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Exhibit 13.01

Consolidated Selected Financial Statistics

Year Ended December 31,	2011			2010			2009			2008			2007
(Thousands of dollars, except per share amounts)
Operating revenues	$	1,887,188		$	1,830,371		$	1,893,824		$	2,144,743		$	2,152,088
Operating expenses		1,637,108			1,598,254			1,685,433			1,936,881			1,929,788
Operating income	$	250,080		$	232,117		$	208,391		$	207,862		$	222,300
Net income	$	112,287		$	103,877		$	87,482		$	60,973		$	83,246
Total assets at year end	$	4,276,007		$	3,984,193		$	3,906,292		$	3,820,384		$	3,670,188
Capitalization at year end
Total equity	$	1,225,031		$	1,166,996		$	1,102,086		$	1,037,841		$	983,673
Subordinated debentures		—			—			100,000			100,000			100,000
Long-term debt, excluding current maturities		930,858			1,124,681			1,169,357			1,185,474			1,266,067
	$	2,155,889		$	2,291,677		$	2,371,443		$	2,323,315		$	2,349,740
Current maturities of long-term debt	$	322,618		$	75,080		$	1,327		$	7,833		$	38,079
Common stock data
Common equity percentage of capitalization		56.8	%		50.9	%		46.5	%		44.7	%		41.9	%
Return on average common equity		9.3	%		9.1	%		8.1	%		6.0	%		8.8	%
Basic earnings per share	$	2.45		$	2.29		$	1.95		$	1.40		$	1.97
Diluted earnings per share	$	2.43		$	2.27		$	1.94		$	1.39		$	1.95
Dividends declared per share	$	1.06		$	1.00		$	0.95		$	0.90		$	0.86
Payout ratio		43	%		44	%		49	%		64	%		44	%
Book value per share at year end	$	26.68		$	25.60		$	24.44		$	23.48		$	22.98
Market value per share at year end	$	42.49		$	36.67		$	28.53		$	25.22		$	29.77
Market value per share to book value per share		159	%		143	%		117	%		107	%		130	%
Common shares outstanding at year end (000)		45,956			45,599			45,092			44,192			42,806
Number of common shareholders at year end		16,834			17,821			20,489			22,244			22,664
Ratio of earnings to fixed charges		3.21			2.87			2.46			2.01			2.25

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Natural Gas Operations

Year Ended December 31,	2011			2010			2009			2008			2007
(Thousands of dollars)
Sales	$	1,329,512		$	1,438,809		$	1,547,081		$	1,728,924		$	1,754,913
Transportation		73,854			73,098			67,762			62,471			59,853
Operating revenue		1,403,366			1,511,907			1,614,843			1,791,395			1,814,766
Net cost of gas sold		613,489			736,175			866,630			1,055,977			1,086,194
Operating margin		789,877			775,732			748,213			735,418			728,572
Expenses
Operations and maintenance		358,498			354,943			348,942			338,660			331,208
Depreciation and amortization		175,253			170,456			166,850			166,337			157,090
Taxes other than income taxes		40,949			38,869			37,318			36,780			37,553
Operating income	$	215,177		$	211,464		$	195,103		$	193,641		$	202,721
Contribution to consolidated net income	$	91,420		$	91,382		$	79,420		$	53,747		$	72,494
Total assets at year end	$	4,048,613		$	3,845,111		$	3,782,913		$	3,680,327		$	3,518,304
Net gas plant at year end	$	3,218,944		$	3,072,436		$	3,034,503		$	2,983,307		$	2,845,300
Construction expenditures and property additions	$	305,542		$	188,379		$	212,919		$	279,254		$	312,412
Cash flow, net
From operating activities	$	216,745		$	342,522		$	371,416		$	261,322		$	320,594
From (used in) investing activities		(289,234	)		(178,685	)		(265,850	)		(237,093	)		(306,396	)
From (used in) financing activities		(2,327	)		(107,779	)		(81,744	)		(34,704	)		(5,347	)
Net change in cash	$	(74,816	)	$	56,058		$	23,822		$	(10,475	)	$	8,851
Total throughput (thousands of therms)
Residential		718,765			704,693			669,736			704,986			698,063
Small commercial		303,923			300,940			294,225			314,555			310,666
Large commercial		112,256			111,833			117,241			125,121			127,561
Industrial/Other		50,208			58,922			72,623			97,702			103,525
Transportation		941,544			998,600			1,043,894			1,164,190			1,128,422
Total throughput		2,126,696			2,174,988			2,197,719			2,406,554			2,368,237
Weighted average cost of gas purchased ($/therm)	$	0.58		$	0.62		$	0.71		$	0.84		$	0.81
Customers at year end		1,859,000			1,837,000			1,824,000			1,819,000			1,813,000
Employees at year end		2,298			2,349			2,423			2,447			2,538
Customer to employee ratio		809			782			753			743			714
Degree days – actual		2,002			1,998			1,824			1,902			1,850
Degree days – ten-year average		1,888			1,876			1,882			1,893			1,936

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

About Southwest Gas Corporation

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

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

As of December 31, 2011, Southwest had 1,859,000 residential, commercial, industrial, and other natural gas customers, of which 1,001,000 customers were located in Arizona, 674,000 in Nevada, and 184,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2011, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 86% of operating margin from residential and small commercial customers, 4% from other sales customers, and 10% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting operating margin are general rate relief, weather, conservation and efficiencies, and customer growth. Weather has traditionally been the primary reason for volatility in margin, which continued throughout 2011 with respect to Southwest’s Arizona service territories. In January 2012, however, a full revenue decoupling mechanism, which includes a monthly weather adjuster, was implemented in the Arizona service territories. With this change, all of Southwest’s service territories now have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on margin and allow the Company to aggressively pursue energy efficiency iniatives.

NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in 18 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs coupled with bonus depreciation tax deduction incentives have resulted in a significant increase in multi-year pipeline replacement projects throughout the country. NPL has successfully captured some of these additional projects.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and are covered in greater detail in later sections of management’s discussion and analysis. The natural gas operations segment accounted for an average of 86% of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

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Summary Operating Results

Year ended December 31,	2011		2010		2009
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	91,420	$	91,382	$	79,420
Construction services		20,867		12,495		8,062
Consolidated	$	112,287	$	103,877	$	87,482
Average number of common shares outstanding		45,858		45,405		44,752
Basic earnings per share
Consolidated	$	2.45	$	2.29	$	1.95
Natural Gas Operations
Operating margin	$	789,877	$	775,732	$	748,213

2011 Overview

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

Natural gas operations highlights include the following:

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

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

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

• Net financing costs decreased $8 million between 2011 and 2010

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

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

Construction services highlights include the following:

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

• Contribution to net income increased $8 million

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

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

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

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

Customer Growth.    Southwest completed 13,000 first-time meter sets, but realized 22,000 net new customers over the last twelve months. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth associated with new meter sets of 1% or less for 2012, along with the gradual return of customers from previously vacant homes.

Company-Owned Life Insurance (“COLI”).    Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $227 million at December 31, 2011. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $74 million at December 31, 2011 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. As indicated in Note 1, income from changes in the cash surrender value of COLI policies and recognized net death benefits was $700,000 in 2011 and $9.8 million in 2010. Management currently expects average returns of $2 million to $4 million annually on the COLI policies, excluding any net death benefits recognized. Based on the current investment mix, both positive and negative deviations from expected levels are likely to continue.

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

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

Southwest also believes its ability to obtain funding for ongoing expenditures and future expansions is secure and adequate. Historically, Southwest has accessed the public debt markets for funding, most recently in February 2011 in connection with the issuance of $125 million of 6.1% Senior Notes to certain institutional investors. Other than replacing $200 million of debt maturing in May 2012, and securing a replacement credit facility, Southwest has no long-term debt maturities until 2017. In January 2012, Southwest redeemed $12.4 million in 6.1% Clark County Series A Industrial Development Revenue Bonds (“IDRBs”) at par originally due in 2038.

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Results of Natural Gas Operations

Year Ended December 31,	2011			2010		2009
(Thousands of dollars)
Gas operating revenues	$	1,403,366		$	1,511,907	$	1,614,843
Net cost of gas sold		613,489			736,175		866,630
Operating margin		789,877			775,732		748,213
Operations and maintenance expense		358,498			354,943		348,942
Depreciation and amortization		175,253			170,456		166,850
Taxes other than income taxes		40,949			38,869		37,318
Operating income		215,177			211,464		195,103
Other income (deductions)		(5,404	)		4,016		6,590
Net interest deductions		68,777			75,113		74,091
Net interest deductions on subordinated debentures		—			1,912		7,731
Income before income taxes		140,996			138,455		119,871
Income tax expense		49,576			47,073		40,451
Contribution to consolidated net income	$	91,420		$	91,382	$	79,420

2011 vs. 2010

The contribution to consolidated net income from natural gas operations was relatively unchanged between 2011 and 2010; however, operating income improved by $3.7 million between years. An increase in operating margin and reduced financing costs were offset by higher operating expenses and a decrease in other income.

Operating margin increased $14 million between periods. Differences in heating demand, caused primarily by weather variations, accounted for the $14 million increase as colder-than-normal temperatures were experienced in Arizona in 2011. Incremental margin from rate relief in California ($2 million) and new customers ($2 million) was offset by the out-of-period adjustment recorded during the third quarter of 2011, related to a regulatory deferral mechanism.

Operations and maintenance expense increased $3.6 million, or 1%, between periods primarily due to general cost increases, partially offset by favorable claims experience under Southwest’s self-insured medical plan. The increase also includes approximately $1 million of costs associated with restoring service to approximately 20,000 Arizona customers in early February 2011, following an outage due to extreme weather conditions. Cost containment efforts (including lower staffing levels) mitigated the increases.

Depreciation expense increased $4.8 million, or 3%, as a result of additional plant in service. Average gas plant in service for 2011 increased $151 million, or 3%, as compared to 2010. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business.

Taxes other than income taxes increased $2.1 million primarily due to higher property tax rates in Arizona.

Other income, which principally includes returns on COLI policies and non-utility expenses, declined $9.4 million between 2011 and 2010. The current year reflects COLI-related income (resulting from recognized death benefits net of decreases in cash surrender values) of $700,000, while the prior year included income of $9.8 million due to an increase in COLI cash surrender values and recognized net death benefits. COLI income in the previous year was especially high due to strong equity-market returns on investments underlying the policies.

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Net financing costs decreased $8.2 million between 2011 and 2010 primarily due to the redemption of $100 million of subordinated debentures in March 2010, cost savings from debt refinancing, and reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs).

Income tax expense includes $1.6 million of previously unrecognized tax benefits and related interest associated with the expiration of the statute of limitations with respect to a previously recorded uncertain tax position.

2010 vs. 2009

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

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

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

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

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

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

Outlook for 2012

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

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

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

Rates and Regulatory Proceedings

General Rate Relief and Rate Design

Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management has worked with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Effective January 2012, such rate structures are in place in all of Southwest’s operating areas.

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

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

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

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

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

Southwest Gas Corporation 27

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

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

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

Pipe Replacement Tracking Mechanisms

Customer-Owned Yardline (“COYL”) Program.    There are approximately 100,000 customers in Arizona whose natural gas meters are set-off away from the customer’s home (e.g., near a backyard property line), as opposed to a more traditional configuration in which the meter is adjacent to the home. Under the COYL configuration, the customer owns, operates, and is responsible for maintaining the service line that runs from the meter to the home. As these lines age, they periodically develop low pressure leaks which result in immediate termination of natural gas service, and a subsequent need for the customer to repair or replace the COYL prior to service restoration. To address the cost normally borne by the customer to repair or replace the COYL, the Company received approval to implement a new program (as part of its recent Arizona rate case decision) under which the Company will replace the customer’s facilities at no immediate direct cost to the customer, and relocate the customer’s meter adjacent to the home, thereby eliminating the customer’s previous operating and maintenance responsibilities associated with the COYL. In addition, the program provides for the Company to endeavor to leak survey all such COYLs over a 3-year period; anticipated costs for the survey are reflected in current rates. The costs of the replacement portion of this program will be capitalized by the Company. Subject to an annual reporting requirement, a surcharge will be added to all bills to recover an amount approximately equal to the amount that the Company would have earned if the additional pipe replacement costs had been included in the rate base amount filed in the recently concluded Arizona rate case. Recovery of the surcharge will cease as of the next Arizona general rate case (as the expenditures will then be included in rate base).

Nevada Pipe Replacement Program.    The Company has identified specific pipe replacement projects (including early vintage plastic pipe) for accelerated replacement in its Northern Nevada jurisdiction during 2011 and for its Southern Nevada jurisdiction during 2011 and 2012. The PUCN has authorized Southwest to accumulate the incremental depreciation and carrying costs associated with these projects as a regulatory asset through January 2015, by which time any accumulated costs must be reflected in rates pursuant to a general rate case filing, or become subject to an eight-year amortization period; recovery of unamortized post-2015 balances may also be requested in a general rate case filing.

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PGA Filings

The rate schedules in all of Southwest’s service territories contain provisions that permit adjustments to rates as the cost of purchased gas changes. These deferred energy provisions and purchased gas adjustment clauses are collectively referred to as “PGA” clauses. Differences between gas costs recovered from customers and amounts paid for gas by Southwest result in over- and under-collections. At December 31, 2011, over-collections in Arizona and Nevada resulted in a liability of $72.4 million and under-collections in California resulted in an asset of $2.3 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

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

	2011			2010
Arizona	$	(28.4	)	$	(45.2	)
Northern Nevada		(7.9	)		(8.4	)
Southern Nevada		(36.1	)		(69.8	)
California		2.3			0.4
	$	(70.1	)	$	(123.0	)

Arizona PGA Filings.    In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits measured on a twelve-month rolling average. A temporary surcredit of $0.08 per therm was put into place in December 2009 to help accelerate the refund of the over-collected balance to customers, which continued throughout 2011. On an annual basis, the surcredit is designed to refund approximately $40 million; however, continued low natural gas prices have resulted in a continuing balance due customers. A prudence review of gas costs is conducted in conjunction with general rate cases.

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

Nevada Annual Rate Adjustment (“ARA”) Application.    In June 2011, Southwest filed its ARA application with the PUCN to establish revised Deferred Energy Account Adjustment (“DEAA”) rates (in addition to adjustments to the Variable Interest Expense Recovery, the Uncollectible Gas Cost Expense rates, and other rate-related items). Recently approved legislation allows Southwest to make quarterly DEAA adjustments based upon a twelve-month rolling average. Southwest filed its first quarterly DEAA rate adjustment application under the new rules in July 2011, which was approved, and was made effective in October 2011.

Gas Price Volatility Mitigation

Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and fixed-for-floating swap contracts (“Swaps”) under its collective volatility mitigation programs for a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its annual normal weather supply needs. For the 2011/2012 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $7 per dekatherm. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities, and on the spot market. Prices for these contracts are not known until the month of purchase.

Southwest Gas Corporation 29

Capital Resources and Liquidity

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

Cash Flows

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

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

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

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

2011 Construction Expenditures

During the three-year period ended December 31, 2011, total gas plant increased from $4.3 billion to $4.8 billion, or at an average annual rate of 4%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as the Company set 48,000 meters, resulting in 40,000 net new customers during the three-year period.

During 2011, construction expenditures for the natural gas operations segment were $306 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant (see also Bonus Depreciation below). Cash flows from operating activities of Southwest were $217 million and provided approximately 61% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and existing credit facilities.

Southwest Gas Corporation 30

2011 Financing Activity

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

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

During 2011, the Company issued shares of common stock through its various stock plans, including the Stock Incentive Plan, raising approximately $7 million.

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

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

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2014 will range from approximately $750 million to $1 billion. Of this amount, approximately $300 million are expected to be incurred in 2012. Southwest is taking advantage of bonus depreciation to accelerate projects that improve system flexibility and enhance safety (including replacement of early vintage plastic and steel pipe). Significant replacement projects are expected to continue during the next several years. During the three-year period, cash flows from operating activities of Southwest (including the bonus depreciation benefits) are expected to provide a substantial majority of the funding for the gas operations total construction expenditures and dividend requirements. During the three-year period, the Company expects to raise additional funds from its various common stock programs. Southwest also has $12.8 million in restricted cash from a 2009 Industrial Development Revenue Bond offering that was drawn upon in February 2012 to fund qualifying construction expenditures in southern Nevada. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

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

Southwest Gas Corporation 31

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

Liquidity

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

On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2011, the combined balance in the PGA accounts totaled an over-collection of $70.1 million. See PGA Filings for more information on recent regulatory filings.

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

Credit Ratings

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

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

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

The Company’s unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is Baa2 with a stable outlook as of May 2010. Moody’s applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.

Southwest Gas Corporation 32

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

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2011, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.6 billion in additional debt and meet the leverage ratio requirement. The Company has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Inflation

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

Off-Balance Sheet Arrangements

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

Contractual Obligations

The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statement of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Company’s contractual obligations at December 31, 2011 (millions of dollars):

	Payments due by period
Contractual Obligations	Total		2012		2013-2014		2015-2016		Thereafter
Operating activities:
Operating leases (Note 2)	$	22	$	6	$	9	$	6	$	1
Gas purchase obligations		212		154		57		1		—
Pipeline capacity		803		95		167		139		402
Derivatives (Note 13)		37		36		1		—		—
Other commitments		11		6		4		1		—
Financing activities:
Long-term debt, including current maturities (Note 7)		1,253		323		19		1		910
Interest on long-term debt		881		46		89		89		657
Other		16		—		1		2		13
Total	$	3,235	$	666	$	347	$	239	$	1,983

Southwest Gas Corporation 33

Obligations for Operating Activities:    The table provides a summary of the Company’s obligations associated with operating activities. Operating leases represent multi-year obligations for office rent and certain equipment. Gas purchase obligations include fixed-price and variable-rate gas purchase contracts covering approximately 165 million dekatherms. Fixed-price contracts range in price from approximately $4 to $7 per dekatherm. Variable-price contracts reflect minimum contractual obligations.

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

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

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

Results of Construction Services

Year Ended December 31,	2011			2010			2009
(Thousands of dollars)
Construction revenues	$	483,822		$	318,464		$	278,981
Operating expenses:
Construction expenses		423,703			277,804			242,461
Depreciation and amortization		25,216			20,007			23,232
Operating income		34,903			20,653			13,288
Other income (deductions)		(8	)		(166	)		55
Net interest deductions		825			564			1,179
Income before income taxes		34,070			19,923			12,164
Income tax expense		13,727			7,852			4,466
Net income		20,343			12,071			7,698
Net income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)
Contribution to consolidated net income attributable to NPL	$	20,867		$	12,495		$	8,062

2011 vs. 2010

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

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

Revenues increased $165 million, a 52% improvement, when compared to 2010 primarily due to increased replacement construction. The construction revenues include NPL contracts with Southwest totaling $92.1 million in 2011 and $61.3 million in 2010. NPL accounts for the services provided to Southwest at contractual (market) prices.

Southwest Gas Corporation 34

Construction expenses increased $146 million, or 53%, between years due primarily to costs associated with the increase in replacement construction work. Depreciation expense increased $5.2 million as a result of an increase in the construction equipment fleet. Interest expense increased $261,000 between years due to an increase in outstanding debt.

NPL’s revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Typically, revenues and profit are lowest during the first quarter of the year due to unfavorable winter weather conditions. Operating results typically improve as more favorable weather conditions occur during the summer and fall months. Current low interest rates, the impact of bonus depreciation legislation, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure), are having a positive influence on NPL’s growth and resulting earnings.

2010 vs. 2009

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

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

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

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

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates dealing with the presentation of comprehensive income, disclosures about fair value measurements, goodwill impairment testing, and the offsetting of assets and liabilities on the balance sheets. See Note 1 - Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on the Company’s financial position, results of operations, and disclosures.

Application of Critical Accounting Policies

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

Southwest Gas Corporation 35

Regulatory Accounting

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

Accrued Utility Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, net revenues for natural gas that has been delivered but not yet billed are accrued. This accrued utility revenue is estimated each month based on daily sales volumes, applicable rates, number of customers, rate structure, analyses reflecting significant historical trends, weather, and experience. In periods of extreme weather conditions, the interplay of these assumptions could impact the variability of the accrued utility revenue estimates. The California and Nevada rate jurisdictions have decoupled rate structures in place such that when combined with Arizona’s decoupled rate structure effective January 2012, variability due to extreme weather conditions will be significantly reduced.

Accounting for Income Taxes

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

Accounting for Pensions and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Company’s pension obligations and costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans. For example, a change of 0.25% in the discount rate assumption would change the pension plan projected benefit obligation by approximately $24.8 million and future pension expense by $2.7 million. A change of

Southwest Gas Corporation 36

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

At December 31, 2011, the Company lowered the discount rate to 5.00% from a rate of 5.75% at December 31, 2010. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase decreased to 3.00% at December 31, 2011 from 3.25% in the prior year. The asset return assumption remains the same at 8.00%. Low asset returns were experienced during 2011, relative to the assumed rate of return. This, combined with significant favorable returns in 2010 and 2009, partially offset substantial losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2012. Pension expense for 2012 is estimated to increase by $7.5 million. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Certifications

The SEC requires the Company to file certifications of its Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to the Company’s periodic filings. The CEO and CFO certifications for the period ended December 31, 2011 are included as exhibits to the 2011 Annual Report on Form 10-K filed with the SEC.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” “forecast,” “intend,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, amount and timing for completion of estimated future construction expenditures, forecasted operating cash flows and results of operations, incremental margin in 2012, operating expense increases in 2012, funding sources of cash requirements, sufficiency of working capital, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, the amount and form of any such financing, plans to fund maturing obligations, expected interest rate upon refinancing maturing debt. the effectiveness of forward-starting interest rate swap agreements in hedging against changing interest rates, future dividend increases, earnings trends, pension and post-retirement benefits, liquidity, certain benefits of tax acts, the effect of rate decoupling in Arizona, the impact of fuel switching by large customers, expenditures for compliance with any EPA requirements, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, and the impact of certain legal proceedings are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, renewal of franchises, easements and rights-of-way, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related

Southwest Gas Corporation 37

thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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

Common Stock Price and Dividend Information

	2011				2010				Dividends Declared
	High		Low		High		Low		2011		2010
First quarter	$	39.68	$	36.33	$	30.70	$	26.28	$	0.265	$	0.250
Second quarter		40.59		36.61		32.91		28.12	$	0.265	$	0.250
Third quarter		39.92		32.12		34.06		28.58	$	0.265	$	0.250
Fourth quarter		43.20		34.55		37.25		33.41	$	0.265	$	0.250
									$	1.060	$	1.000

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2012, there were 16,668 holders of record of common stock, and the market price of the common stock was $41.86.

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

Southwest Gas Corporation 38

Southwest Gas Corporation

Consolidated Balance Sheets

(Thousands of dollars, except par value)

December 31,	2011			2010
ASSETS
Utility plant:
Gas plant	$	4,811,050		$	4,569,105
Less: accumulated depreciation		(1,638,091	)		(1,535,429	)
Acquisition adjustments, net		1,091			1,271
Construction work in progress		44,894			37,489
Net utility plant (Note 2)		3,218,944			3,072,436
Other property and investments		192,004			134,648
Restricted cash		12,785			37,781
Current assets:
Cash and cash equivalents		21,937			116,096
Accounts receivable, net of allowances (Note 3)		209,246			147,605
Accrued utility revenue		70,300			64,400
Income taxes receivable, net		7,793			21,514
Deferred income taxes (Note 12)		53,435			8,046
Deferred purchased gas costs (Note 4)		2,323			356
Prepaids and other current assets (Note 4)		96,598			87,877
Total current assets		461,632			445,894
Deferred charges and other assets (Notes 4 and 13)		390,642			293,434
Total assets	$	4,276,007		$	3,984,193

Southwest Gas Corporation 39

Consolidated Balance Sheets - Continued

December 31,	2011			2010
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized - 60,000,000 shares; issued and outstanding - 45,956,088 and 45,599,036 shares) (Note 11)	$	47,586		$	47,229
Additional paid-in capital		821,640			807,885
Accumulated other comprehensive income (loss), net (Note 5)		(49,331	)		(30,784	)
Retained earnings		406,125			343,131
Total Southwest Gas Corporation equity		1,226,020			1,167,461
Noncontrolling interest		(989	)		(465	)
Total equity		1,225,031			1,166,996
Long-term debt, less current maturities (Note 7)		930,858			1,124,681
Total capitalization		2,155,889			2,291,677
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)		322,618			75,080
Accounts payable		186,755			165,536
Customer deposits		83,839			86,891
Accrued general taxes		42,102			40,438
Accrued interest		16,699			20,162
Deferred purchased gas costs (Note 4)		72,426			123,344
Other current liabilities (Notes 4 and 13)		123,129			85,510
Total current liabilities		847,568			596,961
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 12)		557,118			466,628
Taxes payable		828			1,234
Accumulated removal costs (Note 4)		233,000			211,000
Other deferred credits (Notes 4 and 10)		481,604			416,693
Total deferred income taxes and other credits		1,272,550			1,095,555
Total capitalization and liabilities	$	4,276,007		$	3,984,193

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 40

Southwest Gas Corporation

Consolidated Statements of Income

(In thousands, except per share amounts)

Year Ended December 31,	2011			2010			2009
Operating revenues:
Gas operating revenues	$	1,403,366		$	1,511,907		$	1,614,843
Construction revenues		483,822			318,464			278,981
Total operating revenues		1,887,188			1,830,371			1,893,824
Operating expenses:
Net cost of gas sold		613,489			736,175			866,630
Operations and maintenance		358,498			354,943			348,942
Depreciation and amortization		200,469			190,463			190,082
Taxes other than income taxes		40,949			38,869			37,318
Construction expenses		423,703			277,804			242,461
Total operating expenses		1,637,108			1,598,254			1,685,433
Operating income		250,080			232,117			208,391
Other income and (expenses):
Net interest deductions (Notes 7 and 8)		(69,602	)		(75,677	)		(75,270	)
Net interest deductions on subordinated debentures (Note 6)		—			(1,912	)		(7,731	)
Other income (deductions)		(5,412	)		3,850			6,645
Total other income and (expenses)		(75,014	)		(73,739	)		(76,356	)
Income before income taxes		175,066			158,378			132,035
Income tax expense (Note 12)		63,303			54,925			44,917
Net income		111,763			103,453			87,118
Net income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)
Net income attributable to Southwest Gas Corporation	$	112,287		$	103,877		$	87,482
Basic earnings per share (Note 15)	$	2.45		$	2.29		$	1.95
Diluted earnings per share (Note 15)	$	2.43		$	2.27		$	1.94
Average number of common shares outstanding		45,858			45,405			44,752
Average shares outstanding (assuming dilution)		46,291			45,823			45,062

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 41

Southwest Gas Corporation

Consolidated Statements of Comprehensive Income

(Thousands of dollars)

Year Ended December 31,	2011			2010			2009
Net Income	$	111,763		$	103,453		$	87,118
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)		(84,005	)		(5,616	)		(16,398	)
Amortization of prior service credit		—			—			(1	)
Amortization of transition obligation		537			538			538
Amortization of net loss		9,653			7,516			3,470
Regulatory adjustment		65,677			404			9,567
Net defined benefit pension plans		(8,138	)		2,842			(2,824	)
Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 13)		(11,134	)		(11,436	)		—
Amounts reclassified into net income (Notes 5 and 13)		725			60			—
Net forward-starting interest rate swaps		(10,409	)		(11,376	)		—
Total other comprehensive income (loss), net of tax		(18,547	)		(8,534	)		(2,824	)
Comprehensive income	$	93,216		$	94,919		$	84,294
Comprehensive income (loss) attributable to noncontrolling interest		(524	)		(424	)		(364	)
Comprehensive income attributable to Southwest Gas Corporation	$	93,740		$	95,343		$	84,658

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 42

Southwest Gas Corporation

Consolidated Statements of Cash Flows

(Thousands of dollars)

Year Ended December 31,	2011			2010			2009
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	111,763		$	103,453		$	87,118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		200,469			190,463			190,082
Deferred income taxes		56,467			50,111			42,798
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(61,641	)		10,117			11,107
Accrued utility revenue		(5,900	)		7,300			900
Deferred purchased gas costs		(52,885	)		33,013			56,902
Accounts payable		15,826			6,680			(32,578	)
Accrued taxes		14,979			(15,240	)		22,497
Other current assets and liabilities		(3,347	)		12,895			32,733
Gains on sale		(3,307	)		(1,547	)		(3,291	)
Changes in undistributed stock compensation		6,125			4,429			3,942
AFUDC and property-related changes		(1,154	)		(945	)		(1,221	)
Changes in other assets and deferred charges		11,025			(12,262	)		(15,553	)
Changes in other liabilities and deferred credits		(36,378	)		(17,474	)		10,366
Net cash provided by operating activities		252,042			370,993			405,802

Southwest Gas Corporation 43

Consolidated Statements of Cash Flows - Continued

Year Ended December 31,	2011			2010			2009
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(380,991	)		(215,439	)		(216,985	)
Restricted cash		24,996			11,988			(49,769	)
Changes in customer advances		(7,771	)		(830	)		(2,476	)
Miscellaneous inflows		7,686			4,075			7,933
Miscellaneous outflows		(2,719	)		(2,800	)		(3,620	)
Net cash provided by (used in) investing activities		(358,799	)		(203,006	)		(264,917	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		7,402			11,098			18,401
Dividends paid		(47,929	)		(44,846	)		(41,950	)
Interest rate swap settlement		—			(11,691	)		—
Issuance of long-term debt, net		274,598			123,960			49,834
Retirement of long-term debt		(330,473	)		(3,327	)		(15,654	)
Redemption of subordinated debentures		—			(100,000	)		—
Change in credit facility		109,000			(92,400	)		(57,600	)
Change in short-term debt		—			—			(55,000	)
Net cash provided by (used in) financing activities		12,598			(117,206	)		(101,969	)
Change in cash and cash equivalents		(94,159	)		50,781			38,916
Cash and cash equivalents at beginning of period		116,096			65,315			26,399
Cash and cash equivalents at end of period	$	21,937		$	116,096		$	65,315
Supplemental information:
Interest paid, net of amounts capitalized	$	69,842		$	87,000		$	80,771
Income taxes paid (received)	$	(13,635	)	$	19,200		$	(21,616	)

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 44

Southwest Gas Corporation

Consolidated Statements of Equity

(In thousands, except per share amounts)

Southwest Gas Corporation Equity
	Common Stock					Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total
	Shares			Amount
DECEMBER 31, 2008		44,192		$	45,822	$	770,463	$	(19,426	)	$	240,982		$	—		$	1,037,841
Common stock issuances		900			900		21,876											22,776
Net income (loss)												87,482			(364	)		87,118
Noncontrolling interest capital investment															323			323
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)									(2,824	)								(2,824	)
Dividends declared Common: $0.95 per share												(43,148	)					(43,148	)
DECEMBER 31, 2009		45,092			46,722		792,339		(22,250	)		285,316			(41	)		1,102,086
Common stock issuances		507			507		15,546											16,053
Net income (loss)												103,877			(424	)		103,453
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)									2,842									2,842
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13)									(11,436	)								(11,436	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)									60									60
Dividends declared Common: $1.00 per share												(46,062	)					(46,062	)
DECEMBER 31, 2010		45,599			47,229		807,885		(30,784	)		343,131			(465	)		1,166,996
Common stock issuances		357			357		13,755											14,112
Net income (loss)												112,287			(524	)		111,763
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)									(8,138	)								(8,138	)
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13)									(11,134	)								(11,134	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)									725									725
Dividends declared Common: $1.06 per share												(49,293	)					(49,293	)
DECEMBER 31, 2011		45,956	*	$	47,586	$	821,640	$	(49,331	)	$	406,125		$	(989	)	$	1,225,031

*At December 31, 2011, 2.1 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 177,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 11).

The accompanying notes are an integral part of these statements.

Southwest Gas Corporation 45

Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

Nature of Operations.    Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. Natural gas purchases and the timing of related recoveries can materially impact liquidity. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary.

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

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

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

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

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

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

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

Southwest Gas Corporation 46

Accumulated Removal Costs.    Approved regulatory practices allow Southwest to include in depreciation expense a component to recover removal costs associated with utility plant retirements. In accordance with the Securities and Exchange Commission’s (“SEC”) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):

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

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

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

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

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

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

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

Depreciation and Amortization.    Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for removal costs (net of salvage value), and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are

Southwest Gas Corporation 47

depreciated on a straight-line method based on the estimated useful lives of the related assets. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense.

Allowance for Funds Used During Construction (“AFUDC”).    AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.

	2011		2010		2009
(In thousands)
AFUDC:
Debt portion	$	718	$	512	$	957
Equity portion		1,154		945		1,221
AFUDC capitalized as part of utility plant	$	1,872	$	1,457	$	2,178

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

	2011			2010			2009
Change in COLI policies	$	700		$	9,770		$	8,546
Interest income		485			194			271
Pipe replacement costs		(4,761	)		(5,024	)		(2,642	)
Miscellaneous income and (expense)		(1,836	)		(1,090	)		470
Total other income (deductions)	$	(5,412	)	$	3,850		$	6,645

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

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

	2011		2010		2009
(In thousands)
Average basic shares		45,858		45,405		44,752
Effect of dilutive securities:
Stock options		52		56		14
Performance shares		271		260		216
Restrictled stock units		110		102		80
Average diluted shares		46,291		45,823		45,062

Southwest Gas Corporation 48

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

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

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

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

In December 2011, the FASB issued the update “Balance Sheet (Topic 210).” The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entity’s financial statements to understand the effect of those arrangements on the entity’s financial position. The Company will adopt this update, as required, on January 1, 2013 for interim and annual reporting periods. All disclosures are required to be provided retrospectively for all periods presented. This update is not expected to have a material impact on the Company’s disclosures.

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

Southwest Gas Corporation 49

Note 2 – Utility Plant

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

December 31,	2011			2010
Gas plant:
Storage	$	20,496		$	20,396
Transmission		295,103			274,646
Distribution		4,048,078			3,847,731
General		291,639			279,402
Other		155,734			146,930
		4,811,050			4,569,105
Less: accumulated depreciation		(1,638,091	)		(1,535,429	)
Acquisition adjustments, net		1,091			1,271
Construction work in progress		44,894			37,489
Net utility plant	$	3,218,944		$	3,072,436

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

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

Operating Leases and Rentals.    Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The table below presents the rental payments and the current term expiration dates, although both leases have optional renewal terms available.

	2012		2013		2014		2015		2016		2017
(In thousands)
Corporate headquarters (expires in 2017)	$	2,100	$	2,140	$	2,190	$	2,270	$	2,343	$	1,194
Phoenix administrative offices (expires in 2014)		1,396		1,446		243		—		—		—

In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. NPL has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest rental payments and NPL lease payments that are included in operating expenses for all operating leases (in thousands):

	2011		2010		2009
Southwest Gas	$	7,812	$	7,585	$	8,630
NPL		19,017		11,780		11,301
Consolidated rental payments/lease expense	$	26,829	$	19,365	$	19,931

Southwest Gas Corporation 50

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

Year Ending December 31,
2012	$	6,310
2013		5,674
2014		3,358
2015		2,881
2016		2,449
Thereafter		1,194
Total minimum lease payments	$	21,866

Note 3 - Receivables and Related Allowances

Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. The table below contains information about the gas utility customer accounts receivable balance at December 31, 2011, and the percentage of customers in each of the three states.

Gas utility customer accounts receivable balance (in thousands)	$	124,794
Percent of customers by state
Arizona		54	%
Nevada		36	%
California		10	%

Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Customer accounts are subject to collection procedures that vary by jurisdiction (late fee assessment, noticing requirements for disconnection of service, and procedures for actual disconnection and/or reestablishment of service). After disconnection of service, accounts are generally written off approximately one month after inactivation. Dependent upon the jurisdiction, reestablishment of service requires both payment of previously unpaid balances and additional deposit requirements. Provisions for uncollectible accounts are based on experience and recorded monthly, as needed. They are included in the ratemaking process as a cost of service. Beginning in November 2009, a regulatory mechanism was implemented in the Nevada jurisdictions associated with the gas cost-related portion of uncollectible accounts. Such amounts are deferred and collected through a surcharge in the ratemaking process. Activity in the allowance account for uncollectibles is summarized as follows (thousands of dollars):

	Allowance for Uncollectibles
Balance, December 31, 2008	$	3,788
Additions charged to expense		6,658
Accounts written off, less recoveries		(6,493	)
Balance, December 31, 2009		3,953
Additions charged to expense		2,646
Accounts written off, less recoveries		(3,405	)
Balance, December 31, 2010		3,194
Additions charged to expense		2,678
Accounts written off, less recoveries		(2,690	)
Balance, December 31, 2011	$	3,182

Southwest Gas Corporation 51

Note 4 - Regulatory Assets and Liabilities

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

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

December 31,	2011			2010
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	330,844		$	224,913
Unrealized loss on non-trading derivatives (Swaps) (2)		11,743			11,482
Deferred purchased gas costs (3)		2,323			356
Accrued purchased gas costs (4)		18,400			14,000
Unamortized premium on reacquired debt (5)		19,011			19,881
Other (6)		32,988			28,402
		415,309			299,034
Regulatory liabilities:
Deferred purchased gas costs (3)		(72,426	)		(123,344	)
Accumulated removal costs		(233,000	)		(211,000	)
Unrealized gain on non-trading derivatives (Swaps) (2)		—			(656	)
Deferred gain on southern Nevada division operations facility (7)		(806	)		(1,246	)
Rate refunds due customers (8)		—			(546	)
Unamortized gain on reacquired debt (9)		(12,470	)		(13,006	)
Other (10)		(14,501	)		(2,811	)
Net regulatory assets (liabilities)	$	82,106		$	(53,575	)

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

(2) The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the balance sheets (thousands of dollars). The actual amounts, when realized at settlement, become a component of purchased gas costs under the Company’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13).

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

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

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

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

Southwest Gas Corporation 52

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

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

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

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

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

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

The following represents a rollforward of AOCI, presented on the Company’s Consolidated Balance Sheets and its Consolidated Statements of Equity:

AOCI - Rollforward (Thousands of dollars)
	Defined Benefit Plans (Note 10)								FSIRS (Note 13)								AOCI
	Before- Tax			Tax (Expense) Benefit		After- Tax			Before- Tax			Tax (Expense) Benefit		After-Tax
Beginning Balance AOCI December 31, 2010	$	(31,304	)	$	11,896	$	(19,408	)	$	(18,349	)	$	6,973	$	(11,376	)	$	(30,784	)
Current period other comprehensive income (loss)		(13,125	)		4,987		(8,138	)		(16,789	)		6,380		(10,409	)		(18,547	)
Ending Balance AOCI December 31, 2011	$	(44,429	)	$	16,883	$	(27,546	)	$	(35,138	)	$	13,353	$	(21,785	)	$	(49,331	)

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

The information below provides insight into amounts impacting Other Comprehensive Income (Loss), before and after- tax impacts, within the Consolidated Statements of Comprehensive Income, which also impact Accumulated Other Comprehensive Income in the Company’s Consolidated Balance Sheets and Consolidated Statements of Equity.

Southwest Gas Corporation 53

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

	2011									2010									2009
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(135,492	)	$	51,487		$	(84,005	)	$	(9,058	)	$	3,442		$	(5,616	)	$	(26,448	)	$	10,050		$	(16,398	)
Amortization of prior service credit		—			—			—			—			—			—			(2	)		1			(1	)
Amortization of transition obligation		867			(330	)		537			867			(329	)		538			867			(329	)		538
Amortization of net loss		15,569			(5,916	)		9,653			12,122			(4,606	)		7,516			5,596			(2,126	)		3,470
Regulatory adjustment		105,931			(40,254	)		65,677			652			(248	)		404			15,431			(5,864	)		9,567
Pension plans other comprehensive income (loss)		(13,125	)		4,987			(8,138	)		4,583			(1,741	)		2,842			(4,556	)		1,732			(2,824	)
FSIRS (designated hedging activities):
Unrealized/realized loss		(17,958	)		6,824			(11,134	)		(18,446	)		7,010			(11,436	)		—			—			—
Amounts reclassified into net income		1,169			(444	)		725			97			(37	)		60			—			—			—
FSIRS other comprehensive income (loss)		(16,789	)		6,380			(10,409	)		(18,349	)		6,973			(11,376	)		—			—			—
Total other comprehensive income (loss)	$	(29,914	)	$	11,367		$	(18,547	)	$	(13,766	)	$	5,232		$	(8,534	)	$	(4,556	)	$	1,732		$	(2,824	)

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

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

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

See Note 10 – Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 13 – Derivatives and Fair Value Measurements for more information on the FSIRS.

Note 6 - Preferred Trust Securities and Subordinated Debentures

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

Southwest Gas Corporation 54

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

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

Note 7 – Long-Term Debt

December 31,	2011					2010
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011	$	—		$	—	$	200,000		$	201,560
Notes, 7.625%, due 2012		200,000			204,312		200,000			214,666
Notes, 4.45%, due 2020		125,000			128,673		125,000			125,325
Notes, 6.1%, due 2041		125,000			143,074		—			—
8% Series, due 2026		75,000			96,340		75,000			99,968
Medium-term notes, 7.59% series, due 2017		25,000			30,199		25,000			30,295
Medium-term notes, 7.78% series, due 2022		25,000			31,932		25,000			32,063
Medium-term notes, 7.92% series, due 2027		25,000			31,648		25,000			33,211
Medium-term notes, 6.76% series, due 2027		7,500			8,510		7,500			8,956
Unamortized discount		(2,087	)				(2,534	)
		605,413					679,966
Revolving credit facility and commercial paper, due 2012		109,000			109,000		—			—
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
6.10% 1999 Series A, due 2038		12,410			12,410		12,410			11,968
5.95% 1999 Series C, due 2038		14,320			14,449		14,320			13,594
5.55% 1999 Series D, due 2038		8,270			8,253		8,270			7,468
5.45% 2003 Series C, due 2038 (rate resets in 2013)		30,000			31,332		30,000			31,547
5.25% 2003 Series D, due 2038		20,000			19,583		20,000			17,474
5.80% 2003 Series E, due 2038 (rate resets in 2013)		15,000			15,634		15,000			15,436
5.25% 2004 Series A, due 2034		65,000			64,291		65,000			58,574
5.00% 2004 Series B, due 2033		31,200			30,283		31,200			27,295
4.85% 2005 Series A, due 2035		100,000			94,836		100,000			84,485
4.75% 2006 Series A, due 2036		24,855			23,179		24,855			20,518
Unamortized discount		(3,360	)				(3,502	)
		517,695					517,553
NPL debt obligations		21,368			21,380		2,242			2,473
		1,253,476					1,199,761
Less: current maturities		(322,618	)				(75,080	)
Long-term debt, less current maturities	$	930,858				$	1,124,681

Southwest Gas Corporation 55

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

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

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

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

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

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

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

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

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

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

Southwest Gas Corporation 56

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

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

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

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2011, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.6 billion in additional debt and meet the leverage ratio requirement. The Company has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Note 8 - Short-Term Debt

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

Note 9 - Commitments and Contingencies

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

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

Note 10 – Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is 3.5% of an employee’s annual compensation. NPL has a separate plan, the cost and liability of which are not significant. The cost of the Southwest plan is listed below (in thousands):

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

Southwest has a deferred compensation plan for all officers and a separate deferred compensation plan for members of the Board of Directors. The plans provide the opportunity to defer up to 100% of annual cash compensation. Southwest matches one-half of amounts deferred by officers, up to a maximum matching contribution of 3.5% of an officer’s annual

Southwest Gas Corporation 57

base salary. Upon retirement, payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150% of Moody’s Seasoned Corporate Bond Rate Index.

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

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

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

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

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

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

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

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

Southwest Gas Corporation 58

December 31 of each year and expected to be available during the period to maturity of the pension benefits. In determining the discount rate, the Company matches the plan’s projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are generally made in increments of 25 basis points.

Due to the continuing low interest rate environment for high-quality fixed income investments, the Company lowered the discount rate in 2011 from 2010. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also lowered (consistent with management’s expectations overall) in 2011 from 2010 and the asset return assumption was unchanged between periods. The rates are presented in the table below:

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

Low asset returns were experienced during 2011, relative to the assumed rate of return. This, combined with significant favorable returns in 2010 and 2009, partially offset substantial losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will increase the expense level for 2012. Pension expense for 2012 is estimated to increase by $7.5 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

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

	2011									2010
	Qualified Retirement Plan			SERP			PBOP			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Change in benefit obligations
Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO)	$	662,134		$	31,860		$	46,765		$	606,276		$	35,339		$	42,322
Service cost		17,725			217			858			16,932			372			856
Interest cost		37,276			1,766			2,631			35,614			2,045			2,491
Actuarial loss (gain)		89,922			2,427			2,835			27,680			(3,480	)		2,632
Benefits paid		(26,486	)		(2,443	)		(907	)		(24,368	)		(2,416	)		(1,536	)
Benefit obligation at end of year (PBO/PBO/APBO)		780,571			33,827			52,182			662,134			31,860			46,765
Change in plan assets
Market value of plan assets at beginning of year		475,931			-			29,640			392,975			-			25,511
Actual return on plan assets		2,384			-			(200	)		53,224			-			3,181
Employer contributions		70,000			2,443			904			54,100			2,416			1,348
Benefits paid		(26,486	)		(2,443	)		(400	)		(24,368	)		(2,416	)		(400	)
Market value of plan assets at end of year		521,829			-			29,944			475,931			-			29,640
Funded status at year end	$	(258,742	)	$	(33,827	)	$	(22,238	)	$	(186,203	)	$	(31,860	)	$	(17,125	)
Weighted-average assumptions (benefit obligation)
Discount rate		5.00%			5.00%			5.00%			5.75%			5.75%			5.75%
Weighted-average rate of compensation increase		3.00%			3.00%			3.00%			3.25%			3.25%			3.25%

Southwest Gas Corporation 59

Estimated funding for the plans above during calendar year 2012 is approximately $47 million of which $46 million pertains to the retirement plan. Management monitors plan assets and liabilities and could, at its discretion, increase plan funding levels above the minimum in order to achieve a desired funded status and avoid or minimize potential benefit restrictions.

The accumulated benefit obligation for the retirement plan and the SERP is presented below (in thousands):

	December 31, 2011		December 31, 2010
Retirement plan	$	699,269	$	590,811
SERP		32,695		30,725

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

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

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

For PBOP measurement purposes, the per capita cost of covered health care benefits medical rate trend assumption is 7.5% declining to 5%. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays all covered health care costs for employees who retired prior to 1989. The medical trend rate assumption noted above applies to the benefit obligations of pre-1989 retirees only.

Components of net periodic benefit cost

	Qualified Retirement Plan									SERP									PBOP
	2011			2010			2009			2011			2010			2009			2011			2010			2009
(Thousands of dollars)
Service cost	$	17,725		$	16,932		$	15,390		$	217		$	372		$	195		$	858		$	856		$	729
Interest cost		37,276			35,614			34,527			1,766			2,045			2,065			2,631			2,491			2,370
Expected return on plan assets		(40,114	)		(36,538	)		(35,221	)		—			—			—			(2,379	)		(2,093	)		(1,603	)
Amortization of prior service costs (credits)		—			—			(2	)		—			—			—			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			867			867
Amortization of net actuarial loss		14,348			10,478			4,253			631			1,155			909			590			489			434
Net periodic benefit cost	$	29,235		$	26,486		$	18,947		$	2,614		$	3,572		$	3,169		$	2,567		$	2,610		$	2,797
Weighted-average assumptions (net benefit cost)
Discount rate		5.75	%		6.00	%		6.75	%		5.75	%		6.00	%		6.75	%		5.75	%		6.00	%		6.75	%
Expected return on plan assets		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		3.25	%		3.75	%		3.25	%		3.25	%		3.75	%		3.25	%		3.25	%		3.75	%

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

	2011												2010												2009
	Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)	$	135,492		$	127,651		$	2,427		$	5,414		$	9,058		$	10,994		$	(3,480	)	$	1,544		$	26,448		$	21,054		$	3,785		$	1,609
Amortization of prior service credit (b)		—			—			—			—			—			—			—			—			2			2			—			—
Amortization of transition obligation (b)		(867	)		—			—			(867	)		(867	)		—			—			(867	)		(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(15,569	)		(14,348	)		(631	)		(590	)		(12,122	)		(10,478	)		(1,155	)		(489	)		(5,596	)		(4,253	)		(909	)		(434	)
Regulatory adjustment		(105,931	)		(101,974	)		—			(3,957	)		(652	)		(464	)		—			(188	)		(15,431	)		(15,123	)		—			(308	)
Recognized in other comprehensive (income) loss	$	13,125		$	11,329		$	1,796		$	—		$	(4,583	)	$	52		$	(4,635	)	$	—		$	4,556		$	1,680		$	2,876		$	—
Net period benefit costs recognized in net income		34,416			29,235			2,614			2,567			32,668			26,486			3,572			2,610			24,913			18,947			3,169			2,797
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	47,541		$	40,564		$	4,410		$	2,567		$	28,085		$	26,538		$	(1,063	)	$	2,610		$	29,469		$	20,627		$	6,045		$	2,797

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

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

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

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

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

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

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The following table sets forth, by level within the three-level fair value hierarchy, the fair values of the assets of the qualified pension plan and the PBOP as of December 31, 2011 and December 31, 2010. The SERP has no assets.

	December 31, 2011						December 31, 2010
	Qualified Retirement Plan		PBOP		Total		Qualified Retirement Plan			PBOP			Total
Assets at fair value (thousands of dollars):
Level 1 - Quoted prices in active markets for identical financial assets
Cash equivalents	$	20	$	1	$	21	$	48		$	2		$	50
Common stock
Capital equipment		4,332		133		4,465		11,083			362			11,445
Chemicals/materials		7,425		227		7,652		4,273			140			4,413
Consumer goods		40,806		1,249		42,055		35,491			1,158			36,649
Energy and mining		39,080		1,196		40,276		34,530			1,127			35,657
Finance/insurance		23,808		729		24,537		27,097			884			27,981
Healthcare		26,070		798		26,868		19,275			629			19,904
Information technology		29,052		889		29,941		33,445			1,091			34,536
Services		17,417		533		17,950		20,570			671			21,241
Telecommunications/utilities		16,257		498		16,755		12,172			397			12,569
Other		22,473		688		23,161		15,917			519			16,436
Real estate investment trusts		5,779		177		5,956		4,504			147			4,651
Mutual funds		57,512		14,154		71,666		49,994			14,234			64,228
Government fixed income		5,727		175		5,902		11,020			360			11,380
Futures contracts		4		—		4		(51	)		(2	)		(53	)
Total Level 1 Assets (1)	$	295,762	$	21,447	$	317,209	$	279,368		$	21,719		$	301,087
Level 2 - Significant other observable inputs
Government fixed income and mortgage backed	$	42,361	$	1,297	$	43,658	$	39,201		$	1,279		$	40,480
Corporate fixed income
Asset-backed and mortgage-backed		16,969		519		17,488		14,014			457			14,471
Banking		16,192		496		16,688		17,178			561			17,739
Utilities		5,064		155		5,219		2,430			79			2,509
Other		25,769		789		26,558		20,575			671			21,246
Pooled funds and mutual funds		17,447		2,244		19,691		8,230			1,974			10,204
State and local obligations		936		29		965		626			20			646
Total Level 2 assets (2)	$	124,738	$	5,529	$	130,267	$	102,254		$	5,041		$	107,295
Level 3 - Significant unobservable inputs
Commingled equity funds	$	97,295	$	2,978	$	100,273	$	94,389		$	3,080		$	97,469
Total Level 3 assets (3)	$	97,295	$	2,978	$	100,273	$	94,389		$	3,080		$	97,469
Total Plan assets at fair value	$	517,795	$	29,954	$	547,749	$	476,011		$	29,840		$	505,851
Guaranteed investment contracts/guaranteed annuity contracts (4)		4,952		—		4,952		5,342			—			5,342
Total Plan assets (5)	$	522,747	$	29,954	$	552,701	$	481,353		$	29,840		$	511,193

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

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

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

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

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

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

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

• Diversification by country, limiting exposure in any one country

• Emerging markets

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

(5) The assets in the above table exceed the market value of plan assets shown in the funded status table by $928,000 (qualified retirement plan - $918,000, PBOP - $10,000) and $5.6 million (qualified retirement plan - $5.4 million, PBOP - $200,000) for 2011 and 2010, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

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Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2009	$	77,879
Actual return on plan assets:
Relating to assets still held at the reporting date		13,090
Relating to assets sold during the period		—
Purchases		6,500
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2010	$	97,469
Actual return on plan assets:
Relating to assets still held at the reporting date		(8,442	)
Relating to assets sold during the period		246
Purchases		12,000
Sales		(1,000	)
Settlements		—
Transfers in and/or out of Level 3		—
Balance, December 31, 2011	$	100,273

Note 11 – Stock-Based Compensation

At December 31, 2011, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income is shown in the table below (in thousands):

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

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

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

	2011					2010					2009
	Number of options			Weighted- average exercise price		Number of options			Weighted- average exercise price		Number of options			Weighted- average exercise price
Outstanding at the beginning of the year		369		$	28.04		651		$	27.49		731		$	27.12
Exercised during the year		(192	)		28.75		(273	)		26.67		(66	)		23.18
Forfeited or expired during the year		—			—		(9	)		29.51		(14	)		28.88
Outstanding and exercisable at year end		177		$	27.28		369		$	28.04		651		$	27.49

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The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding and exercisable options and options that were exercised are presented in the table below (in thousands):

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

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

The weighted-average remaining contractual life for outstanding options was 3.4 years for 2011. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2011 (thousands of options):

	Options Outstanding and Exercisable
Range of     Exercise Price	Number outstanding	Weighted- average remaining contractual life	Weighted- average exercise price
$20.49 to $23.40	52	2.1 Years	$22.45
$24.50 to $26.10	58	3.3 Years	$25.81
$29.08 to $33.07	67	4.5 Years	$32.29

The total grant date fair value of options vested was $405,000 during 2009. The Company received $5.4 million in cash from the exercise of options during 2011 and a corresponding tax benefit of $702,000 which was recorded in additional paid-in capital.

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

The Company awards restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/units vest 40% at the end of year one and 30% at the end of years two and three and are then issued as common stock. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants to directors followed the vesting schedule for employees; however, beginning with grants in 2012, the directors’ restricted stock/units will vest immediately upon grant. The issuance of common stock for directors occurs when their service on the Board ends.

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The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2011 (thousands of shares):

	Performance Shares			Weighted- average grant date fair value		Restricted Stock/Units			Weighted- average grant date fair value
Nonvested/unissued at beginning of year		366		$	27.54		170		$	27.42
Granted		125			37.87		92			37.87
Dividends		11					5
Forfeited or expired		(4	)		30.11		(2	)		30.50
Vested and issued*		(137	)		29.52		(89	)		28.45
Nonvested/unissued at December 31, 2011		361		$	30.66		176		$	32.65

*Includes shares converted for taxes and retiree payouts.

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

Note 12 - Income Taxes

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is subject to examinations by the Internal Revenue Service for years after 2007, and is subject to examination by the various state taxing authorities for years after 2006.

The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):

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

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

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

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

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

	2011			2010
Unrecognized tax benefits at beginning of year	$	1,445		$	1,445
Gross increases – tax positions in prior period		—			—
Gross decreases – tax positions in prior period		—			—
Gross increases – current period tax positions		—			—
Gross decreases – current period tax positions		—			—
Settlements		—			—
Lapse of statute of limitations		(1,445	)		—
Unrecognized tax benefits at end of year	$	—		$	1,445

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

Year Ended December 31,	2011			2010		2009
Current:
Federal	$	(265	)	$	4,204	$	(1,020	)
State		2,122			4,442		3,101
		1,857			8,646		2,081
Deferred:
Federal		58,584			44,778		41,410
State		2,862			1,501		1,426
		61,446			46,279		42,836
Total income tax expense	$	63,303		$	54,925	$	44,917

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

Year Ended December 31,	2011			2010			2009
Deferred federal and state:
Property-related items	$	51,710		$	43,420		$	46,201
Purchased gas cost adjustments		(92	)		(315	)		(4,167	)
Employee benefits		11,766			8,753			(452	)
All other deferred		(1,070	)		(4,711	)		2,122
Total deferred federal and state		62,314			47,147			43,704
Deferred ITC, net		(868	)		(868	)		(868	)
Total deferred income tax expense	$	61,446		$	46,279		$	42,836

Southwest Gas Corporation 67

The consolidated effective income tax rate for the period ended December 31, 2011 and the two prior periods differ from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:

Year Ended December 31,	2011			2010			2009
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.7			2.8			2.5
Property-related items		0.2			0.2			0.2
Effect of income tax settlements		(0.9	)		(0.3	)		(0.2	)
Tax credits		(0.6	)		(0.5	)		(0.7	)
Company owned life insurance		(0.1	)		(2.3	)		(2.5	)
All other differences		(0.1	)		(0.2	)		(0.3	)
Consolidated effective income tax rate		36.2	%		34.7	%		34.0	%

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

December 31,	2011			2010
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	3,743		$	4,280
Employee benefits		24,605			31,384
Alternative minimum tax credit		17,411			15,495
Net operating losses and credits		59,096			—
Interest rate swap		13,352			6,973
Other		15,099			8,026
Valuation allowance		(142	)		—
		133,164			66,158
Deferred tax liabilities:
Property-related items, including accelerated depreciation		611,022			500,216
Regulatory balancing accounts		743			836
Property-related items previously flowed through		2,797			3,910
Unamortized ITC		5,992			6,860
Debt-related costs		4,379			4,824
Other		11,914			8,094
		636,847			524,740
Net deferred tax liabilities	$	503,683		$	458,582
Current	$	(53,435	)	$	(8,046	)
Noncurrent		557,118			466,628
Net deferred tax liabilities	$	503,683		$	458,582

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

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Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2012 through March 2014. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):

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

Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2011, 2010, and 2009 and their location in the income statements (thousands of dollars):

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

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

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

In January 2010, Southwest entered into two FSIRS to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt that matured in February 2011 and $200 million maturing in May 2012. The counterparties to each agreement are four major banking institutions. The first FSIRS was a designated cash flow hedge and terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. The terms of the remaining FSIRS are as follows:

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

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

Southwest Gas Corporation 69

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

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

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

	Year Ended December 31, 2011			Year Ended December 31, 2010
Amount of loss on unrealized FSIRS recognized in other comprehensive income on derivative (effective portion)	$	(17,958	)	$	(6,755	)
Amount of loss on realized FSIRS recognized in other comprehensive income on derivative		—			(11,691	)
Total	$	(17,958	)	$	(18,446	)

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

Fair values of derivatives not designated as hedging instruments:

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(11,122	)	$	(11,122	)
Swaps	Other deferred credits		—		(621	)		(621	)
Total		$	—	$	(11,743	)	$	(11,743	)
December 31, 2010 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	656	$	—		$	656
Swaps	Other current liabilities		65		(11,547	)		(11,482	)
Total		$	721	$	(11,547	)	$	(10,826	)

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Fair values of derivatives designated as hedging instruments:

December 31, 2011 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other current liabilities	$	—	$	(24,713	)	$	(24,713	)
December 31, 2010 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
FSIRS	Other deferred credits	$	—	$	(6,755	)	$	(6,755	)

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

Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. Neither changes in fair value, nor settled amounts, of Swaps have a direct effect on earnings or other comprehensive income. The following table shows the amounts Southwest paid to and received from counterparties for settlements of matured Swaps.

	Year ended December 31, 2011		Year ended December 31, 2010		Year ended December 31, 2009
(Thousands of dollars)
Paid to counterparties	$	17,283	$	16,574	$	19,661
Received from counterparties	$	—	$	831	$	—

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

December 31, 2011
Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	11,122
Swaps	Deferred charges and other assets		621
December 31, 2010
Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(656	)
Swaps	Prepaids and other current assets		11,482

Fair Value Measurements.    The estimated fair values of Southwest’s Swaps were determined at December 31, 2011 and 2010 using New York Mercantile Exchange (“NYMEX”) futures settlement prices for delivery of natural gas at Henry Hub, adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

Southwest Gas Corporation 71

The estimated fair value of Southwest’s FSIRS was determined using a discounted cash flow model that utilizes forward interest rate curves. The inputs to the model are the terms of the FSIRS. These Level 2 inputs are observable in the marketplace throughout the full term of the FSIRS, but have been credit-risk adjusted with no significant impact to the overall fair value measure. See Note 5 – Other Comprehensive Income and Accumulated Other Comprehensive Income for more information on the FSIRS.

See Note 10 – Pension and Other Postretirement Benefits for definitions of the levels of the fair value hierarchy. The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value:

Level 2 - Significant other observable inputs

	December 31, 2011			December 31, 2010
(Thousands of dollars)
Assets at fair value:
Deferred charges and other assets - swaps	$	—		$	656
Liabilities at fair value:
Other current liabilities - swaps		(11,122	)		(11,482	)
Other deferred credits - swaps		(621	)		—
Other current liabilities - FSIRS		(24,713	)		—
Other deferred credits - FSIRS		—			(6,755	)
Net Assets (Liabilities)	$	(36,456	)	$	(17,581	)

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

Note 14 - Segment Information

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

The accounting policies of the reported segments are the same as those described within Note 1 - Summary of Significant Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices. Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).

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

Southwest Gas Corporation 72

The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2011 is as follows (thousands of dollars):

2011	Gas Operations		Construction Services		Adjustments	Total
Revenues from unaffiliated customers	$	1,403,366	$	391,701		$	1,795,067
Intersegment sales		—		92,121			92,121
Total	$	1,403,366	$	483,822		$	1,887,188
Interest revenue	$	465	$	20		$	485
Interest expense	$	68,777	$	825		$	69,602
Depreciation and amortization	$	175,253	$	25,216		$	200,469
Income tax expense	$	49,576	$	13,727		$	63,303
Segment net income	$	91,420	$	20,867		$	112,287
Segment assets	$	4,048,613	$	227,394		$	4,276,007
Capital expenditures	$	305,542	$	75,449		$	380,991
2010	Gas Operations		Construction Services		Adjustments	Total
Revenues from unaffiliated customers	$	1,511,907	$	257,213		$	1,769,120
Intersegment sales		—		61,251			61,251
Total	$	1,511,907	$	318,464		$	1,830,371
Interest revenue	$	158	$	36		$	194
Interest expense	$	77,025	$	564		$	77,589
Depreciation and amortization	$	170,456	$	20,007		$	190,463
Income tax expense	$	47,073	$	7,852		$	54,925
Segment net income	$	91,382	$	12,495		$	103,877
Segment assets	$	3,845,111	$	139,082		$	3,984,193
Capital expenditures	$	188,379	$	27,060		$	215,439

Southwest Gas Corporation 73

2009	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,614,843	$	226,407				$	1,841,250
Intersegment sales		—		52,574					52,574
Total	$	1,614,843	$	278,981				$	1,893,824
Interest revenue	$	189	$	82				$	271
Interest expense	$	81,822	$	1,179				$	83,001
Depreciation and amortization	$	166,850	$	23,232				$	190,082
Income tax expense	$	40,451	$	4,466				$	44,917
Segment net income	$	79,420	$	8,062				$	87,482
Segment assets	$	3,782,913	$	124,755	$	(1,376	)	$	3,906,292
Capital expenditures	$	212,919	$	4,066				$	216,985

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

Southwest Gas Corporation 74

Note 15 - Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2011
Operating revenues	$	628,440	$	388,505		$	352,592		$	517,651
Operating income		126,335		20,568			1,253			101,924
Net income (loss)		68,549		4,055			(15,641	)		55,324
Basic earnings (loss) per common share*		1.50		0.09			(0.34	)		1.20
Diluted earnings (loss) per common share*		1.48		0.09			(0.34	)		1.19
2010
Operating revenues	$	668,751	$	385,825		$	307,683		$	468,112
Operating income		121,732		24,031			184			86,170
Net income (loss)		64,648		(933	)		(4,823	)		44,985
Basic earnings (loss) per common share*		1.43		(0.02	)		(0.11	)		0.99
Diluted earnings (loss) per common share*		1.42		(0.02	)		(0.11	)		0.98
2009
Operating revenues	$	689,862	$	387,648		$	317,509		$	498,805
Operating income		102,729		14,685			522			90,455
Net income (loss)		49,981		(594	)		(8,297	)		46,392
Basic earnings (loss) per common share*		1.13		(0.01	)		(0.18	)		1.03
Diluted earnings (loss) per common share*		1.12		(0.01	)		(0.18	)		1.02

* The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted-average number of common shares outstanding.

The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for the interim periods do not reliably reflect overall trends and changes in the operations of the Company. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.

Southwest Gas Corporation 75

Management’s Report on Internal Control Over Financial Reporting

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2011. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 28, 2012

Southwest Gas Corporation 76

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of cash flows and of equity present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

Las Vegas, Nevada

February 28, 2012