new contracts and an improvement in the amount and profitability of new bid work. The construction revenues above include NPL contracts with Southwest totaling $71.4 million in 2007 and $80.6 million in 2006. NPL accounts for the services provided to Southwest at contractual (market) prices.

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Construction expenses increased $39.5 million due primarily to incremental costs associated with revenue growth including labor and other administrative expenses. Interest expense increased $350,000 due to additional long-term borrowings for purchases of new equipment.

Recently Issued Accounting Pronouncements

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

Title		Month of Issue	Effective Date
SFAS No. 141(R),	“Business Combinations.”	December 2007	January 1, 2009
SFAS No. 160,	“Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.”	December 2007	January 1, 2009
SFAS No. 161,	“Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.”	March 2008	January 1, 2009
FSP SFAS 132(R)-1	“Employers’ Disclosures about Postretirement Benefit Plan Assets.”	December 2008	December 31, 2009

Application of Critical Accounting Policies

A critical accounting policy is one which is very important to the portrayal of the financial condition and results of a company, and requires the most difficult, subjective, or complex judgments of management. The need to make estimates about the effect of items that are uncertain is what makes these judgments difficult, subjective, and/or complex. Management makes subjective judgments about the accounting and regulatory treatment of many items and bases its estimates on historical experience and on various other assumptions that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. The following are accounting policies that are critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1—Summary of Significant Accounting Policies.

Regulatory Accounting

Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated enterprises (including SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”) and reflect the effects of the ratemaking process. As such, the Company is allowed to defer as regulatory assets, costs that otherwise would be expensed if it is probable that future recovery from customers will occur. The Company reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset (which would be recognized as current-period expense). Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4—Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.

Accrued Utility Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, revenues for natural gas that has been delivered but not yet billed are accrued. This accrued utility revenue is estimated each month based on daily sales volumes, applicable rates, analyses reflecting significant historical trends, weather, and experience. In periods of extreme weather conditions, the interplay of these assumptions could impact the variability of the accrued utility revenue estimates.

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

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taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recoverable from or refunded to customers in future rates. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The Company regularly assesses financial statement tax provisions to identify any change in the regulatory treatment or tax-related estimates, assumptions, or enacted tax rates that could have a material impact on cash flows, the financial position, and/or results of operations of the Company.

Accounting for Pensions and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Company’s pension obligations and costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans.

At December 31, 2008, the Company raised the discount rate to 6.75% from 6.50% at December 31, 2007. The weighted-average rate of compensation increase was lowered to 3.75% from 4.00%. The asset return assumption remains at 8.00%. The impact of the discount rate and salary change assumption on the funded status of the pension plan at year end and the expense level for 2009 are not significant. However, asset returns during 2008 were substantially below assumed returns. As a result, pension expense for 2009 is estimated to increase by $2 million. Absent future asset returns in excess of the assumed rate or pension contributions to make up for return shortfalls, additional increases to expense beyond 2009 are likely.

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, 2008 were included as exhibits to the 2008 Annual Report on Form 10-K which was filed with the SEC. The Company is also required to file an annual CEO certification regarding corporate governance listing standards compliance with the New York Stock Exchange (“NYSE”). The most recent annual CEO certification, dated May 8, 2008, was filed with the NYSE in May 2008.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, 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. For example, statements regarding operating margin earned, customer growth, the composition of our customer base, price volatility, risks and costs associated with having non-performing assets associated with new homes, timing of improvements in the housing market, timing for completion of estimated future construction expenditures, forecasted operating cash flows, funding sources of cash requirements, sufficiency of working capital, bank lending practices, ability to raise funds and receive external financing, the amount and form of any such financing, liquidity, the recovery of under-collected PGA balances, the impact of the application of certain accounting standards, certain tax benefits from the Economic Stimulus Act of 2008, statements regarding future gas prices, gas purchase contracts and derivative financial interests, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, conditions in the housing market, our ability to recover costs through our PGA mechanisms, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital

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requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, renewal of franchises, easements and rights-of-way, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

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

	2008				2007				Dividends Declared
	High		Low		High		Low		2008		2007
First quarter	$	30.48	$	25.14	$	39.95	$	35.30	$	0.225	$	0.215
Second quarter		31.74		27.90		39.77		33.10		0.225		0.215
Third quarter		33.29		27.56		34.22		26.45		0.225		0.215
Fourth quarter		30.78		21.11		30.97		26.61		0.225		0.215
									$	0.900	$	0.860

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 17, 2009, there were 22,046 holders of record of common stock, and the market price of the common stock was $23.37.

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 declared was 21.5 cents per share throughout 2007 and 22.5 cents per share throughout 2008. In February 2009, the Board of Directors increased the quarterly dividend payout from 22.5 cents to 23.75 cents per share, effective with the June 2009 payment.

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SOUTHWEST GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008			2007
(Thousands of dollars, except par value)
ASSETS
Utility plant:
Gas plant	$	4,258,727		$	4,043,936
Less: accumulated depreciation		(1,347,093	)		(1,261,867	)
Acquisition adjustments, net		1,632			1,812
Construction work in progress		70,041			61,419
Net utility plant (Note 2)		2,983,307			2,845,300
Other property and investments		124,781			143,097
Current assets:
Cash and cash equivalents		26,399			31,991
Accounts receivable, net of allowances (Note 3)		168,829			203,660
Accrued utility revenue		72,600			74,900
Income taxes receivable, net		32,069			14,286
Deferred income taxes (Note 11)		14,902			6,965
Deferred purchased gas costs (Note 4)		—			33,946
Prepaids and other current assets (Notes 2 and 4)		123,277			136,711
Total current assets		438,076			502,459
Deferred charges and other assets (Notes 4 and 12)		274,220			179,332
Total assets	$	3,820,384		$	3,670,188
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—44,191,535 and 42,805,706 shares) (Note 10)	$	45,822		$	44,436
Additional paid-in capital		770,463			732,319
Accumulated other comprehensive income (loss), net (Note 9)		(19,426	)		(12,850	)
Retained earnings		240,982			219,768
Total equity		1,037,841			983,673
Subordinated debentures due to Southwest Gas Capital II (Note 5)		100,000			100,000
Long-term debt, less current maturities (Note 6)		1,185,474			1,266,067
Total capitalization		2,323,315			2,349,740
Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)		7,833			38,079
Short-term debt (Note 7)		55,000			9,000
Accounts payable		191,434			220,731
Customer deposits		83,468			75,019
Accrued general taxes		41,490			44,637
Accrued interest		19,699			21,290
Deferred purchased gas costs (Note 4)		33,073			46,088
Other current liabilities (Notes 4 and 12)		77,898			73,088
Total current liabilities		509,895			527,932
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 11)		387,539			347,497
Taxes payable		3,480			4,387
Accumulated removal costs (Note 4)		169,000			146,000
Other deferred credits (Notes 4 and 9)		427,155			294,632
Total deferred income taxes and other credits		987,174			792,516
Total capitalization and liabilities	$	3,820,384		$	3,670,188

The accompanying notes are an integral part of these statements.

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SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2008			2007			2006
(In thousands, except per share amounts)
Operating revenues:
Gas operating revenues	$	1,791,395		$	1,814,766		$	1,727,394
Construction revenues		353,348			337,322			297,364
Total operating revenues		2,144,743			2,152,088			2,024,758
Operating expenses:
Net cost of gas sold		1,055,977			1,086,194			1,033,988
Operations and maintenance		338,660			331,208			320,803
Depreciation and amortization		193,719			182,514			168,964
Taxes other than income taxes		36,780			37,553			34,994
Construction expenses		311,745			292,319			252,859
Total operating expenses		1,936,881			1,929,788			1,811,608
Operating income		207,862			222,300			213,150
Other income and (expenses):
Net interest deductions (Notes 6 and 7)		(84,919	)		(88,472	)		(87,253	)
Net interest deductions on subordinated debentures (Note 5)		(7,729	)		(7,727	)		(7,724	)
Other income (deductions)		(13,406	)		4,923			10,184
Total other income and (expenses)		(106,054	)		(91,276	)		(84,793	)
Income before income taxes		101,808			131,024			128,357
Income tax expense (Note 11)		40,835			47,778			44,497
Net income	$	60,973		$	83,246		$	83,860
Basic earnings per share (Note 14)	$	1.40		$	1.97		$	2.07
Diluted earnings per share (Note 14)	$	1.39		$	1.95		$	2.05
Average number of common shares outstanding		43,476			42,336			40,566
Average shares outstanding (assuming dilution)		43,775			42,714			40,975

The accompanying notes are an integral part of these statements.

P34

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2008			2007			2006
(Thousands of dollars)
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	60,973		$	83,246		$	83,860
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		193,719			182,514			168,964
Deferred income taxes		36,135			16,068			3,909
Changes in current assets and liabilities:
Accounts receivable, net of allowances		34,831			22,268			(27,847	)
Accrued utility revenue		2,300			(1,600	)		(4,900	)
Deferred purchased gas costs		20,931			89,149			32,408
Accounts payable		(29,297	)		(45,008	)		6,263
Accrued taxes		(21,837	)		(16,537	)		3,198
Other current assets and liabilities		(3,636	)		24,972			24,156
Gains on sale		(2,068	)		(2,530	)		(3,968	)
Changes in undistributed stock compensation		3,825			3,324			4,361
AFUDC and property-related changes		(561	)		(871	)		(1,156	)
Changes in other assets and deferred charges		(5	)		(4,971	)		(1,780	)
Changes in other liabilities and deferred credits		4,438			1,111			(1,753	)
Net cash provided by operating activities		299,748			351,135			285,715
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(300,217	)		(340,875	)		(345,325	)
Changes in customer advances		4,044			24,407			27,988
Return of exchange fund deposit		28,000			—			—
Miscellaneous inflows		17,656			5,257			10,771
Miscellaneous outflows		(2,693	)		(20,724	)		(5,560	)
Net cash used in investing activities		(253,210	)		(331,935	)		(312,126	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		35,391			31,495			67,829
Dividends paid		(38,705	)		(35,993	)		(33,238	)
Issuance of long-term debt, net		103,875			128,594			92,400
Retirement of long-term debt		(198,691	)		(142,091	)		(84,397	)
Change in long-term portion of credit facility		—			3,000			(3,000	)
Change in short-term debt		46,000			9,000			(24,000	)
Net cash provided by (used in) financing activities		(52,130	)		(5,995	)		15,594
Change in cash and cash equivalents		(5,592	)		13,205			(10,817	)
Cash at beginning of period		31,991			18,786			29,603
Cash at end of period	$	26,399		$	31,991		$	18,786
Supplemental information:
Interest paid, net of amounts capitalized	$	91,211		$	93,335		$	92,533
Income taxes paid	$	22,472		$	45,025		$	39,682

The accompanying notes are an integral part of these statements.

P35

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
(In thousands, except per share amounts)
DECEMBER 31, 2005	39,328		$	40,958	$	628,248	$	(41,645	)	$	123,574		$	751,135
Common stock issuances	2,442			2,442		70,010								72,452
Net income											83,860			83,860		$	83,860
Additional minimum pension liability adjustment, net of $20.3 million of tax (Note 9)								33,047						33,047			33,047
Net adjustment to adopt SFAS No. 158, net of $3.1 million of tax (Note 9)								(5,068	)					(5,068	)
Dividends declared
Common: $0.82 per share											(34,001	)		(34,001	)
2006 Comprehensive Income																$	116,907
DECEMBER 31, 2006	41,770			43,400		698,258		(13,666	)		173,433			901,425
Common stock issuances	1,036			1,036		34,061								35,097
Net income											83,246			83,246		$	83,246
Net actuarial gain arising during the period, less amortization of unamortized benefit plan cost, net of $500,000 of tax (Note 9)								816						816			816
Dividends declared
Common: $0.86 per share											(36,911	)		(36,911	)
2007 Comprehensive Income																$	84,062
DECEMBER 31, 2007	42,806			44,436		732,319		(12,850	)		219,768			983,673
Common stock issuances	1,386			1,386		38,144								39,530
Net income											60,973			60,973		$	60,973
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of $4 million of tax (Note 9)								(6,576	)					(6,576	)		(6,576	)
Dividends declared
Common: $0.90 per share											(39,759	)		(39,759	)
2008 Comprehensive Income																$	54,397
DECEMBER 31, 2008	44,192	*	$	45,822	$	770,463	$	(19,426	)	$	240,982		$	1,037,841

* At December 31, 2008, 1.8 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 731,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10). During 2008, no shares were issued in at-the-market offerings through the Equity Shelf Program.

The accompanying notes are an integral part of these statements.

P36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Summary of Significant Accounting Policies

Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing and transporting natural gas 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. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.

Basis of Presentation. The Company follows generally accepted accounting principles (“GAAP”) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with GAAP as applied to regulated companies and as prescribed by federal agencies and the commissions of the various states in which the utility operates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction, less contributions in aid of construction.

Deferred Purchased Gas Costs. The various regulatory commissions have established procedures to enable Southwest to adjust its billing rates for changes in the cost of natural gas purchased. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred. Generally, these deferred amounts are recovered or refunded within one year.

Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date.

For regulatory and financial reporting purposes, investment tax credits (“ITC”) related to gas utility operations are deferred and amortized over the life of related fixed assets.

Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less.

Accumulated Removal Costs. Approved regulatory practices allow Southwest to include in depreciation expense a component to recover removal costs associated with utility plant retirements. In accordance with the Securities and Exchange Commission’s (“SEC”) position on presentation of these amounts, management has reclassified $169 million and $146 million, as of December 31, 2008 and 2007, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheet.

Gas Operating Revenues. Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs and state and local laws, regulations, and agreements. An estimate of the amount of natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized as accrued utility revenue.

The Company acts as an agent for state and local taxing authorities in the collection and remission of a variety of taxes, including franchise fees, sales and use taxes, and surcharges. These taxes are not included in gas operating revenues, except for certain franchise fees in California operating jurisdictions which are not significant. The Company uses the net classification method to report taxes collected from customers to be remitted to governmental authorities.

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Construction Revenues. The majority of NPL contracts are performed under unit price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two weeks or less. Revenues are recorded as installations are completed. Long-term fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements.

Construction Expenses. The construction expenses classification in the income statement includes payroll expenses, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, and office-related fixed costs of the Company’s construction services subsidiary, NPL.

Net Cost of Gas Sold. Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of derivative instruments (Swaps). Also included are the net impacts of PGA deferrals and recoveries.

Operations and Maintenance Expense. For financial reporting purposes, operations and maintenance expense includes Southwest’s operating and maintenance costs associated with serving utility customers, uncollectible expense, administrative and general salaries and expense, employee benefits expense, and injuries and damages expense.

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

Allowance for Funds Used During Construction (“AFUDC”). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The Company capitalized $1.2 million in 2008, $1.3 million in 2007, and $2.8 million in 2006 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 $635,000, $619,000, and $1.4 million for 2008, 2007 and 2006, 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.

Other Income (Deductions). The following table provides the composition of significant items included in Other income (deductions) on the consolidated statements of income (thousands of dollars):

	2008			2007			2006
Gain/(loss) on company-owned life insurance policies	$	(12,041	)	$	1,165		$	2,740
Interest income		2,212			4,448			7,843
Miscellaneous income and expense		(3,577	)		(690	)		(399	)
Total other income (deductions)	$	(13,406	)	$	4,923		$	10,184

Included in the table above is the gain/(loss) on company owned life insurance policies (“COLI”). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the gain/(loss) in the cash surrender value components of COLI policies as they progress towards the ultimate death benefits are also recorded without tax consequences.

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Earnings Per Share. Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of additional weighted-average common stock equivalents (stock options, performance shares, and restricted stock units). Unless otherwise noted, the term “Earnings Per Share” refers to Basic EPS. A reconciliation of the shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.

	2008	2007	2006
(In thousands)
Average basic shares	43,476	42,336	40,566
Effect of dilutive securities:
Stock options	60	147	195
Performance shares	193	210	214
Restricted stock units	46	21	—
Average diluted shares	43,775	42,714	40,975

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. None of the reclassifications affected previously reported net income.

Recently Issued Accounting Pronouncements. In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations.” SFAS No. 141 (revised 2007) provides guidelines for the presentation and measurement of assets and liabilities acquired in a business combination and requires the disclosure of all information necessary to evaluate the nature and financial effect of a business combination. The provisions of SFAS No. 141 (revised 2007) are effective for the Company for acquisitions that occur on or after January 1, 2009. 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 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” SFAS No. 160 requires all entities to report minority interests in subsidiaries as equity in the consolidated financial statements. The provisions of SFAS No. 160 are effective for the Company beginning January 1, 2009. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.” SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities. The provisions of SFAS No. 161 are effective for the Company beginning January 1, 2009. The adoption of the standard will require additional disclosures but is not expected to have a material impact on the financial position or results of operations of the Company.

In December 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” FSP SFAS 132(R)-1 requires companies to enhance disclosures about the plan assets of a defined benefit pension or other postretirement plan. Companies will be required to disclose how investment decisions are made, the major plan asset categories, the inputs and valuation techniques used to measure the fair value of plan assets, the level within the fair value hierarchy in which the fair value measurements in their entirety fall, the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period, and significant concentrations of risk within plan assets. The provisions of FSP SFAS 132(R)-1 are effective for the Company beginning with 2009 year-end. The Company is evaluating what impact this standard might have on its disclosures.

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Note 2—Utility Plant

Net utility plant as of December 31, 2008 and 2007 was as follows (thousands of dollars):

December 31,	2008			2007
Gas plant:
Storage	$	19,094		$	17,403
Transmission		262,271			256,696
Distribution		3,615,253			3,419,799
General		228,282			219,126
Other		133,827			130,912
		4,258,727			4,043,936
Less: accumulated depreciation		(1,347,093	)		(1,261,867	)
Acquisition adjustments, net		1,632			1,812
Construction work in progress		70,041			61,419
Net utility plant	$	2,983,307		$	2,845,300

Depreciation and amortization expense on gas plant was $162 million in 2008, $155 million in 2007, and $145 million in 2006.

In October 2007, the Company sold its Southern Nevada Division operations facility for $35 million. Of the proceeds, $28 million was held by JP Morgan Property Exchange, Inc. at December 31, 2007 (and reflected in Prepaids and other current assets on Southwest’s balance sheet) to facilitate like-kind exchange tax treatment for the new land and facilities to be developed. The funds were returned to Southwest in April 2008. The gain on the sale (approximately $20.5 million) was deferred and recorded as a regulatory liability. The amount and timing of the amortization of the gain will be addressed in a future Nevada general rate case. The Company is currently building two separate facilities in Southern Nevada to better serve the customer base in Las Vegas. During construction of the new facilities, the Company is leasing back the operations facility (see details below). The Company’s corporate headquarters complex is not affected by these transactions.

Operating Leases and Rentals. Southwest leases a portion of its corporate headquarters office complex in Las Vegas, the southern Nevada operations facility, and its administrative offices in Phoenix. The leases provide for current terms which expire in 2017, 2009, 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 2009 through 2013 and $8 million cumulatively thereafter. The rental payments for the southern Nevada operations facility are $875,000 in 2009 when the lease expires. The rental payments for the Phoenix administrative offices are $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 $23.4 million in 2008, $23.9 million in 2007, and $19.2 million in 2006. These amounts include NPL lease expenses of approximately $13.9 million in 2008, $15.9 million in 2007, and $11.5 million in 2006, for various short-term operating leases of equipment and temporary office sites.

The following is a schedule of future minimum lease payments for significant non-cancelable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2008 (thousands of dollars):

Year Ending December 31,
2009	$	6,306
2010		3,474
2011		2,971
2012		2,627
2013		2,521
Thereafter		8,408
Total minimum lease payments	$	26,307

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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, 2008, the gas utility customer accounts receivable balance was $131 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, 2005	$	2,301
Additions charged to expense		5,805
Accounts written off, less recoveries		(5,085	)
Balance, December 31, 2006		3,021
Additions charged to expense		7,178
Accounts written off, less recoveries		(7,252	)
Balance, December 31, 2007		2,947
Additions charged to expense		7,047
Accounts written off, less recoveries		(6,206	)
Balance, December 31, 2008	$	3,788

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Note 4—Regulatory Assets and Liabilities

Natural gas operations are subject to the regulation of the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”). Southwest accounting policies conform to generally accepted accounting principles applicable to rate-regulated enterprises, principally SFAS No. 71, and reflect the effects of the ratemaking process. SFAS No. 71 allows for the deferral as regulatory assets, costs that otherwise would be expensed, if it is probable future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

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

December 31,	2008			2007
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	208,830		$	92,655
Unrealized loss on non-trading derivatives (Swaps) (2)		14,440			—
Deferred purchased gas costs (3)		—			33,946
Accrued purchased gas costs (4)		37,400			40,100
Unamortized premium on reacquired debt (5)		17,772			17,215
Other (8)		29,223			34,020
		307,665			217,936
Regulatory liabilities:
Deferred purchased gas costs (3)		(33,073	)		(46,088	)
Accumulated removal costs		(169,000	)		(146,000	)
Unrealized gain on non-trading derivatives (Swaps) (2)		(292	)		—
Deferred gain on southern Nevada division operations facility (6)		(20,522	)		(20,522	)
Rate refunds due customers (7)		—			(12,474	)
Unamortized gain on reacquired debt (6)		(14,099	)		—
Other (6)		(1,668	)		(1,401	)
Net regulatory assets (liabilities)	$	69,011		$	(8,549	)

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

(2) Regulatory asset included in Prepaids and other current assets ($14.4 million) in 2008. Regulatory liability included in Other deferred credits ($292,000) in 2008. The actual amounts, when realized at settlement, become a component of gas costs. (See Note 12)

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

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

(5) Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovered over life of debt instruments.

(6) Included in Other deferred credits on the Consolidated Balance Sheets.

(7) Included in Other current liabilities on the Consolidated Balance Sheets.

(8) Other regulatory assets include deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as margin and interest-tracking accounts, amounts associated with accrued absence time, net SFAS No. 109 income taxes, and deferred post-retirement benefits other than pensions. Recovery periods vary.

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Note 5—Preferred Trust Securities and Subordinated Debentures

In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the distribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures are redeemable at the option of the Company after August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest. In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Trust Securities. As of December 31, 2008, 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.

Although the Company owns 100 percent of the common voting securities of Trust II, under Interpretation No. 46 “Consolidation of Variable Interest Entities (revised December 2003)”, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. As a result, the $103.1 million Subordinated Debentures are shown on the balance sheet of the Company, net of the $3.1 million Common Securities, as Subordinated debentures due to Southwest Gas Capital II. Payments and amortizations associated with the Subordinated Debentures are classified on the consolidated statements of income as Net interest deductions on subordinated debentures. The estimated market values of the subordinated debentures at December 31, 2008 and 2007 were $85 million and $96 million, respectively.

(In millions)	Liability		Maximum Exposure to Loss
Subordinated debentures	$	100	$	—

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Note 6—Long-Term Debt

December 31,	2008					2007
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011	$	200,000		$	206,200	$	200,000		$	216,872
Notes, 7.625%, due 2012		200,000			203,880		200,000			214,172
8% Series, due 2026		75,000			79,163		75,000			82,274
Medium-term notes, 6.27% series, due 2008		—			—		25,000			25,152
Medium-term notes, 7.59% series, due 2017		25,000			25,560		25,000			26,946
Medium-term notes, 7.78% series, due 2022		25,000			25,793		25,000			27,486
Medium-term notes, 7.92% series, due 2027		25,000			26,245		25,000			26,975
Medium-term notes, 6.76% series, due 2027		7,500			7,004		7,500			7,183
Unamortized discount		(2,837	)		—		(3,443	)		—
		554,663					579,057
Revolving credit facility and commercial paper, due 2012		150,000			150,000		150,000			150,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2003 Series B, due 2038		—			—		50,000			50,000
2008 Series A, due 2038		50,000			50,000		—			—
Fixed-rate bonds:
6.10% 1999 Series A, due 2038		12,410			9,375		12,410			12,519
5.95% 1999 Series C, due 2038		14,320			10,585		14,320			14,353
5.55% 1999 Series D, due 2038		8,270			5,752		8,270			8,116
5.45% 2003 Series C, due 2038		30,000			32,966		30,000			28,955
5.25% 2003 Series D, due 2038		20,000			15,859		20,000			18,691
5.80% 2003 Series E, due 2038		15,000			15,006		15,000			14,481
5.25% 2004 Series A, due 2034		65,000			43,929		65,000			60,588
5.00% 2004 Series B, due 2033		31,200			24,278		75,000			68,616
4.85% 2005 Series A, due 2035		100,000			62,862		100,000			90,925
4.75% 2006 Series A, due 2036		24,855			18,316		56,000			49,243
Unamortized discount		(3,605	)		—		(4,531	)		—
		467,450					541,469
Other		21,194			20,993		33,620			33,998
		1,193,307					1,304,146
Less: current maturities		(7,833	)				(38,079	)
Long-term debt, less current maturities	$	1,185,474				$	1,266,067

The Company has a $300 million credit facility scheduled to expire in May 2012. The Company uses $150 million of the $300 million as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the facility are calculated at either the London Interbank Offering Rate plus an applicable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. At December 31, 2008, $55 million in borrowings were outstanding on the short-term portion of the credit facility (see Note 7—Short-Term Debt) and $150 million was outstanding on the long-term portion.

In September 2008, the Company issued $50 million in Clark County, Nevada variable-rate 2008 Series A Industrial Development Revenue Bonds (“IDRBs”), due 2038, supported by a letter of credit with JPMorgan Chase Bank. The proceeds from the 2008 Series A IDRBs were used by the Company to redeem its $50 million 2003 Series B variable-rate IDRBs. From 2003 through September 2008, the Company had utilized an insurance policy from Ambac Assurance Corporation (“Ambac”) to support its $50 million 2003 Series B variable-rate IDRBs. The

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2003 Series B were designed to be repriced weekly in an auction market. Since mid-February 2008, the 2003 Series B weekly auctions had failed amid the uncertainty surrounding bond insurers. In June 2008, Standard & Poor’s and Moody’s Investors Service, the two largest ratings companies, downgraded Ambac and assigned a “negative” outlook to the new rating. This resulted in the Company’s 2003 Series B being downgraded from a AAA rating to a AA rating. As a result of the failed auctions and the ratings downgrade, the Company had been required to price the 2003 Series B at a predetermined maximum auction-rate (200 percent of the one-month LIBOR rate at the time of redemption).

In early December 2008, the Company announced a tender offer to purchase for cash up to $75 million of the Clark County, Nevada 4.75% 2006 Series A, 5.00% 2004 Series B, and 5.25% 2003 Series D IDRBs. In accordance with the tender offer, the Company purchased $31.2 million of the 4.75% 2006 Series A IDRBs, $43.8 million of the 5.00% 2004 Series B IDRBs, and none of the 5.25% 2003 Series D IDRBs (as the $75 million limit set forth in the tender offer had been met). The Company engaged Banc of America Securities LLC as the exclusive dealer manager for the tender offer. The net gain on the bonds tendered (approximately $14 million after expenses and proportionate elimination of previously deferred issuance costs) was deferred and recorded as a regulatory liability and will be accreted to income over the remaining lives of the IDRBs partially tendered.

The effective interest rates on the 2003 Series A and 2008 Series A variable-rate IDRBs were 1.85 percent and 2.29 percent, respectively, at December 31, 2008. The effective interest rate on the 2003 Series A and B variable-rate IDRBs was 4.51 percent and 4.79 percent, respectively, at December 31, 2007. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 1.74 percent and 4.46 percent at December 31, 2008 and 2007, respectively.

The fair value of the revolving credit facility and the variable-rate IDRBs approximates carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for December 31, 2008 and 2007, as applicable, and other secondary sources which are customarily consulted for data of this kind. The fair values for certain securities disclosed for 2008 reflect the impacts of a constrained securities market and may differ significantly from those determined in a normal functioning credit market.

Estimated maturities of long-term debt for the next five years are $7.8 million, $6.6 million, $203.9 million, $350.8 million, and $91,000, respectively.

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2008, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.4 billion in additional debt and meet the leverage ratio requirement and has an approximate $600 million cushion in equity relating to the minimum net worth requirement.

Note 7—Short-Term Debt

As discussed in Note 6, Southwest has a $300 million credit facility that expires in May 2012, of which $150 million has been designated by management for working capital purposes (and related outstanding amounts are shown as short-term debt). Southwest had $55 million in short-term borrowings outstanding on the credit facility at December 31, 2008 and $9 million at December 31, 2007. The weighted-average interest rate on these borrowings was 1.04 percent at December 31, 2008.

Note 8—Commitments and Contingencies

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

Note 9—Pension and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees and a separate unfunded supplemental retirement plan (“SERP”) which is limited to officers. Southwest also provides postretirement benefits other than pensions (“PBOP”) to its qualified retirees for health care, dental, and life insurance benefits.

In 2006, the FASB issued SFAS No. 158, which requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in their balance sheets. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards are recognized in accumulated other

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comprehensive income under stockholders’ equity, net of tax, until they are amortized as a component of net periodic benefit cost. SFAS No. 158 did not change how net periodic pension and postretirement costs are accounted for and reported in the income statement. The Company adopted the provisions of SFAS No. 158 effective December 31, 2006.

In accordance with SFAS No. 71, the Company has established a regulatory asset for the portion of the total amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through rates in future periods. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are recognized as components of net periodic pension costs each year.

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

	Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Adjustments to adopt SFAS No. 158:
Net actuarial loss, net of $44.9 million of tax	$	(73,323	)	$	(62,464	)	$	(8,045	)	$	(2,814	)
Net transition obligation, net of $2 million of tax		(3,225	)		—			—			(3,225	)
Prior service credit, net of $9,000 of tax		14			14			—			—
Reversal of additional minimum pension liability, net of $14.4 million of tax		23,551			16,432			7,119			—
Estimated amounts recoverable through rates, net of $29.4 million of tax		47,915			41,876			—			6,039
Total amounts recognized in accumulated other comprehensive income	$	(5,068	)	$	(4,142	)	$	(926	)	$	—

Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors of the Company. They are designed to enhance capital, maintain minimum liquidity required for retirement plan operations and effectively manage pension assets.

A target portfolio of investments in the qualified retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. 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	59 to 71
Debt securities	31 to 37
Other	up to 5

The Company’s pension costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan.

SFAS No. 87 “Employer’s Accounting for Pensions” states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. In determining the discount rate, the Company matches the plan’s projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are made in increments of 25 basis points.

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At year end 2008, the Company raised the discount rate to 6.75% from 6.50% at December 31, 2007. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was lowered to 3.75% from 4.00%. The asset return assumption remains at 8.00%. The impact of the discount rate and salary change assumption on the funded status of the pension plan at year end and the expense level for 2009 are not significant. However, asset returns during 2008 were substantially below assumed returns. As a result, the funded status of the qualified retirement plan decreased substantially from 2007 to 2008 and pension expense for 2009 is estimated to increase by $2 million.

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

	2008									2007
	Qualified Retirement Plan			SERP			PBOP			Qualified Retirement Plan			SERP			PBOP
	(Thousands of dollars)									(Thousands of dollars)
Change in benefit obligations
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$	509,862		$	32,605		$	36,504		$	495,803		$	33,657		$	39,107
Service cost		16,108			97			730			16,491			153			811
Interest cost		32,491			2,041			2,324			29,244			1,948			2,304
Actuarial loss (gain)		(15,199	)		(594	)		(2,529	)		(14,648	)		(810	)		(4,647	)
Benefits paid		(20,251	)		(2,363	)		(1,114	)		(17,028	)		(2,343	)		(1,071	)
Benefit obligation at end of year (PBO/PBO/APBO)		523,011			31,786			35,915			509,862			32,605			36,504
Change in plan assets
Market value of plan assets at beginning of year		415,263			—			26,473			388,706			—			24,828
Actual return on plan assets		(105,552	)		—			(7,657	)		17,230			—			854
Employer contributions		34,000			2,363			620			26,355			2,343			791
Benefits paid		(20,251	)		(2,363	)		—			(17,028	)		(2,343	)		—
Market value of plan assets at end of year		323,460			—			19,436			415,263			—			26,473
Funded status at year end	$	(199,551	)	$	(31,786	)	$	(16,479	)	$	(94,599	)	$	(32,605	)	$	(10,031	)
Weighted-average assumptions (benefit obligation)
Discount rate		6.75	%		6.75	%		6.75	%		6.50	%		6.50	%		6.50	%
Weighted-average rate of compensation increase		3.75	%		3.75	%		3.75	%		4.00	%		4.00	%		4.00	%
Asset Allocation
Equity securities		59	%					74	%		60	%					76	%
Debt securities		35	%					18	%		35	%					17	%
Other		6	%					8	%		5	%					7	%
Total		100	%		N/A			100	%		100	%		N/A			100	%

The accumulated benefit obligation for the retirement plan was $457 million and $442 million, and for the SERP was $28.4 million and $31 million at December 31, 2008 and 2007, respectively.

Estimated funding for the plans above during calendar year 2009 is approximately $23 million of which $22 million pertains to the retirement plan. The Pension Protection Act of 2006 provides for benefit restrictions to future retirees if the funded status of the retirement plan, determined in accordance with IRS rules, falls below certain thresholds (80%—modest restrictions, 60%—severe restrictions). The funded status is determined on the date of the plan year-end (July 31 for the Company). Management will monitor the funded status of the plan and could, at its discretion, increase plan funding levels above the minimum in order to avoid or minimize benefit restrictions.

Pension benefits expected to be paid for each of the next five years beginning with 2009 are the following: $23 million, $24 million, $26 million, $27 million, and $29 million. Pension benefits expected to be paid during 2014 to 2018 total $176 million. Retiree welfare benefits expected to be paid for each of the next five years beginning with 2009 are the following: $1.6 million, $1.7 million, $1.8 million, $1.9 million, and $2 million. Retiree welfare benefits expected to be paid during 2014 to 2018 total $14 million. SERP benefits expected to be paid for each of the next five years beginning with 2009 are approximately $2.5 million. SERP benefits expected to be paid during 2014 to 2018 total $12 million. No assurance can be made that actual funding and benefits paid will match our estimates.

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For PBOP measurement purposes, the per capita cost of covered health care benefits medical rate trend assumption is seven percent declining to five percent. 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 medical trend rate assumption noted above applies to the benefit obligations of pre-1989 retirees only.

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2008			2007			2006			2008			2007			2006			2008			2007			2006
(Thousands of dollars)
Service cost	$	16,108		$	16,491		$	16,284		$	97		$	153		$	211		$	730		$	811		$	854
Interest cost		32,491			29,244			26,805			2,041			1,948			1,893			2,324			2,304			2,118
Expected return on plan assets		(34,714	)		(33,030	)		(30,608	)		—			—			—			(2,138	)		(2,144	)		(1,817	)
Amortization of prior service costs (credits)		(11	)		(11	)		(11	)		—			—			9			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			867			867
Amortization of net actuarial loss		3,104			5,007			5,352			997			1,131			1,244			—			57			168
Net periodic benefit cost	$	16,978		$	17,701		$	17,822		$	3,135		$	3,232		$	3,357		$	1,783		$	1,895		$	2,190
Weighted-average assumptions (net benefit cost)
Discount rate		6.50	%		6.00	%		5.75	%		6.50	%		6.00	%		5.75	%		6.50	%		6.00	%		5.75	%
Expected return on plan assets		8.00	%		8.50	%		8.50	%		8.00	%		8.50	%		8.50	%		8.00	%		8.50	%		8.50	%
Weighted-average rate of compensation increase		4.00	%		3.75	%		3.30	%		4.00	%		3.75	%		3.30	%		4.00	%		3.75	%		3.30	%

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income

	2008												2007
	Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)	$	131,738		$	125,067		$	(595	)	$	7,266		$	(3,012	)	$	1,155		$	(809	)	$	(3,358	)
Amortization of prior service credit (b)		11			11			—			—			11			11			—			—
Amortization of transition obligation (b)		(867	)		—			—			(867	)		(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(4,101	)		(3,104	)		(997	)		—			(6,195	)		(5,007	)		(1,131	)		(57	)
Regulatory adjustment		(116,175	)		(109,776	)		—			(6,399	)		8,747			4,465			—			4,282
Recognized in other comprehensive (income) loss	$	10,606		$	12,198		$	(1,592	)	$	—		$	(1,316	)	$	624		$	(1,940	)	$	—
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	32,502		$	29,176		$	1,543		$	1,783		$	21,512		$	18,325		$	1,292		$	1,895

The table above discloses the net gain or loss, prior service cost, and transition amount recognized in other comprehensive income, separated into (a) amounts initially recognized in other comprehensive income, and (b) amounts subsequently recognized as adjustments to other comprehensive income as those amounts are amortized as components of net periodic benefit cost.

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Related Tax Effects Allocated to Each Component of Other Comprehensive Income

	2008									2007
	Before-Tax Amount			Tax (Expense) or Benefit (a)			Net-of-Tax Amount			Before-Tax Amount			Tax (Expense) or Benefit (a)			Net-of-Tax Amount
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial loss (gain)	$	131,738		$	(50,060	)	$	81,678		$	(3,012	)	$	1,145		$	(1,867	)
Amortization of prior service credit		11			(4	)		7			11			(4	)		7
Amortization of transition obligation		(867	)		329			(538	)		(867	)		329			(538	)
Amortization of net loss		(4,101	)		1,558			(2,543	)		(6,195	)		2,354			(3,841	)
Regulatory adjustment		(116,175	)		44,147			(72,028	)		8,747			(3,324	)		5,423
Other comprehensive (income) loss	$	10,606		$	(4,030	)	$	6,576		$	(1,316	)	$	500		$	(816	)

(a) Tax amounts are calculated using a 38 percent rate.

The estimated net loss that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year is $4.3 million for the qualified retirement plan and $900,000 for the SERP. The estimated amounts for the PBOP that will be amortized from regulatory assets into net periodic benefit cost over the next year are $400,000 related to net loss and $870,000 for the transition obligation. The estimated prior service costs (credits) for the qualified retirement plan and SERP that will be amortized over the next year are not significant.

The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is three and one-half percent of an employee’s annual compensation. The cost of the plan was $4.4 million in 2008, $3.8 million in 2007, and $3.6 million in 2006. NPL has a separate plan, the cost and liability for which are not significant.

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

Note 10—Stock-Based Compensation

At December 31, 2008, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. The stock option plan and the performance share stock plan were both in existence prior to January 1, 2006 and were accounted for in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payment” using the modified prospective transition method. Under the modified prospective transition method, expense is recognized for any new awards granted after the effective date and for the unvested portion of awards granted prior to the effective date. Total stock-based compensation expense recognized in the consolidated statements of income for the years ended December 31, 2008, December 31, 2007, and December 31, 2006 were $4.9 million (net of related tax benefits of $3 million), $4.9 million (net of related tax benefits of $3 million), and $3.3 million (net of related tax benefits of $1.6 million), respectively.

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Under the option plan, the Company granted options to purchase shares of common stock to key employees and outside directors. The option grants in 2006 consumed the remaining options that could be issued under the option plan and no future grants are anticipated. 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. The following assumptions were used in the valuation calculation:

	2006
Dividend yield	2.48 to 2.82	%
Risk-free interest rate range	4.91 to 5.06	%
Expected volatility range	15	%
Expected life	6 years

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

	2008				2007				2006
	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	798		$	26.85	957		$	26.26	1,475		$	23.70
Granted during the year	—			—	—			—	252			32.60
Exercised during the year	(64	)		23.70	(158	)		23.24	(749	)		23.30
Forfeited during the year	(3	)		27.72	(1	)		33.07	(6	)		26.81
Expired during the year	—			—	—			—	(15	)		28.09
Outstanding at year end	731		$	27.12	798		$	26.85	957		$	26.26
Exercisable at year end	663		$	26.55	561		$	25.50	413		$	23.31

The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding options was $661,000, $3.1 million, and $11.6 million at December 31, 2008, December 31, 2007, and December 31, 2006, respectively. The aggregate intrinsic value of exercisable options was $661,000, $2.7 million, and $6.2 million at December 31, 2008, December 31, 2007, and December 31, 2006, respectively. The aggregate intrinsic value of exercised options was $339,000, $1 million, and $11.3 million during 2008, 2007, and 2006, respectively. The market value of Southwest Gas stock was $25.22, $29.77, and $38.37 at December 31, 2008, December 31, 2007, and December 31, 2006, respectively.

The weighted-average remaining contractual life for outstanding options was 6.1 years for 2008. The weighted-average remaining contractual life for exercisable options was 6 years for 2008. No options were granted in 2007 or 2008; the weighted-average grant-date fair value of options granted was $5.92 for 2006. The following table summarizes information about stock options outstanding at December 31, 2008 (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
$17.94 to $23.40	249	4.7 Years	$	22.61	249	$	22.61
$24.50 to $26.10	222	6.4 Years	$	25.94	222	$	25.94
$28.75 to $33.07	260	7.1 Years	$	32.46	192	$	32.39

As of December 31, 2008, there was $147,000 of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over the next year. The total fair value of options vested was $824,000, $1.2 million, and $1 million during 2008, 2007, and 2006, respectively. The Company received $1.5 million in cash from the exercise of options during 2008 and a corresponding tax benefit of $125,000 which was recorded in additional paid-in capital.

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The following table summarizes the status of the Company’s nonvested options as of December 31, 2008 (thousands of options):

	Number of options		Weighted- average grant date fair value
Nonvested at the beginning of the year	237		$	5.25
Granted	—			—
Vested	(166	)		4.98
Forfeited	(3	)		4.67
Nonvested at December 31, 2008	68		$	5.93

Under the performance share stock plan, the Company may issue performance shares to encourage key employees to remain in its employment and to achieve short-term and long-term performance goals. Plan participants are eligible to receive a cash bonus (i.e., short-term incentive) and performance shares (i.e., long-term incentive). The performance shares vest three years after grant (and are subject to a final adjustment as determined by the Board of Directors) and are then issued as common stock.

In 2007, the Company instituted a restricted stock/unit plan to award restricted stock and restricted stock/units to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. The restricted stock/units vest 40 percent at the end of year one and 30 percent at the end of years two and three.

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2008 (thousands of shares):

	Performance Shares		Weighted- average grant date fair value		Restricted Stock/Units		Weighted- average grant date fair value
Nonvested at beginning of year	292		$	29.63	49		$	38.34
Granted	102		$	29.31	54		$	27.25
Dividends	9				3
Forfeited	—		$	—	(1	)	$	31.52
Vested and issued*	(136	)	$	25.81	(21	)	$	37.34
Nonvested at December 31, 2008	267		$	31.38	84		$	31.15

* Includes shares converted for taxes and retiree payouts.

The average grant date fair value of performance shares granted in 2007 and 2006 was $38.21 and $26.97, respectively. The average grant date fair value of restricted stock/units granted in 2007 was $38.48.

Note 11—Income Taxes

The Company adopted the provisions of FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes”, on January 1, 2007. Upon adoption, the Company identified $1.4 million in uncertain tax liabilities. As of December 31, 2008 and 2007, the Company had $1.4 million of uncertain tax liabilities which, if recognized, would favorably impact the effective tax rate. There was no change to the balance of unrecognized tax benefits during 2008 and the Company does not expect a significant increase or decrease in its unrecognized tax benefits in the next twelve months. The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. Tax-related interest income of $900,000 and $1 million is included in the consolidated statements of income for the years ended December 31, 2008 and December 31, 2007, respectively. Tax-related interest receivable of $700,000 and $1 million is included in the consolidated balance sheets as of December 31, 2008 and December 31, 2007, respectively.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is subject to examinations by the Internal Revenue Service for years after 2004, and is subject to examination by the various state taxing authorities for years after 2003.

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

	2008		2007
Unrecognized tax benefits at beginning of year	$	1,445	$	1,445
Gross increases—tax positions in prior period		—		—
Gross decreases—tax positions in prior period		—		—
Gross increases—current period tax positions		—		—
Gross decreases—current period tax positions		—		—
Settlements		—		—
Lapse of statute of limitations		—		—
Unrecognized tax benefits at end of year	$	1,445	$	1,445

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

Year Ended December 31,	2008		2007		2006
Current:
Federal	$	5,420	$	37,668	$	29,916
State		1,106		6,989		4,830
		6,526		44,657		34,746
Deferred:
Federal		32,569		2,813		9,385
State		1,740		308		366
		34,309		3,121		9,751
Total income tax expense	$	40,835	$	47,778	$	44,497

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

Year Ended December 31,	2008			2007			2006
Deferred federal and state:
Property-related items	$	53,978		$	26,300		$	28,372
Purchased gas cost adjustments		(15,918	)		(24,972	)		(22,188	)
Employee benefits		(1,884	)		2,263			(3,223	)
Injuries and damages reserves		(48	)		85			4,543
All other deferred		(951	)		313			3,115
Total deferred federal and state		35,177			3,989			10,619
Deferred ITC, net		(868	)		(868	)		(868	)
Total deferred income tax expense	$	34,309		$	3,121		$	9,751

The consolidated effective income tax rate for the period ended December 31, 2008 and the two prior periods differ from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:

Year Ended December 31,	2008		2007		2006
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Net state taxes	2.4		2.7		2.5
Property-related items	0.2		0.4		0.6
Effect of income tax settlements	(0.9	)	(0.4	)	(1.3	)
Tax credits	(0.9	)	(0.7	)	(0.7	)
Company owned life insurance	4.0		(0.5	)	(0.9	)
All other differences	0.3		—		(0.5	)
Consolidated effective income tax rate	40.1	%	36.5	%	34.7	%

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

December 31,	2008			2007
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	5,353		$	5,890
Employee benefits		39,693			33,779
Alternative minimum tax credit		20,457			22,518
Other		6,686			5,267
		72,189			67,454
Deferred tax liabilities:
Property-related items, including accelerated depreciation		410,588			356,609
Regulatory balancing accounts		5,317			21,235
Property-related items previously flowed through		6,161			7,176
Unamortized ITC		8,595			9,463
Debt-related costs		5,143			5,291
Other		9,022			8,212
		444,826			407,986
Net deferred tax liabilities	$	372,637		$	340,532
Current	$	(14,902	)	$	(6,965	)
Noncurrent		387,539			347,497
Net deferred tax liabilities	$	372,637		$	340,532

Note 12—Derivatives and Fair Value Measurements

In managing its natural gas supply portfolios, Southwest has historically entered into fixed and variable-price contracts, which qualify as derivatives under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS No. 133”). In 2008, Southwest also began utilizing fixed-for-floating swap contracts (“Swaps”) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business under SFAS No. 133 and are exempt from its fair value provisions. The variable-price contracts have no significant market value and are likewise not affected by SFAS No. 133’s fair value provisions. Swaps are subject to the fair value provisions and must be recorded at fair value.

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on approximately 50 percent of its natural gas portfolios. The maturities of the Swaps highly correlate to actual purchases of natural gas, during timeframes ranging from January 2009 through March 2010. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts (approximately 6.5 million dekatherms at December 31, 2008). Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.

Pursuant to regulatory deferral accounting treatment under SFAS No. 71, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps settle, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. In accordance with this described treatment, at December 31, 2008, Southwest recorded the fair values of the Swaps in Other current liabilities ($14.4 million) and Deferred charges and other assets ($292,000). Corresponding offsetting amounts were recorded in Prepaids and other current assets ($14.4 million) and in Other deferred credits ($292,000). Due to the provisions of SFAS No. 71, neither changes in the fair value of the contracts nor settled amounts have a direct effect on earnings or other comprehensive income. The estimated fair values of the derivatives were determined using future natural gas index prices (as more fully described below). The Company has master netting arrangements with each counterparty that provide for the net settlement of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets.

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In January 2008, the Company adopted SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 states that a fair value measurement should be based on the assumptions that market participants would use in pricing the asset or liability and establishes a fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1—quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access at the measurement date.

Level 2—inputs other than quoted prices included within Level 1 that are observable for similar assets or liabilities, either directly or indirectly.

Level 3—unobservable inputs for the asset or liability. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

The estimated fair values of Southwest’s Swaps were determined at December 31, 2008 using NYMEX futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2008.

				Fair Value Measurements Using:
	Total			Quoted Prices in Active Markets for Identical Financial Assets and Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
				Level 1		Level 2			Level 3
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets—swaps	$	—		$	—	$	—		$	—
Deferred charges and other assets—swaps		292			—		292			—
Liabilities at fair value:
Other current liabilities—swaps		(14,440	)		—		(14,440	)		—
Other deferred credits—swaps		—			—		—			—
Net Assets (Liabilities)	$	(14,148	)	$	—	$	(14,148	)	$	—

Note 13—Segment Information

Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, 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, 2008 and 2007, accounts receivable for these services totaled $6.6 million and $6.1 million, respectively, which were not eliminated during consolidation.

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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, 2008 is as follows (thousands of dollars):

2008	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,791,395	$	290,218				$	2,081,613
Intersegment sales		—		63,130					63,130
Total	$	1,791,395	$	353,348				$	2,144,743
Interest revenue	$	2,107	$	105				$	2,212
Interest expense	$	90,825	$	1,823				$	92,648
Depreciation and amortization	$	166,337	$	27,382				$	193,719
Income tax expense	$	35,600	$	5,235				$	40,835
Segment income	$	53,747	$	7,226				$	60,973
Segment assets	$	3,680,327	$	140,057				$	3,820,384
Capital expenditures	$	279,254	$	20,963				$	300,217
2007	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,814,766	$	265,937				$	2,080,703
Intersegment sales		—		71,385					71,385
Total	$	1,814,766	$	337,322				$	2,152,088
Interest revenue	$	4,366	$	82				$	4,448
Interest expense	$	94,163	$	2,036				$	96,199
Depreciation and amortization	$	157,090	$	25,424				$	182,514
Income tax expense	$	40,914	$	6,864				$	47,778
Segment income	$	72,494	$	10,752				$	83,246
Segment assets	$	3,518,304	$	152,096	$	(212	)	$	3,670,188
Capital expenditures	$	312,412	$	28,463				$	340,875
2006	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,727,394	$	216,753				$	1,944,147
Intersegment sales		—		80,611					80,611
Total	$	1,727,394	$	297,364				$	2,024,758
Interest revenue	$	7,711	$	132				$	7,843
Interest expense	$	93,291	$	1,686				$	94,977
Depreciation and amortization	$	146,654	$	22,310				$	168,964
Income tax expense	$	36,240	$	8,257				$	44,497
Segment income	$	71,473	$	12,387				$	83,860
Segment assets	$	3,352,074	$	136,654	$	(3,763	)	$	3,484,965
Capital expenditures	$	305,914	$	39,411				$	345,325

(a) Construction services segment assets include income taxes payable of $212,000 in 2007, which was netted against gas operations segment income taxes receivable, net during consolidation. Construction services segment assets include deferred tax assets of $3 million and income taxes payable of $758,000 in 2006, which were netted against gas operations segment deferred tax liabilities and income taxes receivable, net during consolidation.

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Note 14—Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2008
Operating revenues	$	813,607	$	447,304		$	374,422		$	509,410
Operating income		104,685		18,256			2,900			82,021
Net income (loss)		49,152		(2,725	)		(16,686	)		31,232
Basic earnings (loss) per common share*		1.14		(0.06	)		(0.38	)		0.71
Diluted earnings (loss) per common share*		1.14		(0.06	)		(0.38	)		0.71
2007
Operating revenues	$	793,716	$	426,537		$	371,524		$	560,311
Operating income		101,325		18,405			8,569			94,001
Net income (loss)		49,764		(337	)		(9,318	)		43,137
Basic earnings (loss) per common share*		1.19		(0.01	)		(0.22	)		1.01
Diluted earnings (loss) per common share*		1.17		(0.01	)		(0.22	)		1.00
2006
Operating revenues	$	676,941	$	430,902		$	351,800		$	565,115
Operating income		89,895		26,681			4,167			92,407
Net income (loss)		44,180		3,709			(10,736	)		46,707
Basic earnings (loss) per common share*		1.12		0.09			(0.26	)		1.12
Diluted earnings (loss) per common share*		1.11		0.09			(0.26	)		1.11

* 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.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. 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, 2008. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 27, 2009

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of stockholders’ equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 27, 2009

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