Exhibit 13.01

CONSOLIDATED SELECTED FINANCIAL STATISTICS

Year Ended December 31,	2010			2009			2008			2007			2006
(Thousands of dollars, except per share amounts)
Operating revenues	$	1,830,371		$	1,893,824		$	2,144,743		$	2,152,088		$	2,024,758
Operating expenses		1,598,254			1,685,433			1,936,881			1,929,788			1,811,608
Operating income	$	232,117		$	208,391		$	207,862		$	222,300		$	213,150
Net income	$	103,877		$	87,482		$	60,973		$	83,246		$	83,860
Total assets at year end	$	3,984,193		$	3,906,292		$	3,820,384		$	3,670,188		$	3,484,965
Capitalization at year end
Common equity	$	1,166,996		$	1,102,086		$	1,037,841		$	983,673		$	901,425
Subordinated debentures		—			100,000			100,000			100,000			100,000
Long-term debt		1,124,681			1,169,357			1,185,474			1,266,067			1,286,354
	$	2,291,677		$	2,371,443		$	2,323,315		$	2,349,740		$	2,287,779
Common stock data
Common equity percentage of capitalization		50.9	%		46.5	%		44.7	%		41.9	%		39.4	%
Return on average common equity		9.1	%		8.1	%		6.0	%		8.8	%		10.3	%
Basic earnings per share	$	2.29		$	1.95		$	1.40		$	1.97		$	2.07
Diluted earnings per share	$	2.27		$	1.94		$	1.39		$	1.95		$	2.05
Dividends declared per share	$	1.00		$	0.95		$	0.90		$	0.86		$	0.82
Payout ratio		44	%		49	%		64	%		44	%		40	%
Book value per share at year end	$	25.60		$	24.44		$	23.48		$	22.98		$	21.58
Market value per share at year end	$	36.67		$	28.53		$	25.22		$	29.77		$	38.37
Market value per share to book value per share		143	%		117	%		107	%		130	%		178	%
Common shares outstanding at year end (000)		45,599			45,092			44,192			42,806			41,770
Number of common shareholders at year end		17,821			20,489			22,244			22,664			23,610
Ratio of earnings to fixed charges		2.87			2.46			2.01			2.25			2.25

23 Greener than you think

NATURAL GAS OPERATIONS

Year Ended December 31,	2010			2009			2008			2007			2006
(Thousands of dollars)
Sales	$	1,438,809		$	1,547,081		$	1,728,924		$	1,754,913		$	1,671,093
Transportation		73,098			67,762			62,471			59,853			56,301
Operating revenue		1,511,907			1,614,843			1,791,395			1,814,766			1,727,394
Net cost of gas sold		736,175			866,630			1,055,977			1,086,194			1,033,988
Operating margin		775,732			748,213			735,418			728,572			693,406
Expenses
Operations and maintenance		354,943			348,942			338,660			331,208			320,803
Depreciation and amortization		170,456			166,850			166,337			157,090			146,654
Taxes other than income taxes		38,869			37,318			36,780			37,553			34,994
Operating income	$	211,464		$	195,103		$	193,641		$	202,721		$	190,955
Contribution to consolidated net income	$	91,382		$	79,420		$	53,747		$	72,494		$	71,473
Total assets at year end	$	3,845,111		$	3,782,913		$	3,680,327		$	3,518,304		$	3,352,074
Net gas plant at year end	$	3,072,436		$	3,034,503		$	2,983,307		$	2,845,300		$	2,668,104
Construction expenditures and property additions	$	188,379		$	212,919		$	279,254		$	312,412		$	305,914
Cash flow, net
From operating activities	$	342,522		$	371,416		$	261,322		$	320,594		$	253,245
From (used in) investing activities		(178,685	)		(265,850	)		(237,093	)		(306,396	)		(277,980	)
From (used in) financing activities		(107,779	)		(81,744	)		(34,704	)		(5,347	)		15,989
Net change in cash	$	56,058		$	23,822		$	(10,475	)	$	8,851		$	(8,746	)
Total throughput (thousands of therms)
Residential		704,693			669,736			704,986			698,063			677,605
Small commercial		300,940			294,225			314,555			310,666			309,856
Large commercial		111,833			117,241			125,121			127,561			128,255
Industrial/Other		58,922			72,623			97,702			103,525			149,243
Transportation		998,600			1,043,894			1,164,190			1,128,422			1,175,238
Total throughput		2,174,988			2,197,719			2,406,554			2,368,237			2,440,197
Weighted average cost of gas purchased ($/therm)	$	0.62		$	0.71		$	0.84		$	0.81		$	0.79
Customers at year end		1,837,000			1,824,000			1,819,000			1,813,000			1,784,000
Employees at year end		2,349			2,423			2,447			2,538			2,525
Customer to employee ratio		782			753			743			714			706
Degree days – actual		1,998			1,824			1,902			1,850			1,826
Degree days – ten-year average		1,876			1,882			1,893			1,936			1,961

24 Southwest Gas Corporation

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, 2010, Southwest had 1,837,000 residential, commercial, industrial, and other natural gas customers, of which 991,000 customers were located in Arizona, 664,000 in Nevada, and 182,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2010, 54 percent of operating margin was earned in Arizona, 35 percent in Nevada, and 11 percent in California. During this same period, Southwest earned 86 percent of operating margin from residential and small commercial customers, 4 percent from other sales customers, and 10 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, primarily in Arizona, can have a significant impact on the margin and associated net income of the Company. A decoupled rate structure designed to mitigate the impact of weather variability as well as conservation on margin is utilized in the Nevada service territories. Weather impacts and conservation are also offset by the margin tracking mechanism in Southwest’s California service territories.

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 17 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, pipe replacement programs of utilities, 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 89 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

25 Greener than you think

Summary Operating Results

Year ended December 31,	2010		2009		2008
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	91,382	$	79,420	$	53,747
Construction services		12,495		8,062		7,226
Consolidated	$	103,877	$	87,482	$	60,973
Average number of common shares outstanding		45,405		44,752		43,476
Basic earnings per share
Consolidated	$	2.29	$	1.95	$	1.40
Natural Gas Operations
Operating margin	$	775,732	$	748,213	$	735,418

2010 Overview

Consolidated results for 2010 increased compared to 2009 due to improvements in both the natural gas and construction services segments. Basic earnings per share were $2.29 in 2010 compared to basic earnings per share of $1.95 in 2009.

Natural gas operations highlights include the following:

• Rate relief and improved weather significantly enhanced operating margin during 2010

• Operating margin increased more than $27 million, or four percent, compared to the prior year

• Operating expenses increased $11 million, or two percent, between years

• Net financing costs decreased $5 million between 2010 and 2009

• Southwest’s liquidity position remains strong

Construction services highlights include the following:

• Revenues in 2010 increased $40 million compared to 2009, and contribution to net income increased $4 million

Rate Relief.    During 2010, Southwest realized the benefits of rate relief in its Nevada and California regulatory jurisdictions which accounted for $18 million of incremental operating margin. See Rates and Regulatory Proceedings for additional details of the various rate decisions.

Weather and Conservation.    The rate structures in each of Southwest’s three states provide varying levels of protection from risks that drive operating margin volatility, particularly weather risk and conservation efforts. Southwest’s exposure to these risks on operating margin is largely limited to its Arizona operating areas as both Nevada and California operations are under decoupled rate structures. During 2010, the estimated weather impact on operating margin was a decrease of $10 million as Arizona experienced one of its warmest Decembers on record. By comparison, during 2009, weather resulted in an estimated negative operating margin impact of $18 million, thereby resulting in a favorable comparative impact between years.

26 Southwest Gas Corporation

Additionally, throughout 2009 and 2010 Southwest experienced a decline in consumption over and above the more typical impacts of conservation from improvements in new construction practices and energy efficient appliances. This excess decline was attributed to the impact of the difficult economic environment and, in particular, vacant homes. Southwest continues to note an excessive number of vacant homes as compared to historical levels. Consequently, further economic-related declines are possible.

In December 2010, the Arizona Corporation Commission (“ACC”) issued a Policy Statement which allows utilities to file proposals for alternative mechanisms including revenue per customer decoupling, in their next general rate case to address the financial disincentives to utilities of promoting energy efficiency. In anticipation of the Policy Statement, the Company’s recent Arizona rate case filing requested a rate structure to decouple recovery of the Company’s fixed costs from fluctuations in usage, both higher and lower, to enable the Company to aggressively advocate for increased energy efficiency by its customers by eliminating the existing financial disincentive. For more information see the Rates and Regulatory Proceedings discussion.

Customer Growth.    Southwest completed 18,000 and 16,000 first-time meter sets in 2009 and 2010, respectively. These meter sets led to 5,000 and 13,000 net additional active customers between years, respectively. Southwest continues to project net customer growth of 1% or less for 2011.

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 $193 million at December 31, 2010. 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 $70 million at December 31, 2010 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 2010, Southwest recorded in Other income (deductions) a net increase in the cash surrender values of its COLI policies of $9.8 million (including recognized net death benefits), compared to a net increase of $8.5 million in 2009. 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.    Southwest believes its liquidity position remains strong. Southwest has a $300 million credit facility maturing in May 2012, $150 million of which is designated for working capital needs. The facility is provided through a consortium of eight major banking institutions. Usage of the facility was minimal during 2010, even during the winter heating season when gas purchases normally require temporary financing, and there was no balance outstanding at December 31, 2010 leaving the entire $300 million available for long-term and working capital needs. The lower usage was primarily due to existing cash reserves, natural gas prices that were relatively stable, and gas cost-related rate mechanisms that favorably impacted operating cash flows. The current slowdown in housing construction has also allowed Southwest to fund construction expenditures primarily with internally generated cash.

27 Greener than you think

Results of Natural Gas Operations

Year Ended December 31,	2010		2009		2008
(Thousands of dollars)
Gas operating revenues	$	1,511,907	$	1,614,843	$	1,791,395
Net cost of gas sold		736,175		866,630		1,055,977
Operating margin		775,732		748,213		735,418
Operations and maintenance expense		354,943		348,942		338,660
Depreciation and amortization		170,456		166,850		166,337
Taxes other than income taxes		38,869		37,318		36,780
Operating income		211,464		195,103		193,641
Other income (deductions)		4,016		6,590		(13,469	)
Net interest deductions		75,113		74,091		83,096
Net interest deductions on subordinated debentures		1,912		7,731		7,729
Income before income taxes		138,455		119,871		89,347
Income tax expense		47,073		40,451		35,600
Contribution to consolidated net income	$	91,382	$	79,420	$	53,747

2010 vs. 2009

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

Operating margin increased more than $27 million between years. Rate relief provided $18 million toward the operating margin increase, consisting of $15 million in Nevada and $3 million in California. Differences in heating demand caused primarily by weather variations between years resulted in an $8 million operating margin increase as warmer-than-normal temperatures were experienced during both years (during 2010, operating margin was negatively impacted by $10 million, while the negative impact in 2009 was $18 million). Customer growth contributed $1 million of the operating margin increase.

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

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

28 Southwest Gas Corporation

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

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

2009 vs. 2008

Contribution to consolidated net income from natural gas operations increased $25.7 million in 2009 compared to 2008. The increase was a result of a $20 million improvement in other income, higher operating margin, and reduced financing costs, partially offset by an increase in operating expenses.

Operating margin increased $13 million between years. Rate relief provided $30 million toward the operating margin increase, consisting of $25 million in Arizona, $3 million in California, and $2 million in Nevada. Conservation, resulting from current economic conditions and energy efficiency, negatively impacted operating margin by an estimated $11 million. Differences in heating demand caused primarily by weather variations between years resulted in a $7 million operating margin decrease as warmer-than-normal temperatures were experienced during both years (during 2009, operating margin was negatively impacted by $18 million, while the negative impact in 2008 was $11 million). Customer growth contributed $1 million of the operating margin increase.

Operations and maintenance expense increased $10.3 million, or three percent, principally due to the impact of general cost increases and higher employee-related benefit costs. The increase was mitigated by slightly lower staffing levels.

Depreciation expense increased $513,000, or less than one percent, as a result of additional plant in service, substantially offset by lower depreciation rates in the California ($3 million annualized reduction) and Nevada ($2.3 million annualized reduction) rate jurisdictions effective in January and June 2009, respectively. Average gas plant in service for 2009 increased $193 million, or five percent, as compared to 2008. This was attributable to new business, reinforcement work, franchise requirements, routine pipe replacement activities, and the addition of two new operations centers in southern Nevada.

Other income improved $20.1 million between 2009 and 2008. This was primarily due to an $8.5 million increase in the cash surrender values of COLI policies in 2009 compared to cash surrender value declines in 2008 of $12 million, partially offset by a $1.9 million reduction in interest income between the years.

Net financing costs decreased $9 million between 2009 and 2008 primarily due to a reduction in outstanding debt, including the redemption of $75 million of long-term debt in December 2008, and lower interest rates associated with Southwest’s commercial credit and other variable-rate facilities.

29 Greener than you think

Rates and Regulatory Proceedings

General Rate Relief and Rate Design

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

Arizona Energy Efficiency and Decoupling Proceeding.    The ACC convened a series of workshops starting in 2009 to evaluate “rate and regulatory incentives” and establish standards to promote energy efficiency and conservation for utility customers. In conjunction with these workshops, Southwest and other interested parties submitted proposed regulations to the ACC in June 2009. Rate designs which would decouple revenues from customer usage were the topic of much discussion in the proceeding, and were incorporated in several of the parties’ draft regulations. In August 2010, the ACC issued a Notice of Proposed Rulemaking on Gas Energy Efficiency, which adopted an energy efficiency requirement for Arizona’s gas utilities, including Southwest, to achieve cumulative annual energy savings of six percent by December 2020. In October 2010, the Chairman of the ACC issued a draft Policy Statement, which will allow utilities to file proposals for alternative mechanisms including revenue per customer decoupling, in their next general rate case to address the financial disincentives to utilities of promoting energy efficiency. The Policy Statement was approved by the ACC in December 2010.

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

The rate case filing also requested a rate structure to decouple recovery of the Company’s fixed costs from fluctuations in usage, both higher and lower, and enable the Company to aggressively advocate for increased energy efficiency by its customers. The filed structure anticipated the approval of the Policy Statement discussed in the Arizona Energy Efficiency and Decoupling Proceeding section above. The proposed mechanism, referred to as the Energy Efficiency Enabling Provision (“EEEP”), is a revenue-per-customer decoupling mechanism designed to eliminate the link between volumetric sales and revenues that currently exists with traditional rate designs, such that the existing financial disincentive associated with the Company’s pursuit of cost effective energy efficiency is eliminated. This will allow management to focus on customers and to concentrate its attention on the cost of providing service. The pursuit of increased energy efficiency by customers is supported by the requested approval of a detailed energy efficiency and renewable energy resource plan. A decision by the ACC is expected in late 2011 or early 2012.

30 Southwest Gas Corporation

California General Rate Cases.    Effective January 2009, Southwest received general rate relief in California. The California Public Utilities Commission (“CPUC”) decision authorized an overall increase of $2.8 million in 2009 with an additional $400,000 deferred to 2010. In addition, attrition increases were approved and made effective for the years 2010-2013 of 2.95% in southern and northern California and approximately $100,000 per year for the South Lake Tahoe rate jurisdiction. In October 2009, Southwest filed for attrition increases, which were made effective January 2010, in the amount of $2.7 million (including the $400,000 previously deferred). In October 2010, Southwest filed annual attrition increases, which were made effective January 2011, in the amount of $2.3 million.

Nevada General Rate Case.    Southwest filed a general rate application with the Public Utilities Commission of Nevada (“PUCN”) in April 2009 requesting an increase in authorized annual operating revenues of $28.8 million in the Company’s southern Nevada rate jurisdiction and $1.7 million in the northern Nevada rate jurisdiction. The PUCN issued its Order in this proceeding in October 2009 with rates effective November 2009. The Order provided for a revenue increase of $17.6 million in southern Nevada and a revenue decrease of $0.5 million in northern Nevada. On a combined basis, the rate case decision is designed to increase operating income by $19.1 million. The Company was also authorized to implement a decoupled rate structure based on PUCN regulations that will help stabilize operating margin by insulating the Company from the effects of lower usage (including volumes associated with unusual weather). It also allows the Company to more aggressively pursue customer conservation opportunities through implementation of substantive conservation and energy efficiency programs. The PUCN Order also adopted the Company’s recommendation to offset a $20.5 million deferred gain on the sale of the former southern Nevada operations facility against the cost of the land purchased for new facilities by $12.8 million and eliminated approximately $5.9 million of deferred costs associated with a government-mandated pipe inspection program (the remaining $1.8 million will be accreted to income over 4 years). In addition, a tracking mechanism for gas cost-related uncollectible expense was approved.

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 fulfilled an obligation from the settlement agreement reached in the 2005 Paiute general rate case. The application requested an increase in operating revenues of approximately $3.9 million. In accordance with FERC requirements, the requested new rates went into effect in September 2009, subject to refund. In April 2010, the FERC approved an offer of settlement from Paiute which resolved all issues related to its general rate case. The settlement provided for an increase of approximately $900,000 in Paiute’s annual operating income. Paiute had been accruing a liability for the difference between the requested rates and the anticipated settlement rates since September 2009 and refunded the over-collected amounts in the second quarter of 2010.

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, 2010, over-collections in Arizona and Nevada resulted in a liability of $123.4 million and under-collections in California resulted in an asset of $356,000 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

31 Greener than you think

individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

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

	2010			2009
Arizona	$	(45.2	)	$	(33.2	)
Northern Nevada		(8.4	)		1.2
Southern Nevada		(69.8	)		(60.0	)
California		0.4			2.0
	$	(123.0	)	$	(90.0	)

Arizona PGA Filings.    In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits measured on a twelve-month rolling average. A temporary surcredit of $0.08 per therm was put into place in December 2009 to help accelerate the refund of the current over-collected balance to customers. On an annual basis, the surcredit is designed to refund approximately $40 million; however, continued low natural gas prices have resulted in a net increase in the balance due customers. A prudence review of gas costs is conducted in conjunction with general rate cases.

California Gas Cost Filings.    In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments provide the 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. In June 2010, Southwest filed its annual rate adjustment application with the PUCN to establish revised Deferred Energy Account Adjustment (“DEAA”) rates (in addition to adjustments to the Variable Interest Expense Recovery, the Uncollectible Gas Cost Expense rates, and other rate-related items). In October 2010, Southwest filed a stipulation to settle all issues in this case, which was approved by the PUCN effective November 2010. Accordingly, this settlement reduces customer DEAA rates and is designed to result in decreases over the fourteen-month period ending December 2011 of $42.1 million, or 9.58%, in southern Nevada and $11.9 million, or 9.75%, in northern Nevada, which should allow the Company to significantly decrease the Nevada PGA balances.

Gas Price Volatility Mitigation

Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and fixed-for-floating swap contracts (“Swaps”) under its volatility mitigation programs for a portion (ranging from 25 percent to 50 percent, depending on the jurisdiction) of its annual normal weather supply needs. For the 2010/2011 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $7 per dekatherm. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities, and on the spot market. Prices for these contracts are not known until the month of purchase.

32 Southwest Gas Corporation

Capital Resources and Liquidity

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

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 Securities and Exchange Commission (“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 $34.8 million in 2010 as compared to 2009. An increase in net income was more than offset by temporary fluctuations in working capital components and a $32.1 million increase in pension contributions between years, which is included in the caption Changes in other liabilities and deferred credits.

Investing Cash Flows.    Cash used in consolidated investing activities decreased $61.9 million in 2010 as compared to 2009. The current period includes cash inflows from the draw-down of funds, restricted for construction activities, associated with an industrial development revenue bond issuance in 2009.

Financing Cash Flows.    Cash used in consolidated financing activities increased $15.2 million during 2010 as compared to 2009 primarily due to debt repayments, including the redemption in March 2010 of the $100 million 7.7% Subordinated Debentures, and the pay down of a revolving credit facility, partially offset by cash inflows from the issuance of new debt. See also 2010 Financing Activity below. Dividends paid increased in 2010 as compared to 2009 as a result of a quarterly dividend increase and an increase in the number of shares outstanding.

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

2010 Construction Expenditures

During the three-year period ended December 31, 2010, total gas plant increased from $4 billion to $4.6 billion, or at an annual rate of four percent. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase and customer growth also required increased expenditures as the Company set 67,000 meters resulting in 24,000 net new customers during the three-year period.

During 2010, construction expenditures for the natural gas operations segment were $188 million. The majority of these expenditures represented costs associated with routine and targeted replacement of existing transmission,

33 Greener than you think

distribution, and general plant. Cash flows from operating activities of Southwest were $342 million which provided sufficient funding for construction expenditures and dividend requirements of the natural gas operations segment.

2010 Financing Activity

In March 2010, the Company redeemed the $100 million, 7.70% Subordinated Debentures (Preferred Securities) at par. The Company facilitated the redemption using existing cash and borrowings under the $300 million credit facility, though there were no borrowings outstanding on the credit facility by year-end 2010.

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

During 2010, the Company issued shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”) and Stock Incentive Plan, raising approximately $11 million. The Company ceased issuing new common stock under the DRSPP in mid 2010 (the DRSPP will purchase shares on the open market as needed).

Bonus Depreciation.    In September 2010, the Small Business Jobs Act of 2010 (“Act”) was signed into law. The Act provides a 50 percent bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2010. In December 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (“Tax Relief Act”) was signed into law. The Tax Relief Act, among other things, extends the availability of the 50 percent bonus tax depreciation deduction through December 31, 2012. In addition, the Tax Relief Act provides for a temporary 100 percent bonus tax depreciation deduction for qualified property acquired or constructed and placed in service after September 8, 2010 and before January 1, 2012.

As a result of the two acts signed into law in 2010, 50 percent bonus tax depreciation is now available for qualified property acquired or constructed and placed in service from January 1, 2010 through September 8, 2010 and from January 1, 2012 through December 31, 2012. Bonus tax depreciation of 100 percent is available for qualified property acquired or constructed and placed in service from September 9, 2010 through December 31, 2011. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provisions of the two acts will defer the payment of approximately $20 million, $50 million, and $20 million of federal income taxes during 2010, 2011, and 2012, respectively.

Three-Year Construction Expenditures, Debt Maturities, and Financing

In connection with the financial benefits of bonus depreciation, Southwest plans to accelerate approximately $110 million of its pipe replacement, reinforcement, and other future capital expenditures into 2011 and 2012. Including the accelerated amounts, Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2013 will be approximately $680 million. Of this amount, approximately $280 million are expected to be incurred in 2011. During the three-year period, cash flows from operating activities of Southwest (including the bonus depreciation benefits) are expected to provide approximately 80% of the gas operations total construction expenditures and dividend requirements. During the three-year period, the Company expects to raise approximately $15 million from its various common stock programs. Southwest also

34 Southwest Gas Corporation

has $37.8 million in restricted cash from a 2009 Industrial Development Revenue Bond offering that is available to fund qualifying construction expenditures in southern Nevada. 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’s service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

During the three-year period, Southwest has a total of $400 million of maturing debt (including $200 million in February 2011 and $200 million in May 2012). In November 2010, the Company entered into a note purchase agreement with certain institutional investors pursuant to which the Company agreed to issue $125 million of 6.1% Senior Notes to them. The Senior Notes will be unsecured and unsubordinated obligations of the Company, due in February 2041. In February 2011, the Company issued $125 million of 6.1% Senior Notes pursuant to the agreement and used the proceeds to partially fund the redemption of $200 million in maturing debt. Southwest also has $200 million of long-term debt maturing in May 2012 and plans to fund that obligation by issuing $200 million of debentures by the maturity date.

In connection with a portion of planned debt issuances, the Company, in January 2010, entered into two forward-starting interest rate swap (“FSIRS”) agreements to hedge the risk of interest rate variability during the period leading up to planned issuances. The counterparties to each agreement are four major banking institutions. The first FSIRS had a notional amount of $125 million, constituting a hedge related to the 4.45% Senior Notes issued in December (discussed in 2010 Financing Activity above), and terminated on the date of the new debt agreement. At settlement, Southwest paid $11.7 million to the four counterparties. The second FSIRS has a notional amount of $100 million (with Southwest as the fixed-rate payer at a rate of 4.78%) and has a mandatory termination date on or before March 20, 2012. The remaining FSIRS agreement is designated as a cash flow hedge of forecasted future interest payments.

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, 2010, the combined balance in the PGA accounts totaled an over-collection of $123 million. See PGA Filings for more information on recent regulatory filings.

35 Greener than you think

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, 2010, no borrowings were outstanding on either the long-term or short-term portion of the credit facility. During 2010, the short-term portion of the facility was not used. Usage of the long-term portion during 2010 was minimal. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any, or meeting the refund needs of over-collected balances. This credit facility has been, and is expected to continue to be, adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing. 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).

In April 2010, Standard & Poor’s Ratings Services (“S&P”) affirmed the Company’s BBB rating and revised the Company’s outlook to “positive.” S&P cited the Company’s stronger financial performance and an improved debt to capital ratio. 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.

In May 2010, Moody’s Investors Service, Inc. (“Moody’s”) upgraded the Company’s senior unsecured debt rating to Baa2 from Baa3 (the outlook remains stable). Moody’s cited improvements in the Company’s cash flow credit metrics and generally robust financial results in 2009. Moody’s applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.

In June 2010, Fitch, Inc. (“Fitch”) upgraded the Company’s rating outlook to positive from stable. Fitch affirmed the Company’s unsecured long-term debt rating at BBB. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB indicates a credit quality that is considered prudent for investment.

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, 2010, the Company is in compliance with all of its covenants. Under the

36 Southwest Gas Corporation

most restrictive of the covenants, the Company could issue over $1.5 billion in additional debt and meet the leverage ratio requirement and has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Inflation

Inflation can impact the Company’s results of operations. Natural gas, labor, employee benefits, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to the cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor and employee benefits are components of the cost of service, and construction costs are the primary component of rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.

Off-Balance Sheet Arrangements

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

Contractual Obligations

The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statement of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Company’s contractual obligations at December 31, 2010 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2011		2012-2013		2014-2015		Thereafter
Operating activities:
Operating leases (Note 2)	$	25	$	5	$	10	$	6	$	4
Gas purchase obligations		315		241		73		1		—
Pipeline capacity		805		112		141		141		411
Derivatives (Note 13)		19		12		7		—		—
Other commitments		14		7		5		1		1
Financing activities:
Long-term debt (Note 7)		1,200		75		200		—		925
Interest on long-term debt		989		62		92		92		743
Other		16		—		—		1		15
Total	$	3,383	$	514	$	528	$	242	$	2,099

37 Greener than you think

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 184 million dekatherms. Fixed-price contracts range in price from approximately $4 to $7 per dekatherm. Variable-price contracts reflect minimum contractual obligations.

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

Obligations for Financing Activities:    Contractual obligations for financing activities are debt obligations consisting of scheduled principal and interest payments over the life of the debt. The $75 million due in 2011 reflects the net of the $200 million maturing note, offset by $125 million pursuant to the Note Purchase Agreement dated November 2010.

Other:    Estimated funding for pension and other postretirement benefits during calendar year 2011 is $29 million. The Company has an insignificant amount of liabilities in connection with uncertainty surrounding income tax positions taken or expected to be taken.

Results of Construction Services

Year Ended December 31,	2010			2009			2008
(Thousands of dollars)
Construction revenues	$	318,464		$	278,981		$	353,348
Operating expenses:
Construction expenses		277,804			242,461			311,745
Depreciation and amortization		20,007			23,232			27,382
Operating income		20,653			13,288			14,221
Other income (deductions)		(166	)		55			63
Net interest deductions		564			1,179			1,823
Income before income taxes		19,923			12,164			12,461
Income tax expense		7,852			4,466			5,235
Net income		12,071			7,698			7,226
Net income (loss) attributable to noncontrolling interest		(424	)		(364	)		—
Contribution to consolidated net income attributable to NPL	$	12,495		$	8,062		$	7,226

2010 vs. 2009

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

38 Southwest Gas Corporation

The prolonged economic downturn and general slowdown in the new housing market have dramatically reduced the amount of new construction activities. NPL has been able to offset reductions in new construction with replacement work received under existing blanket contracts and incremental bid work in 2010. New construction work is expected to remain sluggish in 2011, although continued opportunities for incremental replacement work appear favorable.

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

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

NPL revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Generally, revenues and profits are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating results typically improve as more favorable weather conditions occur during the summer and fall months.

2009 vs. 2008

Contribution to consolidated net income from construction services for 2009 increased $836,000 compared to 2008. The increase was due primarily to a reduction in construction expenses and lower interest deductions. Gains on sales of equipment were $3.3 million for 2009 and $2.1 million for 2008.

The general slowdown in the new housing market and associated construction activities that started in 2007, continued throughout 2008 and 2009. The adverse economic conditions experienced in 2009 negatively impacted the amount of work under existing blanket contracts, and reduced the amount of profitable bid work.

Revenues decreased $74.4 million due primarily to less new construction work and a decrease in bid work. The construction revenues above include NPL contracts with Southwest totaling $52.6 million in 2009 and $63.1 million in 2008. NPL accounts for the services provided to Southwest at contractual (market) prices.

Construction expenses decreased $69.3 million due primarily to the overall reduction in construction work, cost savings initiatives, and lower fuel and fuel-related expenses. Interest expense decreased $644,000 between years due to a reduction in outstanding debt.

Income tax expense improved from the prior year due to certain beneficial impacts of tax regulations in effect in 2009.

In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65 percent interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

39 Greener than you think

Application of Critical Accounting Policies

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

Regulatory Accounting

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

Accrued Utility Revenues

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

Accounting for Income Taxes

The income tax calculations of the Company require estimates due to known future tax rate changes, book to tax differences, and uncertainty with respect to regulatory treatment of certain property items. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recoverable from or refunded to customers in future rates. Deferred tax assets and liabilities are measured using enacted tax rates

40 Southwest Gas Corporation

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, 2010, the Company lowered the discount rate to 5.75% from 6.00% at December 31, 2009. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase and the asset return assumption remain at 3.25% and 8.00%, respectively. Favorable asset returns were experienced during 2010 relative to the assumed rate of return. This partially offset significant losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2011. Pension expense for 2011 is estimated to increase by $2.8 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Certifications

The SEC requires the Company to file certifications of its Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to the Company’s periodic filings. The CEO and CFO certifications for the period ended December 31, 2010 are included as exhibits to the 2010 Annual Report on Form 10-K filed with the SEC.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” “forecast,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, economic-related declines, the composition of our customer base, price volatility, seasonal patterns, the sufficiency of the level of contracted firm interstate capacity, payment of debt, the Company’s COLI strategy, timing of improvements in the housing market, replacement market and new construction market, amount and timing for completion of estimated future construction expenditures, forecasted

41 Greener than you think

operating cash flows and results of operations, funding sources of cash requirements, sufficiency of working capital, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing, the amount and form of any such financing, the effectiveness of forward-starting interest rate swap agreements in hedging against changing interest rates, pension and post-retirement benefits, liquidity, certain tax benefits from the Act and the Tax Relief Act, the effect of rate decoupling in Arizona, the impact of fuel switching by large customers, expenditures for compliance with any EPA requirements, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, 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 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 and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

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).

42 Southwest Gas Corporation

Common Stock Price and Dividend Information

	2010				2009				Dividends Declared
	High		Low		High		Low		2010		2009
First quarter	$	30.70	$	26.28	$	26.38	$	17.08	$	0.2500	$	0.2375
Second quarter		32.91		28.12		22.32		18.96		0.2500		0.2375
Third quarter		34.06		28.58		26.64		21.58		0.2500		0.2375
Fourth quarter		37.25		33.41		29.48		24.81		0.2500		0.2375
									$	1.0000	$	0.9500

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2011, there were 17,727 holders of record of common stock, and the market price of the common stock was $37.90.

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 22.5 cents per share throughout 2008, 23.75 cents per share throughout 2009, and 25 cents per share throughout 2010. In February 2011, the Board of Directors increased the quarterly dividend from 25 cents to 26.5 cents per share, effective with the June 2011 payment.

43 Greener than you think

SOUTHWEST GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

December 31,	2010			2009
ASSETS
Utility plant:
Gas plant	$	4,569,105		$	4,418,286
Less: accumulated depreciation		(1,535,429	)		(1,431,106	)
Acquisition adjustments, net		1,271			1,451
Construction work in progress		37,489			45,872
Net utility plant (Note 2)		3,072,436			3,034,503
Other property and investments		134,648			115,860
Restricted cash		37,781			49,769
Current assets:
Cash and cash equivalents		116,096			65,315
Accounts receivable, net of allowances (Note 3)		147,605			157,722
Accrued utility revenue		64,400			71,700
Income taxes receivable, net		21,514			8,549
Deferred income taxes (Note 12)		8,046			22,410
Deferred purchased gas costs (Note 4)		356			3,251
Prepaids and other current assets (Note 4)		87,877			88,685
Total current assets		445,894			417,632
Deferred charges and other assets (Notes 4 and 13)		293,434			288,528
Total assets	$	3,984,193		$	3,906,292

44 Southwest Gas Corporation

CONSOLIDATED BALANCE SHEETS - Continued

December 31,	2010			2009
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 45,599,036 and 45,091,734 shares) (Note 11)	$	47,229		$	46,722
Additional paid-in capital		807,885			792,339
Accumulated other comprehensive income (loss), net (Note 5)		(30,784	)		(22,250	)
Retained earnings		343,131			285,316
Total Southwest Gas Corporation equity		1,167,461			1,102,127
Noncontrolling interest		(465	)		(41	)
Total equity		1,166,996			1,102,086
Subordinated debentures due to Southwest Gas Capital II (Note 6)		—			100,000
Long-term debt, less current maturities (Note 7)		1,124,681			1,169,357
Total capitalization		2,291,677			2,371,443
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		75,080			1,327
Accounts payable		165,536			158,856
Customer deposits		86,891			91,668
Accrued general taxes		40,438			40,868
Accrued interest		20,162			19,644
Deferred purchased gas costs (Note 4)		123,344			93,226
Other current liabilities (Notes 4 and 13)		85,510			68,641
Total current liabilities		596,961			474,230
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 12)		466,628			436,113
Taxes payable		1,234			3,079
Accumulated removal costs (Note 4)		211,000			189,000
Other deferred credits (Notes 4 and 10)		416,693			432,427
Total deferred income taxes and other credits		1,095,555			1,060,619
Total capitalization and liabilities	$	3,984,193		$	3,906,292

The accompanying notes are an integral part of these statements.

45 Greener than you think

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

Year Ended December 31,	2010			2009			2008
Operating revenues:
Gas operating revenues	$	1,511,907		$	1,614,843		$	1,791,395
Construction revenues		318,464			278,981			353,348
Total operating revenues		1,830,371			1,893,824			2,144,743
Operating expenses:
Net cost of gas sold		736,175			866,630			1,055,977
Operations and maintenance		354,943			348,942			338,660
Depreciation and amortization		190,463			190,082			193,719
Taxes other than income taxes		38,869			37,318			36,780
Construction expenses		277,804			242,461			311,745
Total operating expenses		1,598,254			1,685,433			1,936,881
Operating income		232,117			208,391			207,862
Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(75,677	)		(75,270	)		(84,919	)
Net interest deductions on subordinated debentures (Note 6)		(1,912	)		(7,731	)		(7,729	)
Other income (deductions)		3,850			6,645			(13,406	)
Total other income and (expenses)		(73,739	)		(76,356	)		(106,054	)
Income before income taxes		158,378			132,035			101,808
Income tax expense (Note 12)		54,925			44,917			40,835
Net income		103,453			87,118			60,973
Net income (loss) attributable to noncontrolling interest		(424	)		(364	)		—
Net income attributable to Southwest Gas Corporation	$	103,877		$	87,482		$	60,973
Basic earnings per share (Note 15)	$	2.29		$	1.95		$	1.40
Diluted earnings per share (Note 15)	$	2.27		$	1.94		$	1.39
Average number of common shares outstanding		45,405			44,752			43,476
Average shares outstanding (assuming dilution)		45,823			45,062			43,775

The accompanying notes are an integral part of these statements.

46 Southwest Gas Corporation

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME

(In thousands, except per share amounts)

	Southwest Gas Corporation Equity
						Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)
														Non- controlling Interest
	Common Stock										Retained Earnings									Comprehensive Income (Loss)
	Shares			Amount													Total
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 10)									(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
Common stock issuances		900			900		21,876											22,776
Net income (loss)												87,482			(364	)		87,118		$	87,118
Noncontrolling interest capital investment															323			323
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of $1.7 million of tax (Note 10)									(2,824	)								(2,824	)		(2,824	)
Dividends declared Common: $0.95 per share												(43,148	)					(43,148	)
2009 Comprehensive Income																				$	84,294
Comprehensive income (loss) attributable to noncontrolling interest																					(364	)
Comprehensive income attributable to Southwest Gas Corporation																				$	84,658
DECEMBER 31, 2009		45,092			46,722		792,339		(22,250	)		285,316			(41	)		1,102,086
Common stock issuances		507			507		15,546											16,053
Net income (loss)												103,877			(424	)		103,453		$	103,453
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of $1.7 million of tax (Notes 5 and 10)									2,842									2,842			2,842
FSIRS realized and unrealized loss, net of $7 million of tax (Notes 5 and 13)									(11,436	)								(11,436	)		(11,436	)
Amounts reclassified to net income, net of $37,000 of tax (Note 13)									60									60			60
Dividends declared Common: $1.00 per share												(46,062	)					(46,062	)
2010 Comprehensive Income																				$	94,919
Comprehensive income (loss) attributable to noncontrolling interest																					(424	)
Comprehensive income attributable to Southwest Gas Corporation																				$	95,343
DECEMBER 31, 2010		45,599	*	$	47,229	$	807,885	$	(30,784	)	$	343,131		$	(465	)	$	1,166,996

*At December 31, 2010, 2.3 million common shares were registered and available for issuance under provisions of the Company's various stock issuance plans. In addition, approximately 369,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 11).

The accompanying notes are an integral part of these statements.

47 Greener than you think

SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

Year Ended December 31,	2010			2009			2008
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	103,453		$	87,118		$	60,973
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		190,463			190,082			193,719
Deferred income taxes		50,111			42,798			36,135
Changes in current assets and liabilities:
Accounts receivable, net of allowances		10,117			11,107			34,831
Accrued utility revenue		7,300			900			2,300
Deferred purchased gas costs		33,013			56,902			20,931
Accounts payable		6,680			(32,578	)		(29,297	)
Accrued taxes		(15,240	)		22,497			(21,837	)
Other current assets and liabilities		12,895			32,733			(3,636	)
Gains on sale		(1,547	)		(3,291	)		(2,068	)
Changes in undistributed stock compensation		4,429			3,942			3,825
AFUDC and property-related changes		(945	)		(1,221	)		(561	)
Changes in other assets and deferred charges		(12,262	)		(15,553	)		(5	)
Changes in other liabilities and deferred credits		(17,474	)		10,366			4,438
Net cash provided by operating activities		370,993			405,802			299,748

48 Greener than you think

CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued

Year Ended December 31,	2010			2009			2008
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(215,439	)		(216,985	)		(300,217	)
Restricted cash		11,988			(49,769	)		—
Changes in customer advances		(830	)		(2,476	)		4,044
Receipt of exchange fund deposit		—			—			28,000
Miscellaneous inflows		4,075			7,933			17,656
Miscellaneous outflows		(2,800	)		(3,620	)		(2,693	)
Net cash used in investing activities		(203,006	)		(264,917	)		(253,210	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		11,098			18,401			35,391
Dividends paid		(44,846	)		(41,950	)		(38,705	)
Interest rate swap settlement		(11,691	)		—			—
Issuance of long-term debt, net		123,960			49,834			103,875
Retirement of long-term debt		(3,327	)		(15,654	)		(198,691	)
Redemption of subordinated debentures		(100,000	)		—			—
Change in long-term portion of credit facility		(92,400	)		(57,600	)		—
Change in short-term debt		—			(55,000	)		46,000
Net cash used in financing activities		(117,206	)		(101,969	)		(52,130	)
Change in cash and cash equivalents		50,781			38,916			(5,592	)
Cash and cash equivalents at beginning of period		65,315			26,399			31,991
Cash and cash equivalents at end of period	$	116,096		$	65,315		$	26,399
Supplemental information:
Interest paid, net of amounts capitalized	$	87,000		$	80,771		$	91,211
Income taxes paid (received)	$	19,200		$	(21,616	)	$	22,472

The accompanying notes are an integral part of these statements.

49 Southwest Gas Corporation

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. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65 percent interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

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

Consolidation.    The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities.

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

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

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

50 Southwest Gas Corporation

tled. 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 $211 million and $189 million, as of December 31, 2010 and 2009, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets.

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

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

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

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

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

51 Greener than you think

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

Depreciation and Amortization.    Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for 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 $1.5 million in 2010, $2.2 million in 2009, and $1.2 million in 2008 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 $512,000, $957,000, and $635,000 for 2010, 2009, and 2008, 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):

	2010			2009			2008
Change in COLI policies	$	9,770		$	8,546		$	(12,041	)
Interest income		194			271			2,212
Pipe replacement costs		(5,024	)		(2,642	)		(1,942	)
Miscellaneous income and (expense)		(1,090	)		470			(1,635	)
Total other income (deductions)	$	3,850		$	6,645		$	(13,406	)

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). These life insurance policies on members of management and other key employees are used by Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work.

52 Southwest Gas Corporation

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.

	2010		2009		2008
(In thousands)
Average basic shares		45,405		44,752		43,476
Effect of dilutive securities:
Stock options		56		14		60
Performance shares		260		216		193
Restricted stock units		102		80		46
Average diluted shares		45,823		45,062		43,775

Subsequent Events.    Management of the Company monitors significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. See Note 7 – Long-Term Debt for information regarding debt issued subsequent to December 31, 2010.

Note 2 – Utility Plant

Net utility plant as of December 31, 2010 and 2009 was as follows (thousands of dollars):

December 31,	2010			2009
Gas plant:
Storage	$	20,396		$	20,326
Transmission		274,646			271,467
Distribution		3,847,731			3,716,881
General		279,402			270,825
Other		146,930			138,787
		4,569,105			4,418,286
Less: accumulated depreciation		(1,535,429	)		(1,431,106	)
Acquisition adjustments, net		1,271			1,451
Construction work in progress		37,489			45,872
Net utility plant	$	3,072,436		$	3,034,503

53 Greener than you think

Depreciation and amortization expense on gas plant was $167 million in 2010 and $162 million in both 2009 and 2008.

Operating Leases and Rentals.    Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The leases provide for current terms which expire in 2017 and 2014, 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 2011 through 2015 and $4 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.4 million in each of the years 2011 through 2013, and $243,000 in 2014 when the lease expires. In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. Rentals included in operating expenses for all operating leases were $19.4 million in 2010, $19.9 million in 2009, and $23.4 million in 2008. These amounts include NPL lease expenses of approximately $11.8 million in 2010, $11.3 million in 2009, and $13.9 million in 2008, 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, 2010 (thousands of dollars):

Year Ending December 31,
2011	$	5,547
2012		4,904
2013		4,697
2014		3,138
2015		2,754
Thereafter		3,599
Total minimum lease payments	$	24,639

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, 2010, the gas utility customer accounts receivable balance was $110 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. Customer accounts are subject to collection procedures that vary by jurisdiction (late fee assessment, noticing requirements for disconnection of service, and procedures for actual disconnection and/or reestablishment of service). After disconnection of service, accounts are generally written off approximately one month after inactivation. Dependent upon the jurisdiction, reestablishment of service requires both payment of previously unpaid balances and additional deposit requirements. Provisions for uncollectible accounts are based on experience and recorded monthly, as needed. They are included in the ratemaking process as a cost of service. Beginning in November 2009, a regulatory mechanism was implemented in the Nevada jurisdictions associated with the gas cost-related portion of uncollectible

54 Southwest Gas Corporation

accounts. Such amounts are deferred and collected through a surcharge in the ratemaking process. Activity in the allowance for uncollectibles is summarized as follows (thousands of dollars):

	Allowance for Uncollectibles
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
Additions charged to expense		6,658
Accounts written off, less recoveries		(6,493	)
Balance, December 31, 2009		3,953
Additions charged to expense		2,646
Accounts written off, less recoveries		(3,405	)
Balance, December 31, 2010	$	3,194

Note 4 - Regulatory Assets and Liabilities

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

55 Greener than you think

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

December 31,	2010			2009
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	224,913		$	224,261
Unrealized loss on non-trading derivatives (Swaps) (2)		11,482			1,496
Deferred purchased gas costs (3)		356			3,251
Accrued purchased gas costs (4)		14,000			12,500
Unamortized premium on reacquired debt (5)		19,881			17,095
Other (8)		28,402			28,055
		299,034			286,658
Regulatory liabilities:
Deferred purchased gas costs (3)		(123,344	)		(93,226	)
Accumulated removal costs		(211,000	)		(189,000	)
Unrealized gain on non-trading derivatives (Swaps) (2)		(656	)		(2,618	)
Deferred gain on southern Nevada division operations facility (6)		(1,246	)		(1,686	)
Rate refunds due customers (7)		(546	)		—
Unamortized gain on reacquired debt (6)		(13,006	)		(13,543	)
Other (6)		(2,811	)		(2,486	)
Net regulatory assets (liabilities)	$	(53,575	)	$	(15,901	)

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

(2) Regulatory asset included in Prepaids and other current assets ($11.5 million and $1.4 million) in 2010 and 2009, respectively. Regulatory asset included in Deferred charges and other assets ($75,000) in 2009. Regulatory liability included in Other deferred credits ($656,000 and $58,000) in 2010 and 2009, respectively. Regulatory liability included in Other current liabilities ($2.6 million) in 2009. The actual amounts, when realized at settlement, become a component of gas costs. (See Note 13)

(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 Sheet.

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

56 Southwest Gas Corporation

Note 5 – Accumulated Other Comprehensive Income

AOCI - Rollforward

(Thousands of dollars)

	Defined Benefit Plans (Note 10)									FSIRS (Note 13)
	Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit		After-Tax			AOCI
Beginning Balance AOCI December 31, 2009	$	(35,887	)	$	13,637		$	(22,250	)	$	—		$	—	$	—		$	(22,250	)
Current period change		4,583			(1,741	)		2,842	*		(18,349	)		6,973		(11,376	)**		(8,534	)
Ending Balance AOCI December 31, 2010	$	(31,304	)	$	11,896		$	(19,408	)	$	(18,349	)	$	6,973	$	(11,376	)	$	(30,784	)

*   Net actuarial gain (loss), less amortization of unamortized benefit plan cost

** FSIRS unrealized $4.2 million loss recorded in other comprehensive income; FSIRS realized $7.2 million loss, less amounts reclassified to net income, recorded in other comprehensive income.

Approximately $725,000 of realized losses (net of tax) related to the FSIRS reported in AOCI at December 31, 2010 will be reclassified into expense within the next twelve months as the related interest payments on long-term debt occur.

Note 6 - Preferred Trust Securities and Subordinated Debentures

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

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

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 value of the subordinated debentures at December 31, 2009 was $102 million.

57 Greener than you think

Note 7 – Long-Term Debt

December 31,	2010					2009
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011	$	200,000		$	201,560	$	200,000		$	213,012
Notes, 7.625%, due 2012		200,000			214,666		200,000			219,240
Notes, 4.45%, due 2020		125,000			125,325		—			—
8% Series, due 2026		75,000			99,968		75,000			87,005
Medium-term notes, 7.59% series, due 2017		25,000			30,295		25,000			27,858
Medium-term notes, 7.78% series, due 2022		25,000			32,063		25,000			28,275
Medium-term notes, 7.92% series, due 2027		25,000			33,211		25,000			28,848
Medium-term notes, 6.76% series, due 2027		7,500			8,956		7,500			7,723
Unamortized discount		(2,534	)				(2,196	)
		679,966					555,304
Revolving credit facility and commercial paper, due 2012		—			—		92,400			92,400
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
6.10% 1999 Series A, due 2038		12,410			11,968		12,410			11,443
5.95% 1999 Series C, due 2038		14,320			13,594		14,320			12,922
5.55% 1999 Series D, due 2038		8,270			7,468		8,270			7,038
5.45% 2003 Series C, due 2038 (rate resets in 2013)		30,000			31,547		30,000			31,422
5.25% 2003 Series D, due 2038		20,000			17,474		20,000			16,701
5.80% 2003 Series E, due 2038 (rate resets in 2013)		15,000			15,436		15,000			15,683
5.25% 2004 Series A, due 2034		65,000			58,574		65,000			55,979
5.00% 2004 Series B, due 2033		31,200			27,295		31,200			26,096
4.85% 2005 Series A, due 2035		100,000			84,485		100,000			79,469
4.75% 2006 Series A, due 2036		24,855			20,518		24,855			19,139
Unamortized discount		(3,502	)				(3,644	)
		517,553					517,411
Other		2,242			2,473		5,569			5,712
		1,199,761					1,170,684
Less: current maturities		(75,080	)				(1,327	)
Long-term debt, less current maturities	$	1,124,681				$	1,169,357

58 Southwest Gas Corporation

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, 2010, no borrowings were outstanding on the short-term portion of the credit facility (see Note 8 – Short-Term Debt) and no borrowings were outstanding on the long-term portion. The effective interest rate on the borrowings on the long-term portion of the credit facility was 0.87% at December 31, 2009.

In November 2010, the Company entered into a note purchase agreement with Metropolitan Life Insurance Company, John Hancock Life Insurance Company (U.S.A.), certain of their respective affiliates, and Union Fidelity Life Insurance Company (collectively, the “Purchasers”), pursuant to which the Company agreed to issue $125 million of 6.1% Senior Notes to the Purchasers. The Senior Notes will be unsecured and unsubordinated obligations of the Company, due in February 2041. The full net proceeds from the Senior Notes will be used to partially repay the maturing 8.375% $200 million debentures due in February 2011. Therefore, $125 million of the maturing notes continue to be shown as long-term obligations. In February 2011, the Company issued $125 million of 6.1% Senior Notes pursuant to the agreement and used the proceeds to partially redeem the 8.375% debentures.

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

In December 2009, the Company issued $50 million in Clark County, Nevada variable-rate 2009 Series A Industrial Development Revenue Bonds (“IDRBs”), supported by a letter of credit with JPMorgan Chase Bank. At December 31, 2009 and 2010, $49.8 million and $37.8 million, respectively, in proceeds from the issuance of the IDRBs remained in trust and are shown as restricted cash on the consolidated balance sheets.

The effective interest rates on the 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs were 1.20%, 2.72%, and 2.68%, respectively, at December 31, 2010. The effective interest rate on the 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs were 1.14%, 3.76%, and 3.68%, respectively, at December 31, 2009. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 1.18% and 1.12% at December 31, 2010 and 2009, respectively. In Nevada, interest fluctuations due to changing interest rates on the 2003 Series A and 2008 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.

The fair values of the revolving credit facility and the variable-rate IDRBs approximate carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for December 31, 2010 and 2009, as applicable, and other secondary sources which are customarily consulted for data of this kind.

Estimated maturities of long-term debt for the next five years are $75.1 million, $200.1 million, $91,000, $97,000, and $103,000, respectively.

59 Greener than you think

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, 2010, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.5 billion in additional debt and meet the leverage ratio requirement and has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Note 8 - Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that expires in May 2012, of which $150 million has been designated by management for working capital purposes (and related outstanding amounts, if any, are shown as short-term debt). Southwest had no short-term borrowings outstanding on the credit facility at December 31, 2010 or December 31, 2009.

Note 9 - Commitments and Contingencies

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

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

Note 10 – Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through 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 $4.6 million in 2010, $4.5 million in 2009, and $4.4 million in 2008. NPL has a separate plan, the cost and liability of 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.

60 Southwest Gas Corporation

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

The Company recognizes the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in its balance sheets. Any actuarial gains and losses, prior service costs and transition assets or obligations are recognized in accumulated other comprehensive income under stockholders’ equity, net of tax, until they are amortized as a component of net periodic benefit cost.

In accordance with regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities, the Company has established a regulatory asset for the portion of the total amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through rates in future periods. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are recognized as components of net periodic pension costs each year.

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

A target portfolio of investments in the qualified retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Asset return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. The current percentage ranges of the target portfolio are:

Type of Investment	Percentage Range
Equity securities	59 to 71
Debt securities	31 to 37
Other	up to 5

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

U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on December 31 of each year and expected to be available during the period to maturity of the

61 Greener than you think

pension benefits. In determining the discount rate, the Company matches the plan’s projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are generally made in increments of 25 basis points.

Due to the continuing low interest rate environment for high-quality fixed income investments, the Company lowered the discount rate from 6.00% at December 31, 2009 to 5.75% at December 31, 2010. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase and the asset return assumption remain at 3.25% and 8.00%, respectively. Favorable asset returns were experienced during 2010 and 2009 relative to the assumed rate of return. This partially offset the significant losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2011. Pension expense for 2011 is estimated to increase by $2.8 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

62 Southwest Gas Corporation

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.

	2010									2009
	Qualified Retirement Plan			SERP			PBOP			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars) Change in benefit obligations
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$	606,276		$	35,339		$	42,322		$	523,011		$	31,786		$	35,915
Service cost		16,932			372			856			15,390			195			729
Interest cost		35,614			2,045			2,491			34,527			2,065			2,370
Actuarial loss (gain)		27,680			(3,480	)		2,632			55,356			3,785			4,546
Benefits paid		(24,368	)		(2,416	)		(1,536	)		(22,008	)		(2,492	)		(1,238	)
Benefit obligation at end of year (PBO/PBO/APBO)		662,134			31,860			46,765			606,276			35,339			42,322
Change in plan assets
Market value of plan assets at beginning of year		392,975			—			25,511			323,460			—			19,436
Actual return on plan assets		53,224			—			3,181			69,523			—			4,540
Employer contributions		54,100			2,416			1,348			22,000			2,492			1,535
Benefits paid		(24,368	)		(2,416	)		(400	)		(22,008	)		(2,492	)		—
Market value of plan assets at end of year		475,931			—			29,640			392,975			—			25,511
Funded status at year end	$	(186,203	)	$	(31,860	)	$	(17,125	)	$	(213,301	)	$	(35,339	)	$	(16,811	)
Weighted-average assumptions (benefit obligation)
Discount rate		5.75	%		5.75	%		5.75	%		6.00	%		6.00	%		6.00	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		3.25	%		3.25	%		3.25	%		3.25	%

The accumulated benefit obligation for the retirement plan was $591 million and $530 million, and for the SERP was $30.7 million and $31.5 million at December 31, 2010 and 2009, respectively.

Estimated funding for the plans above during calendar year 2011 is approximately $29 million of which $28 million pertains to the retirement plan. Management monitors plan assets and liabilities and could, at its discretion, increase plan funding levels above the minimum in order to achieve a desired funded status and avoid or minimize potential benefit restrictions.

Pension benefits expected to be paid for each of the next five years beginning with 2011 are the following: $28 million, $29 million, $31 million, $33 million, and $35 million. Pension benefits expected to be paid during

63 Greener than you think

2016 to 2020 total $204 million. Retiree welfare benefits expected to be paid for each of the next five years beginning with 2011 are the following: $2 million, $2.1 million, $2.3 million, $2.5 million, and $2.6 million. Retiree welfare benefits expected to be paid during 2016 to 2020 total $15 million. SERP benefits expected to be paid in 2011 are $2.3 million, and they are approximately $2.5 million for each of the next four years beginning with 2012. SERP benefits expected to be paid during 2016 to 2020 total $13 million. No assurance can be made that actual funding and benefits paid will match these estimates.

For PBOP measurement purposes, the per capita cost of covered health care benefits medical rate trend assumption is eight 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.

64 Southwest Gas Corporation

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2010			2009			2008			2010			2009			2008			2010			2009			2008
(Thousands of dollars)
Service cost	$	16,932		$	15,390		$	16,108		$	372		$	195		$	97		$	856		$	729		$	730
Interest cost		35,614			34,527			32,491			2,045			2,065			2,041			2,491			2,370			2,324
Expected return on plan assets		(36,538	)		(35,221	)		(34,714	)		—			—			—			(2,093	)		(1,603	)		(2,138	)
Amortization of prior service costs (credits)		—			(2	)		(11	)		—			—			—			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			867			867
Amortization of net actuarial loss		10,478			4,253			3,104			1,155			909			997			489			434			—
Net periodic benefit cost	$	26,486		$	18,947		$	16,978		$	3,572		$	3,169		$	3,135		$	2,610		$	2,797		$	1,783
Weighted-average assumptions (net benefit cost)
Discount rate		6.00	%		6.75	%		6.50	%		6.00	%		6.75	%		6.50	%		6.00	%		6.75	%		6.50	%
Expected return on plan assets		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		3.75	%		4.00	%		3.25	%		3.75	%		4.00	%		3.25	%		3.75	%		4.00	%

65 Greener than you think

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

	2010												2009
	Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)	$	9,058		$	10,994		$	(3,480	)	$	1,544		$	26,448		$	21,054		$	3,785		$	1,609
Amortization of prior service credit (b)		—			—			—			—			2			2			—			—
Amortization of transition obligation (b)		(867	)		—			—			(867	)		(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(12,122	)		(10,478	)		(1,155	)		(489	)		(5,596	)		(4,253	)		(909	)		(434	)
Regulatory adjustment		(652	)		(464	)		—			(188	)		(15,431	)		(15,123	)		—			(308	)
Recognized in other comprehensive (income) loss	$	(4,583	)	$	52		$	(4,635	)	$	—		$	4,556		$	1,680		$	2,876		$	—
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	28,085		$	26,538		$	(1,063	)	$	2,610		$	29,469		$	20,627		$	6,045		$	2,797

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

66 Southwest Gas Corporation

Related Tax Effects Allocated to Each Component of Other Comprehensive Income

	2010									2009
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial loss (gain)	$	9,058		$	(3,442	)	$	5,616		$	26,448		$	(10,050	)	$	16,398
Amortization of prior service credit		—			—			—			2			(1	)		1
Amortization of transition obligation		(867	)		329			(538	)		(867	)		329			(538	)
Amortization of net loss		(12,122	)		4,606			(7,516	)		(5,596	)		2,126			(3,470	)
Regulatory adjustment		(652	)		248			(404	)		(15,431	)		5,864			(9,567	)
Other comprehensive (income) loss	$	(4,583	)	$	1,741		$	(2,842	)	$	4,556		$	(1,732	)	$	2,824

(1) 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 $14.4 million for the qualified retirement plan and $600,000 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 $600,000 related to net loss and $870,000 for the transition obligation.

U.S. GAAP states that a fair value measurement should be based on the assumptions that market participants would use in pricing the asset or liability and establishes a fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The three levels of the fair value hierarchy are as follows:

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

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

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

67 Greener than you think

The following table sets forth, by level within the three-level fair value hierarchy, the fair values of the assets of the qualified pension plan and the PBOP as of December 31, 2010 and December 31, 2009. The SERP has no assets.

	December 31, 2010									December 31, 2009
	Qualified Retirement Plan			PBOP			Total			Qualified Retirement Plan			PBOP			Total
Assets at fair value (thousands of dollars):
Level 1 - Quoted prices in active markets for identical financial assets
Cash equivalents	$	48		$	2		$	50		$	39		$	1		$	40
Common stock		213,853			6,978			220,831			175,247			5,719			180,966
Real estate investment trusts		4,504			147			4,651			2,731			89			2,820
Mutual funds		49,994			14,234			64,228			42,070			12,604			54,674
Government fixed income		11,020			360			11,380			6,580			215			6,795
Preferred securities		—			—			—			169			5			174
Futures contracts		(51	)		(2	)		(53	)		(51	)		(2	)		(53	)
Total Level 1 Assets (1)	$	279,368		$	21,719		$	301,087		$	226,785		$	18,631		$	245,416
Level 2 - Significant other observable inputs
Cash equivalents	$	—		$	—		$	—		$	3		$	—		$	3
Commercial paper		—			—			—			1,414			46			1,460
Government fixed income and mortgage backed		39,201			1,279			40,480			36,078			1,177			37,255
Corporate fixed income		54,197			1,768			55,965			40,646			1,326			41,972
Pooled funds and mutual funds		8,230			1,974			10,204			9,588			1,767			11,355
State and local obligations		626			20			646			262			9			271
Total Level 2 assets (2)	$	102,254		$	5,041		$	107,295		$	87,991		$	4,325		$	92,316
Level 3 - Significant unobservable inputs
Commingled equity funds	$	94,389		$	3,080		$	97,469		$	75,418		$	2,461		$	77,879
Total Level 3 assets (3)	$	94,389		$	3,080		$	97,469		$	75,418		$	2,461		$	77,879
Total Plan assets at fair value	$	476,011		$	29,840		$	505,851		$	390,194		$	25,417		$	415,611
Guaranteed investment contracts/guaranteed annuity contracts (4)		5,342			—			5,342			5,673			—			5,673
Total Plan assets (5)	$	481,353		$	29,840		$	511,193		$	395,867		$	25,417		$	421,284

68 Southwest Gas Corporation

(1) Equity securities, Real Estate Investment Trusts, and U.S. Government securities listed or regularly traded on a national securities exchange are valued at quoted market prices as of the last business day of the calendar year.

The mutual funds category above is an intermediate-term bond fund whose manager employs multiple concurrent strategies and takes only moderate risk in each, thereby reducing the risk of poor performance arising from any single source and a balanced fund that invests in a diversified portfolio of common stocks, preferred stocks and fixed-income securities. Strategies utilized by the bond fund include duration management, yield curve or maturity structuring, sector rotation, and all bottom-up techniques including in-house credit and quantitative research. Strategies employed by the balanced fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income.

(2) The fair value of investments in debt securities with remaining maturities of one year or more is determined by dealers who make markets in such securities or by an independent pricing service, which considers yield or price of bonds of comparable quality, coupon, maturity, and type.

The pooled funds and mutual funds are two collective short-term funds that invest in Treasury bills and money market funds. These funds are used as a temporary cash repository for the pension plan’s various investment managers.

(3) Assets not considered Level 1 or Level 2 are valued using assumptions based on the best information available under the circumstances, such as investment manager pricing.

The commingled equity funds include private equity funds that invest in international securities. These funds are shown in the above table at net asset value. Investment strategies employed by the funds include:

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

• Diversification by country, limiting exposure in any one country

• Emerging markets

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

(5) The assets in the above table exceed the market value of plan assets shown in the funded status table by $5.6 million (qualified retirement plan - $5.4 million, PBOP – $200,000), which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

69 Greener than you think

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2008	$	57,017
Actual return on plan assets:
Relating to assets still held at the reporting date		20,466
Relating to assets sold during the period		816
Purchases, sales, and settlements		(420	)
Transfers in and/or out of Level 3		—
Balance, December 31, 2009	$	77,879
Actual return on plan assets:
Relating to assets still held at the reporting date		13,090
Relating to assets sold during the period		—
Purchases, sales, and settlements		6,500
Transfers in and/or out of Level 3		—
Balance, December 31, 2010	$	97,469

Note 11 – Stock-Based Compensation

At December 31, 2010, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income for the years ended December 31, 2010, December 31, 2009, and December 31, 2008 were $5.9 million (net of related tax benefits of $3.6 million), $5.2 million (net of related tax benefits of $3.2 million), and $4.9 million (net of related tax benefits of $3 million), respectively.

Under the option plan, the Company previously granted options to purchase shares of common stock to key employees and outside directors. The last option grants were in 2006 and no future grants are anticipated. Each option has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years.

70 Southwest Gas Corporation

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

	2010					2009					2008
	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		651		$	27.49		731		$	27.12		798		$	26.85
Granted during the year		—			—		—			—		—			—
Exercised during the year		(273	)		26.67		(66	)		23.18		(64	)		23.70
Forfeited or expired during the year		(9	)		29.51		(14	)		28.88		(3	)		27.72
Outstanding at year end		369		$	28.04		651		$	27.49		731		$	27.12
Exercisable at year end		369		$	28.04		651		$	27.49		663		$	26.55

The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding and exercisable options was $3.2 million, $1.7 million, and $661,000 at December 31, 2010, 2009, and 2008, respectively. The aggregate intrinsic value of exercised options was $1.7 million, $294,000, and $339,000 during 2010, 2009, and 2008, respectively. The market value of Southwest Gas stock was $36.67, $28.53, and $25.22 at December 31, 2010, 2009, and 2008, respectively.

The weighted-average remaining contractual life for outstanding options was 4.5 years for 2010. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2010 (thousands of options):

	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding	Weighted-average remaining contractual life	Weighted-average exercise price
$20.49 to $23.40	102	3.0 Years	$22.61
$24.50 to $26.10	94	4.4 Years	$25.78
$29.08 to $33.07	173	5.5 Years	$32.49

The total grant date fair value of options vested was $405,000 and $824,000 during 2009 and 2008, respectively. The Company received $7.3 million in cash from the exercise of options during 2010 and a corresponding tax benefit of $625,000 which was recorded in additional paid-in capital.

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

71 Greener than you think

The Company awards restricted stock and restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/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, 2010 (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		320		$	29.20		146		$	26.47
Granted		137			29.04		85			29.04
Dividends		12					5
Forfeited or expired		—			—		—			—
Vested and issued*		(103	)		35.15		(66	)		27.74
Nonvested at December 31, 2010		366		$	27.54		170		$	27.42

*Includes shares converted for taxes and retiree payouts.

The average grant date fair value of performance shares granted in 2009 and 2008 was $24.46 and $29.31, respectively. The average grant date fair value of restricted stock/units granted in 2009 and 2008 was $24.46 and $27.25, respectively.

72 Southwest Gas Corporation

Note 12 - Income Taxes

As of December 31, 2010 and 2009, 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 2010. The Company expects the balance of unrecognized tax benefits to be reduced to zero 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 $500,000, $200,000, and $900,000 is included in the consolidated statements of income for 2010, 2009, and 2008, respectively. Tax-related interest payable of $100,000 is included in the consolidated balance sheets at December 31, 2010 and December 31, 2009.

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 2006, and is subject to examination by the various state taxing authorities for years after 2005.

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

	2010		2009
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,	2010		2009			2008
Current:
Federal	$	4,204	$	(1,020	)	$	5,420
State		4,442		3,101			1,106
		8,646		2,081			6,526
Deferred:
Federal		44,778		41,410			32,569
State		1,501		1,426			1,740
		46,279		42,836			34,309
Total income tax expense	$	54,925	$	44,917		$	40,835

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

Year Ended December 31,	2010			2009			2008
Deferred federal and state:
Property-related items	$	43,420		$	46,201		$	53,978
Purchased gas cost adjustments		(315	)		(4,167	)		(15,918	)
Employee benefits		8,753			(452	)		(1,884	)
All other deferred		(4,711	)		2,122			(999	)
Total deferred federal and state		47,147			43,704			35,177
Deferred ITC, net		(868	)		(868	)		(868	)
Total deferred income tax expense	$	46,279		$	42,836		$	34,309

The consolidated effective income tax rate for the period ended December 31, 2010 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,	2010			2009			2008
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.8			2.5			2.4
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		(0.3	)		(0.2	)		(0.9	)
Tax credits		(0.5	)		(0.7	)		(0.9	)
Company owned life insurance		(2.3	)		(2.5	)		4.0
All other differences		(0.2	)		(0.3	)		0.3
Consolidated effective income tax rate		34.7	%		34.0	%		40.1	%

74 Southwest Gas Corporation

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

December 31,	2010			2009
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	4,280		$	4,817
Employee benefits		31,384			41,877
Alternative minimum tax credit		15,495			19,894
Interest rate swap		6,973			—
Other		8,026			7,129
		66,158			73,717
Deferred tax liabilities:
Property-related items, including accelerated depreciation		500,216			456,795
Regulatory balancing accounts		836			1,151
Property-related items previously flowed through		3,910			5,014
Unamortized ITC		6,860			7,728
Debt-related costs		4,824			5,011
Other		8,094			11,721
		524,740			487,420
Net deferred tax liabilities	$	458,582		$	413,703
Current	$	(8,046	)	$	(22,410	)
Noncurrent		466,628			436,113
Net deferred tax liabilities	$	458,582		$	413,703

Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (ranging from 25 percent to 50 percent, depending on the jurisdiction) of its natural gas portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2011 through October 2012. 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 14.2 million dekatherms at December 31, 2010 and 13.6 million dekatherms at December 31, 2009). Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.

75 Greener than you think

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2010, 2009, and 2008 and their location in the income statements (thousands of dollars):

Derivatives not designated as hedging instruments:

	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		Year Ended December 31, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008
Swaps	Net cost of gas sold	$	(27,690	)	$	(4,391	)	$	(18,351	)
Swaps	Net cost of gas sold		27,690	*		4,391	*		18,351	*
Total		$	—		$	—		$	—

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

In January 2010, Southwest entered into two forward starting interest rate swaps (“FSIRS”) to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt maturing in February 2011 and $200 million maturing in May 2012. The counterparties to each agreement are four major banking institutions. The first FSIRS was a designated cash flow hedge and had a notional amount of $125 million. It terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. At settlement of the first FSIRS, Southwest paid an aggregate $11.7 million to the counterparties. The second FSIRS has a notional amount of $100 million (with Southwest as the fixed-rate payer at a rate of 4.78%) and has a mandatory termination date on or before March 20, 2012.

Southwest previously designated the second FSIRS agreement as a cash flow hedge of forecasted future interest payments. At the inception of the hedge, the terms of the derivative were the same as a perfect hypothetical derivative; thus, there is an expectation that there will be no ineffectiveness, and that the effective portion of unrealized gains and losses on the FSIRS leading up to the forecasted debt issuance will be reported as a component of other comprehensive income. At termination, the final value will be reclassified from accumulated other comprehensive income into earnings over the terms of the debt issuance which is the same period the hedged forecasted transaction affects earnings. However, should conditions occur that indicate the existence of ineffectiveness (e.g., deterioration of counterparty creditworthiness, delay in the forecasted debt issuances, etc.), Southwest will measure ineffectiveness by comparing changes in the fair value of the FSIRS with changes in the fair value of a hypothetical swap (the hypothetical derivative method). Gains and losses due to ineffectiveness will be recognized immediately in earnings. At December 31, 2010, the remaining FSIRS continued to qualify as an effective hedge. There was no gain or (loss) reclassified from accumulated other comprehensive income (“AOCI”) into income (effective portion) and no gain or (loss) recognized in income (ineffective portion) for the Company’s second derivative designated as a hedging instrument.

76 Southwest Gas Corporation

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

Derivatives designated as hedging instruments:

Gains (losses) on derivatives in cash flow hedging relationships:

	Gains (losses) on interest rate swaps — FSIRS
	Year Ended December 31, 2010
Amount of Gain or (Loss) on Unrealized FSIRS Recognized in Other Comprehensive Income on Derivative (Effective Portion)	$	(6,755	)
Amount of Gain or (Loss) on Realized FSIRS Recognized in Other Comprehensive Income on Derivative		(11,691	)
Total	$	(18,446	)

There were no gains or (losses) on derivatives designated as cash flow hedging instruments for the years ended December 31, 2009 and 2008.

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

Fair values of derivatives not designated as hedging instruments:

December 31, 2010	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	656	$	—		$	656
Swaps	Other current liabilities		65		(11,547	)		(11,482	)
Total		$	721	$	(11,547	)	$	(10,826	)
December 31, 2009	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	85	$	(27	)	$	58
Swaps	Prepaids and other current assets		2,921		(361	)		2,560
Swaps	Other current liabilities		309		(1,730	)		(1,421	)
Swaps	Other deferred credits		25		(100	)		(75	)
Total		$	3,340	$	(2,218	)	$	1,122
Fair values of derivatives designated as hedging instruments:
December 31, 2010	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other deferred credits	$	—	$	(6,755	)	$	(6,755	)

There were no derivatives designated as hedging instruments at December 31, 2009.

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The estimated fair values of the Swaps were determined using future natural gas index prices (as more fully described below). The Company has master netting arrangements with each counterparty that provide for the net settlement of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets.

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. During the year ended December 31, 2010, Southwest paid counterparties $16.6 million in settlement of matured Swaps and received $831,000 from counterparties in settlement of matured Swaps. During the years ended December 31, 2009 and 2008, Southwest paid counterparties $19.7 million and $4.2 million, respectively, in settlements of matured Swaps. Neither changes in the fair value of the Swaps nor realized amounts have a direct effect on earnings or other comprehensive income.

At December 31, 2010, regulatory assets/liabilities offsetting the amounts in the above table were recorded in Prepaids and other current assets ($11.5 million) and Other deferred credits ($656,000). At December 31, 2009, regulatory assets/liabilities offsetting the amounts in the balance sheet were recorded in Prepaids and other current assets ($1.4 million), Other current liabilities ($2.6 million), Other deferred credits ($58,000), and Deferred charges and other assets ($75,000).

Fair Value Measurements.    The estimated fair values of Southwest’s Swaps were determined at December 31, 2010 and 2009 using NYMEX futures settlement prices for delivery of natural gas at Henry Hub, adjusted by the price of New York Mercantile Exchange (“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 estimated fair value of Southwest’s FSIRS was determined using a discounted cash flow model that utilizes forward interest rate curves. The inputs to the model are the terms of the FSIRS. These Level 2 inputs are observable in the marketplace throughout the full term of the FSIRS, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

78 Southwest Gas Corporation

See Note 10 – Pension and Other Postretirement Benefits for definitions of the levels of the fair value hierarchy. The following table sets forth, by level within the fair value hierarchy, the Company’s financial asset and liability derivatives that were accounted for at fair value:

Level 2 - Significant other observable inputs

(Thousands of dollars)	December 31, 2010			December 31, 2009
Assets at fair value:
Prepaids and other current assets — swaps	$	—		$	2,560
Deferred charges and other assets — swaps		656			58
Liabilities at fair value:
Other current liabilities — swaps		(11,482	)		(1,421	)
Other deferred credits — swaps		—			(75	)
Other deferred credits — FSIRS		(6,755	)		—
Net Assets (Liabilities)	$	(17,581	)	$	1,122

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

Related Tax Effects of Designated Hedging Activities Allocated to Each Component of Other Comprehensive Income

	2010
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
(Thousands of dollars)
FSIRS:
Unrealized/realized loss	$	(18,446	)	$	7,010		$	(11,436	)
Amounts reclassified into net income		97			(37	)		60
Other comprehensive (income) loss	$	(18,349	)	$	6,973		$	(11,376	)

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

There were no FSIRS for the years ended December 31, 2009 and 2008.

See Note 5 – Accumulated Other Comprehensive Income for more information on the FSIRS.

Note 14 – Segment Information

Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, transporting, and distributing natural gas. Revenues are

79 Greener than you think

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, 2010 and 2009, accounts receivable for these services totaled $8.1 million and $5.3 million, respectively, which were not eliminated during consolidation.

The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2010 is as follows (thousands of dollars):

2010	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,511,907	$	257,213				$	1,769,120
Intersegment sales		—		61,251					61,251
Total	$	1,511,907	$	318,464				$	1,830,371
Interest revenue	$	158	$	36				$	194
Interest expense	$	77,025	$	564				$	77,589
Depreciation and amortization	$	170,456	$	20,007				$	190,463
Income tax expense	$	47,073	$	7,852				$	54,925
Segment income	$	91,382	$	12,495				$	103,877
Segment assets	$	3,845,111	$	139,082				$	3,984,193
Capital expenditures	$	188,379	$	27,060				$	215,439
2009	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,614,843	$	226,407				$	1,841,250
Intersegment sales		—		52,574					52,574
Total	$	1,614,843	$	278,981				$	1,893,824
Interest revenue	$	189	$	82				$	271
Interest expense	$	81,822	$	1,179				$	83,001
Depreciation and amortization	$	166,850	$	23,232				$	190,082
Income tax expense	$	40,451	$	4,466				$	44,917
Segment income	$	79,420	$	8,062				$	87,482
Segment assets	$	3,782,913	$	124,755	$	(1,376	)	$	3,906,292
Capital expenditures	$	212,919	$	4,066				$	216,985

80 Southwest Gas Corporation

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

(a) Construction services segment assets include income taxes payable of $1.4 million in 2009, which were netted against gas operations segment income taxes receivable, net during consolidation.

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Note 15 - Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2010
Operating revenues	$	668,751	$	385,825		$	307,683		$	468,112
Operating income		121,732		24,031			184			86,170
Net income (loss)		64,648		(933	)		(4,823	)		44,985
Basic earnings (loss) per common share*		1.43		(0.02	)		(0.11	)		0.99
Diluted earnings (loss) per common share*		1.42		(0.02	)		(0.11	)		0.98
2009
Operating revenues	$	689,862	$	387,648		$	317,509		$	498,805
Operating income		102,729		14,685			522			90,455
Net income (loss)		49,981		(594	)		(8,297	)		46,392
Basic earnings (loss) per common share*		1.13		(0.01	)		(0.18	)		1.03
Diluted earnings (loss) per common share*		1.12		(0.01	)		(0.18	)		1.02
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

* 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.

82 Southwest Gas Corporation

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2010. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 28, 2011

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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 equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 28, 2011

84 Southwest Gas Corporation