Exhibit 13.01

SOUTHWEST GAS CORPORATION 2009

 

CONSOLIDATED SELECTED FINANCIAL STATISTICS

 

 

Year Ended December 31,		2009				2008				2007				2006				2005
(Thousands of dollars, except per share amounts)
Operating revenues		$	1,893,824			$	2,144,743			$	2,152,088			$	2,024,758			$	1,714,283
Operating expenses			1,685,433				1,936,881				1,929,788				1,811,608				1,563,635
Operating income		$	208,391			$	207,862			$	222,300			$	213,150			$	150,648
Net income		$	87,482			$	60,973			$	83,246			$	83,860			$	43,823
Total assets at year end		$	3,906,292			$	3,820,384			$	3,670,188			$	3,484,965			$	3,228,426
Capitalization at year end
Common equity		$	1,102,086			$	1,037,841			$	983,673			$	901,425			$	751,135
Subordinated debentures			100,000				100,000				100,000				100,000				100,000
Long-term debt			1,169,357				1,185,474				1,266,067				1,286,354				1,224,898
		$	2,371,443			$	2,323,315			$	2,349,740			$	2,287,779			$	2,076,033
Common stock data
Common equity percentage of capitalization			46.5	%			44.7	%			41.9	%			39.4	%			36.2	%
Return on average common equity			8.1	%			6.0	%			8.8	%			10.3	%			5.9	%
Basic earnings per share		$	1.95			$	1.40			$	1.97			$	2.07			$	1.15
Diluted earnings per share		$	1.94			$	1.39			$	1.95			$	2.05			$	1.14
Dividends declared per share		$	0.95			$	0.90			$	0.86			$	0.82			$	0.82
Payout ratio			49	%			64	%			44	%			40	%			71	%
Book value per share at year end		$	24.44			$	23.48			$	22.98			$	21.58			$	19.10
Market value per share at year end		$	28.53			$	25.22			$	29.77			$	38.37			$	26.40
Market value per share to book value per share			117	%			107	%			130	%			178	%			138	%
Common shares outstanding at year end (000)			45,092				44,192				42,806				41,770				39,328
Number of common shareholders at year end			20,489				22,244				22,664				23,610				23,571
Ratio of earnings to fixed charges			2.46				2.01				2.25				2.25				1.70

 

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NATURAL GAS OPERATIONS

 

 

Year Ended December 31,		2009				2008				2007				2006				2005
(Thousands of dollars)
Sales		$	1,547,081			$	1,728,924			$	1,754,913			$	1,671,093			$	1,401,329
Transportation			67,762				62,471				59,853				56,301				53,928
Operating revenue			1,614,843				1,791,395				1,814,766				1,727,394				1,455,257
Net cost of gas sold			866,630				1,055,977				1,086,194				1,033,988				828,131
Operating margin			748,213				735,418				728,572				693,406				627,126
Expenses
Operations and maintenance			348,942				338,660				331,208				320,803				314,437
Depreciation and amortization			166,850				166,337				157,090				146,654				137,981
Taxes other than income taxes			37,318				36,780				37,553				34,994				39,040
Operating income		$	195,103			$	193,641			$	202,721			$	190,955			$	135,668
Contribution to consolidated net income		$	79,420			$	53,747			$	72,494			$	71,473			$	33,670
Total assets at year end		$	3,782,913			$	3,680,327			$	3,518,304			$	3,352,074			$	3,103,804
Net gas plant at year end		$	3,034,503			$	2,983,307			$	2,845,300			$	2,668,104			$	2,489,147
Construction expenditures and property additions		$	212,919			$	279,254			$	312,412			$	305,914			$	258,547
Cash flow, net
From operating activities		$	371,416			$	261,322			$	320,594			$	253,245			$	214,036
From (used in) investing activities			(265,850	)			(237,093	)			(306,396	)			(277,980	)			(254,120	)
From (used in) financing activities			(81,744	)			(34,704	)			(5,347	)			15,989				57,763
Net change in cash		$	23,822				$(10,475	)		$	8,851			$	(8,746	)		$	17,679
Total throughput (thousands of therms)
Residential			669,736				704,986				698,063				677,605				650,465
Small commercial			294,225				314,555				310,666				309,856				300,072
Large commercial			117,241				125,121				127,561				128,255				111,839
Industrial/Other			72,623				97,702				103,525				149,243				156,542
Transportation			1,043,894				1,164,190				1,128,422				1,175,238				1,273,964
Total throughput			2,197,719				2,406,554				2,368,237				2,440,197				2,492,882
Weighted average cost of gas purchased ($/therm)		$	0.71			$	0.84			$	0.81			$	0.79			$	0.71
Customers at year end			1,824,000				1,819,000				1,813,000				1,784,000				1,713,000
Employees at year end			2,423				2,447				2,538				2,525				2,590
Customer to employee ratio			753				743				714				706				661
Degree days—actual			1,824				1,902				1,850				1,826				1,735
Degree days—ten-year average			1,882				1,893				1,936				1,961				1,956

 

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SOUTHWEST GAS CORPORATION 2009

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

About Southwest Gas Corporation

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

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

As of December 31, 2009, Southwest had 1,824,000 residential, commercial, industrial, and other natural gas customers, of which 986,000 customers were located in Arizona, 657,000 in Nevada, and 181,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2009, 55 percent of operating margin was earned in Arizona, 34 percent in Nevada, and 11 percent in California. During this same period, Southwest earned 86 percent of operating margin from residential and small commercial customers, 4 percent from other sales customers, and 10 percent from transportation customers. These general patterns are expected to continue.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting operating margin are general rate relief, weather, conservation and efficiencies, and customer growth. Of these, weather is the primary reason for volatility in margin. Variances in temperatures from normal levels, especially in Arizona where rates remain leveraged, have a significant impact on the margin and associated net income of the Company. A decoupled rate structure adopted as part of the recently approved Nevada general rate case (see Rates and Regulatory Proceedings), however, is expected to prospectively mitigate the impact that weather variability will have on margin in Nevada service territories. Weather impacts are substantially offset by the margin tracking mechanism in Southwest’s California service territories.

NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in 17 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including the housing market, interest rates, employment levels, job growth, the equipment resale market, and local and federal tax rates.

Executive Summary

The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and are covered in greater detail in later sections of management’s discussion and analysis. The natural gas operations segment accounted for an average of 89 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

 

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Summary Operating Results

 

Year ended December 31,		2009			2008			2007
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations		$	79,420		$	53,747		$	72,494
Construction services			8,062			7,226			10,752
Consolidated		$	87,482		$	60,973		$	83,246
Average number of common shares outstanding			44,752			43,476			42,336
Basic earnings per share
Consolidated		$	1.95		$	1.40		$	1.97
Natural Gas Operations
Operating margin		$	748,213		$	735,418		$	728,572

2009 Overview

Consolidated results for 2009 increased compared to 2008 due to improvements in both the natural gas and construction services segments. Basic earnings per share were $1.95 in 2009 compared to basic earnings per share of $1.40 in 2008.

Natural gas operations highlights include the following:

 

•

Rate relief, weather, and challenging economic conditions all significantly impacted operating margin during 2009

 

•

Operating margin increased approximately $13 million, or two percent, compared to the prior year

 

•

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

 

•

Other income includes year-over-year COLI improvement of $21 million

 

•

Net financing costs decreased $9 million between 2009 and 2008

 

•

Nevada general rate increase and decoupling mechanism approved effective November 2009

 

•

Southwest’s liquidity position remains strong

Construction services highlights include the following:

 

•

Revenues in 2009 decreased $74 million compared to 2008, but contribution to net income increased $836,000

Rate Relief. During 2009, Southwest received the benefits of rate relief in all of its regulatory jurisdictions which accounted for $30 million of incremental operating margin. Additionally, the Public Utilities Commission of Nevada (“PUCN”) authorized a decoupled rate structure that will help stabilize annual operating margin in Nevada effective November 2009. See Rates and Regulatory Proceedings for additional details of the various rate decisions.

Customers. During 2009, Southwest completed 18,000 first-time meter sets. These meter sets led to 5,000 net additional active customers between 2008 and 2009. The difference between first-time meter sets and incremental active meters indicates a continuing build-up of unoccupied homes, a trend first experienced during 2007. Although the difference between first-time meter sets and additional active meters is narrowing in comparison to the two previous years, Southwest is projecting net growth will remain sluggish (1% or less)

 

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for 2010 as high foreclosure rates and recessionary conditions persist throughout its service territories. Once housing supply and demand come back into balance, Southwest expects to experience a correction in which customer additions exceed first-time meter sets. Although management cannot predict the timing of a turnaround, it is not likely to occur in the near term.

Weather. 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. During 2009, the estimated weather impact on operating margin was a reduction of $18 million, including $13 million from the first quarter when Arizona experienced one of its warmest winters in 100 years. By comparison, during 2008, weather resulted in an estimated negative operating margin impact of $11 million.

In Southwest’s California service territories, weather impacts were offset by the margin tracking mechanism allowing margin to grow as authorized in its most recent general rate case. In Nevada, the negative impacts were mitigated by a declining block rate structure which was in place until November when a decoupled rate structure became effective. Most of the reduction occurred in Arizona, where rates are highly leveraged and a single block rate structure is in effect. In addition, the heating season is fairly condensed in Arizona; therefore variations from “normal” temperatures can cause significant volatility in operating margin as over 50 percent of Southwest’s annual operating margin is normally earned in Arizona.

Conservation, Energy Efficiencies, and Economic Impacts on Consumption. A significant portion of Southwest’s operating margin (primarily in Arizona and partially in Nevada) has been recognized based on the volumetric usage of its customers. Historically the impacts of this rate design methodology have been most pronounced when temperatures varied from normal levels. Over the longer-term, average usage has also declined due to new home construction practices and energy efficient appliances. Recently, the continued downturn in the economy and associated pro-active conservation efforts have resulted in a more pronounced drop in average per-customer usage. For the year ended December 31, 2009, the estimated impact of these non-weather-related volumetric declines was a reduction to operating margin of $11 million. The decoupling methodology authorized in the recent Nevada rate case, effective November 2009, should mitigate this impact in Nevada going forward. Management continues to work with regulators in Arizona to establish a decoupling methodology that would allow the Company to support and encourage conservation efforts without jeopardizing the recognition of authorized operating margin.

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 $136 million at December 31, 2009. 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 $58 million at December 31, 2009 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. During 2009, Southwest recognized in Other income (deductions) a net increase in the cash surrender values of its COLI policies of $8.5 million (compared to a net decline of $12 million in 2008). Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the changes in the cash surrender value components of COLI policies as they progress towards the ultimate death benefits are also recorded without tax consequences. Currently, the Company intends to hold the COLI policies for their duration and purchase additional policies as necessary.

Liquidity. Although the credit crisis eased somewhat during 2009, significant attention is still being paid to companies’ liquidity and credit risks. Focus on these risks will likely continue given the current national economic environment. The Company has experienced no significant impacts to its liquidity position from

 

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the credit crisis. Southwest believes its liquidity position remains strong. Southwest has a $300 million credit facility maturing in May 2012, $150 million of which is designated for working capital needs. The facility is provided through a consortium of eight major banking institutions. Usage of the facility in 2009 was minimal even during the winter heating season when gas purchases normally require temporary financing. This was primarily due to natural gas prices that were relatively stable and gas-cost related rate mechanisms that favorably impacted operating cash flows. The slowdown in housing construction has also allowed Southwest to fund construction expenditures primarily with internally generated cash.

Results of Natural Gas Operations

 

Year Ended December 31,		2009			2008				2007
(Thousands of dollars)
Gas operating revenues		$	1,614,843		$	1,791,395			$	1,814,766
Net cost of gas sold			866,630			1,055,977				1,086,194
Operating margin			748,213			735,418				728,572
Operations and maintenance expense			348,942			338,660				331,208
Depreciation and amortization			166,850			166,337				157,090
Taxes other than income taxes			37,318			36,780				37,553
Operating income			195,103			193,641				202,721
Other income (deductions)			6,590			(13,469	)			4,850
Net interest deductions			74,091			83,096				86,436
Net interest deductions on subordinated debentures			7,731			7,729				7,727
Income before income taxes			119,871			89,347				113,408
Income tax expense			40,451			35,600				40,914
Contribution to consolidated net income		$	79,420		$	53,747			$	72,494

2009 vs. 2008

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

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

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

Depreciation expense increased $513,000, or less than one percent, as a result of additional plant in service, substantially offset by lower depreciation rates in the California ($3 million annualized reduction) and Nevada ($2.3 million annualized reduction) rate jurisdictions effective in January and June 2009, respectively. Average gas plant in service for 2009 increased $193 million, or five percent, as compared to 2008. This was

 

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attributable to new business, reinforcement work, franchise requirements, routine pipe replacement activities, and the addition of two new operations centers in southern Nevada.

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

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

2008 vs. 2007

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

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

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

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

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

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

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

 

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(rate design) can significantly impact the operating margin actually realized by Southwest. Management has worked with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such a rate structure is in place in California and was recently approved in Nevada. See Nevada General Rate Case for additional details. Southwest continues to pursue rate design changes in Arizona. See Arizona Energy Efficiency and Decoupling Proceeding for more information.

Nevada General Rate Case. Southwest filed a general rate application with the PUCN in April 2009 requesting an increase in authorized annual operating revenues of $28.8 million, or 5.9 percent in the Company’s southern Nevada rate jurisdiction and $1.7 million, or 1.4 percent in the northern Nevada rate jurisdiction. At the rebuttal stage in the case, Southwest had reduced its combined southern and northern Nevada requested revenue increase to $27.8 million. The PUCN issued its Order in this proceeding in October with rates effective November 2009. The Order provided for a revenue increase of $17.6 million in southern Nevada based on an overall rate of return of 7.40% and a 10.15% return on equity. Northern Nevada experienced a revenue decrease of $0.5 million with an overall rate of return of 8.29% and a 10.15% return on equity. On a combined basis, the rate case decision is designed to increase operating income by $19.1 million. The Company was also authorized to implement a decoupled rate structure based on PUCN regulations that will help stabilize operating margin by insulating the Company from the effects of lower usage (including volumes associated with unusual weather). It will also allow the Company to more aggressively pursue customer conservation opportunities through implementation of substantive conservation and energy efficiency programs. For 2009, the Order resulted in an operating margin increase of $2 million.

The PUCN Order also included the following:

 

•

Authorized capital structure utilizing 47 percent common equity,

 

•

10.15% return on equity (consisting of 10.40% overall equity return, reduced by 25 basis points for the expected reduction in risk associated with implementation of the decoupling mechanism),

 

•

Authorized rate base of $820 million in southern Nevada and $117 million in northern Nevada,

 

•

Adoption of the Company’s recommendation to offset a $20.5 million deferred gain on the sale of the former southern Nevada operations facility against the cost of the land purchased for new facilities by $12.8 million and eliminating approximately $5.9 million of deferred costs associated with a government-mandated pipe inspection program (the remaining $1.8 million will be accreted to income over 4 years),

 

•

Approval of a tracking mechanism for gas cost-related uncollectible expense, and

 

•

Inclusion for ratemaking purposes of several post test period adjustments (including the new southern Nevada operations facilities), thus mitigating regulatory lag associated with these recently completed construction projects.

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 $100,000 per year for the South Lake Tahoe rate jurisdiction. In October 2009, Southwest filed for attrition which was approved effective January 2010 in the amount of $1.7 million in southern California, $417,000 in northern California, and $559,000 for South Lake Tahoe (including the $400,000 previously deferred). In the general rate case, the CPUC also authorized a return to a seasonal margin methodology (which resulted in significant quarterly swings in reported operating margin for 2009 versus 2008) in addition to lower depreciation rates which reduced annualized depreciation expense by $3 million.

FERC General Rate Case. Paiute Pipeline Company, a subsidiary of the Company, filed a general rate case with the Federal Energy Regulatory Commission (“FERC”) in February 2009. The filing fulfilled an obligation from

 

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the settlement agreement reached in the 2005 Paiute general rate case. The application requested an increase in operating revenues of approximately $3.9 million. A final decision has not been rendered and the parties to the case are in settlement discussions; however, in accordance with FERC requirements, new rates went into effect in September 2009, subject to refund.

Arizona Energy Efficiency and Decoupling Proceeding. The Arizona Corporation Commission (“ACC”) convened a series of workshops earlier in 2009 to evaluate “rate and regulatory incentives” and establish standards to promote energy efficiency and conservation for utility customers. In conjunction with these workshops, Southwest and other interested parties submitted proposed regulations to the ACC in June 2009. Rate designs which would decouple revenues from customer usage were the topic of much discussion in the proceeding, and were incorporated in several of the parties’ draft regulations. The ACC Staff is reviewing the proposals and will develop a draft regulation for consideration by the ACC. The Company anticipates a final decision in this matter later this year.

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, 2009, over-collections in Arizona and southern Nevada resulted in a liability of $93.2 million and under-collections in California and northern Nevada resulted in an asset of $3.2 million on the Company’s balance sheets. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions). In addition, since Southwest is permitted to accrue interest on PGA balances, the cost of incremental PGA-related short-term borrowings will be largely offset and there should be no material negative impact to earnings.

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

 

		2009				2008
Arizona		$	(33.2	)		$	(9.6	)
Northern Nevada			1.2				(1.5	)
Southern Nevada			(60.0	)			(19.9	)
California			2.0				(2.1	)
		$	(90.0	)		$	(33.1	)

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

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

 

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

Gas Price Volatility Mitigation

Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and fixed-for-floating swap contracts (“Swaps”) for about half of its annual normal weather supply needs under its volatility mitigation programs. For the 2009/2010 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $10 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.

Capital Resources and Liquidity

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

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

Cash Flows

Operating Cash Flows. Cash flows provided by consolidated operating activities increased $106 million in 2009 as compared to 2008. The primary driver of the change was temporary fluctuations in working capital components. Operating cash flows were also benefited by an increase in net income between the periods.

In February 2009, the American Recovery and Reinvestment Act of 2009 (“Act”) was signed into law. This Act provides a 50 percent bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2009. Southwest estimates that the bonus depreciation deduction deferred the payment of approximately $19 million of federal income taxes during 2009 to future periods.

Investing Cash Flows. Cash used in consolidated investing activities increased $11.7 million in 2009 as compared to 2008. The 2009 activity includes restricted funds associated with the issuance of the $50 million variable-rate 2009 Series A Industrial Development Revenue Bonds (“IDRBs”) in December 2009 partially offset by reductions in construction expenditures and equipment purchases. The 2008 activity included receipt of an exchange fund deposit.

Financing Cash Flows. Cash used in consolidated financing activities increased $49.8 million during 2009 as compared to 2008 primarily due to a reduction in borrowings under Southwest’s commercial credit facility, partially offset by a net issuance of long-term debt. Beginning in the second quarter of 2009, the Company ceased issuing new Common Stock associated with the Employee Investment Plan. (The Plan will purchase shares on the open market as needed). Dividends paid increased in 2009 as compared to 2008 as a result of a quarterly dividend increase and an increase in the number of shares outstanding.

 

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

2009 Construction Expenditures

During the three-year period ended December 31, 2009, total gas plant increased from $3.8 billion to $4.4 billion, or at an annual rate of five percent. Customer growth was a substantial portion of the plant increase as the Company set 110,000 meters resulting in 40,000 net new customers during the three-year period.

During 2009, construction expenditures for the natural gas operations segment were $213 million. Approximately 55 percent of these expenditures represented new construction and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant. Cash flows from operating activities of Southwest were $371 million which provided sufficient funding for construction expenditures and dividend requirements of the natural gas operations segment.

2009 Financing Activity

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. The Series 2009A IDRBs were issued at par and are due December 1, 2039. At December 31, 2009, $49.8 million in proceeds from the issuance of the IDRBs remained in trust and are reflected as restricted cash on the balance sheet. The IDRBs were issued to finance all or a portion of the cost of the acquisition, construction, and installation of projects consisting of the upgrade, improvement, addition, and replacement of facilities for local furnishing of natural gas in Clark County, Nevada.

During 2009, the Company issued shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), Employee Investment Plan, and Stock Incentive Plan, raising approximately $18 million. The remaining capacity under the Equity Shelf Program of $16.7 million expired unused in March 2009. The DRSPP and Employee Investment Plan are expected to be a source of capital in the future, albeit at lower levels.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2012 will be approximately $570 million. Of this amount, approximately $200 million are expected to be incurred in 2010. During the three-year period, cash flows from operating activities of Southwest are expected to provide sufficient funding for the gas operations total construction expenditures and dividend requirements. During the three-year period, the Company expects to raise $8 million to $10 million from its various common stock programs. Any cash requirements not met by operating activities are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

In February 2010, the Company notified holders of the $100 million, 7.70% subordinated debentures (Preferred Securities) that these securities will be redeemed by the Company in March 2010. The Company will facilitate the redemption using existing cash and borrowings under the $300 million credit facility.

 

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Southwest has $200 million of long-term debt maturing in February 2011 and $200 million maturing in May 2012. The Company currently intends to issue $250 million of new debentures in December 2010 and $200 million of debentures in March 2012 to provide funding for the maturing obligations (and a portion of the redeemed subordinated debentures). In connection with these planned debt issuances, the Company, in January 2010, entered into two forward-starting interest rate swap (“FSIRS”) agreements to hedge the risk of interest rate variability during the period leading up to the planned issuances. The counterparties to both agreements comprise four major banking institutions. The first FSIRS has a notional amount of $125 million (with Southwest as the fixed-rate payer at a rate of 4.26%) and has a mandatory termination date on or before December 7, 2010. The second FSIRS has a notional amount of $100 million (with Southwest as the fixed-rate payer at a rate of 4.78%) and has a mandatory termination date on or before March 20, 2012. Southwest has designated the FSIRS agreements as cash flow hedges of forecasted future interest payments.

Liquidity

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

On an interim basis, Southwest generally defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2009, the combined balance in the PGA accounts totaled an over-collection of $90 million. See PGA Filings for more information on recent regulatory filings.

The Company has a $300 million credit facility that expires in May 2012. Southwest has designated $150 million of the $300 million facility as long-term debt and the remaining $150 million for working capital purposes. At December 31, 2009, $92.4 million was outstanding on the long-term portion and no borrowings were outstanding on the short-term portion of the credit facility. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any. This credit facility has been, and is expected to continue to be, adequate for Southwest’s working capital needs outside of funds raised through operations and other types of external financing. Management believes the Company currently has a solid liquidity position.

Credit Ratings

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

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

 

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

In April 2009, 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 stronger financial performance due to reduced debt leverage and the recent general rate increase in the Company’s Arizona service territory as reasons for the upgrade. 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.

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, 2009, 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 and has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Inflation

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

Off-Balance Sheet Arrangements

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

 

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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, 2009 (millions of dollars):

 

		Payments due by period
Contractual Obligations		Total			2010			2011-2012			2013-2014			Thereafter
Operating activities:
Operating leases (Note 2)		$	26		$	5		$	8		$	7		$	6
Gas purchase obligations			441			332			109			—			—
Pipeline capacity			924			126			182			139			477
Other commitments			27			17			8			1			1
Financing activities:
Subordinated debentures to Southwest Gas Capital II (Note 5)			103			—			—			—			103
Interest on subordinated debentures to Southwest Gas Capital II (Note 5)			260			8			15			15			222
Long-term debt (Note 6)			1,171			1			495			—			675
Interest on long-term debt			798			66			84			67			581
Other			15			—			—			—			15
Total		$	3,765		$	555		$	901		$	229		$	2,080

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 103 million dekatherms. Fixed-price contracts range in price from approximately $4 to $10 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 2010 is $25 million. The Company has an insignificant amount of liabilities in connection with uncertainty surrounding income tax positions taken or expected to be taken.

 

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Results of Construction Services

 

Year Ended December 31,		2009				2008			2007
(Thousands of dollars)
Construction revenues		$	278,981			$	353,348		$	337,322
Operating expenses:
Construction expenses			242,461				311,745			292,319
Depreciation and amortization			23,232				27,382			25,424
Operating income			13,288				14,221			19,579
Other income (deductions)			55				63			73
Net interest deductions			1,179				1,823			2,036
Income before income taxes			12,164				12,461			17,616
Income tax expense			4,466				5,235			6,864
Net income			7,698				7,226			10,752
Net income (loss) attributable to noncontrolling interest			(364	)			—			—
Contribution to consolidated net income attributable to NPL		$	8,062			$	7,226		$	10,752

2009 vs. 2008

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

The general slowdown in the new housing market and associated construction activities that started in 2007, continued throughout 2008 and 2009. The adverse economic conditions experienced in 2009 negatively impacted the amount of work under existing blanket contracts, and reduced the amount of profitable bid work. It is anticipated that the current economic environment will continue to impact construction services results in 2010.

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

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

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

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

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

 

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2008 vs. 2007

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

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

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

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates dealing with the transfer of financial assets, the accounting treatment of Variable Interest Entities, and disclosures about fair value measurements. 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 critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1—Summary of Significant Accounting Policies.

Regulatory Accounting

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

 

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Accrued Utility Revenues

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

Accounting for Income Taxes

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

Accounting for Pensions and Other Postretirement Benefits

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

At December 31, 2009, the Company lowered the discount rate to 6.00% from 6.75% at December 31, 2008. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was lowered to 3.25% from 3.75%. The asset return assumption remains at 8.00%. Favorable asset returns were experienced during 2009 relative to the assumed rate of return. This partially offset the significant losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will significantly increase the expense level for 2010. Pension expense for 2010 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.

 

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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, 2009 were included as exhibits to the 2009 Annual Report on Form 10-K which was filed with the SEC.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin earned, customer growth, the composition of our customer base, average per-customer usage, price volatility, risks and costs associated with having non-performing assets associated with new homes, timing of improvements in the housing market, amount and timing for completion of estimated future construction expenditures, forecasted operating cash flows and results of operations, 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, the amount and form of any such financing, the effectiveness of forward-starting interest rate swap agreements in hedging against changing interest rates, liquidity, the impact of the application of certain accounting standards, certain tax benefits from the American Recovery and Reinvestment Act of 2009, statements regarding future gas prices, gas purchase contracts and derivative financial interests, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.

A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, conditions in the housing market, our ability to recover costs through our PGA mechanisms, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, renewal of franchises, easements and rights-of-way, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

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).

 

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Common Stock Price and Dividend Information

 

		2009				2008				Dividends Declared
		High		Low		High		Low		2009		2008
First quarter		$26.38		$17.08		$30.48		$25.14		$0.2375		$0.225
Second quarter		22.32		18.96		31.74		27.90		0.2375		0.225
Third quarter		26.64		21.58		33.29		27.56		0.2375		0.225
Fourth quarter		29.48		24.81		30.78		21.11		0.2375		0.225
										$0.9500		$0.900

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 17, 2010, there were 20,163 holders of record of common stock, and the market price of the common stock was $27.55.

The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend declared was 21.5 cents per share throughout 2007, 22.5 cents per share throughout 2008, and 23.75 cents per share throughout 2009. In February 2010, the Board of Directors increased the quarterly dividend from 23.75 cents to 25 cents per share, effective with the June 2010 payment.

 

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SOUTHWEST GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

		December 31,
		2009				2008
(Thousands of dollars, except par value)
ASSETS
Utility plant:
Gas plant		$	4,418,286			$	4,258,727
Less: accumulated depreciation			(1,431,106	)			(1,347,093	)
Acquisition adjustments, net			1,451				1,632
Construction work in progress			45,872				70,041
Net utility plant (Note 2)			3,034,503				2,983,307
Other property and investments			115,860				124,781
Restricted cash (Note 6)			49,769				—
Current assets:
Cash and cash equivalents			65,315				26,399
Accounts receivable, net of allowances (Note 3)			157,722				168,829
Accrued utility revenue			71,700				72,600
Income taxes receivable, net			8,549				32,069
Deferred income taxes (Note 11)			22,410				14,902
Deferred purchased gas costs (Note 4)			3,251				—
Prepaids and other current assets (Notes 2 and 4)			88,685				123,277
Total current assets			417,632				438,076
Deferred charges and other assets (Notes 4 and 12)			288,528				274,220
Total assets		$	3,906,292			$	3,820,384
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—45,091,734 and 44,191,535 shares) (Note 10)		$	46,722			$	45,822
Additional paid-in capital			792,339				770,463
Accumulated other comprehensive income (loss), net (Note 9)			(22,250	)			(19,426	)
Retained earnings			285,316				240,982
Total Southwest Gas Corporation equity			1,102,127				1,037,841
Noncontrolling interest			(41	)			—
Total equity			1,102,086				1,037,841
Subordinated debentures due to Southwest Gas Capital II (Note 5)			100,000				100,000
Long-term debt, less current maturities (Note 6)			1,169,357				1,185,474
Total capitalization			2,371,443				2,323,315
Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)			1,327				7,833
Short-term debt (Note 7)			—				55,000
Accounts payable			158,856				191,434
Customer deposits			91,668				83,468
Accrued general taxes			40,868				41,490
Accrued interest			19,644				19,699
Deferred purchased gas costs (Note 4)			93,226				33,073
Other current liabilities (Notes 4 and 12)			68,641				77,898
Total current liabilities			474,230				509,895
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note 11)			436,113				387,539
Taxes payable			3,079				3,480
Accumulated removal costs (Note 4)			189,000				169,000
Other deferred credits (Notes 4 and 9)			432,427				427,155
Total deferred income taxes and other credits			1,060,619				987,174
Total capitalization and liabilities		$	3,906,292			$	3,820,384

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

 

 

		Year Ended December 31,
		2009				2008				2007
(In thousands, except per share amounts)
Operating revenues:
Gas operating revenues		$	1,614,843			$	1,791,395			$	1,814,766
Construction revenues			278,981				353,348				337,322
Total operating revenues			1,893,824				2,144,743				2,152,088
Operating expenses:
Net cost of gas sold			866,630				1,055,977				1,086,194
Operations and maintenance			348,942				338,660				331,208
Depreciation and amortization			190,082				193,719				182,514
Taxes other than income taxes			37,318				36,780				37,553
Construction expenses			242,461				311,745				292,319
Total operating expenses			1,685,433				1,936,881				1,929,788
Operating income			208,391				207,862				222,300
Other income and (expenses):
Net interest deductions (Notes 6 and 7)			(75,270	)			(84,919	)			(88,472	)
Net interest deductions on subordinated debentures (Note 5)			(7,731	)			(7,729	)			(7,727	)
Other income (deductions)			6,645				(13,406	)			4,923
Total other income and (expenses)			(76,356	)			(106,054	)			(91,276	)
Income before income taxes			132,035				101,808				131,024
Income tax expense (Note 11)			44,917				40,835				47,778
Net income			87,118				60,973				83,246
Net income (loss) attributable to noncontrolling interest			(364	)			—				—
Net income attributable to Southwest Gas Corporation		$	87,482			$	60,973			$	83,246
Basic earnings per share (Note 14)		$	1.95			$	1.40			$	1.97
Diluted earnings per share (Note 14)		$	1.94			$	1.39			$	1.95
Average number of common shares outstanding			44,752				43,476				42,336
Average shares outstanding (assuming dilution)			45,062				43,775				42,714

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Year Ended December 31,
		2009				2008				2007
(Thousands of dollars)
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income		$	87,118			$	60,973			$	83,246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			190,082				193,719				182,514
Deferred income taxes			42,798				36,135				16,068
Changes in current assets and liabilities:
Accounts receivable, net of allowances			11,107				34,831				22,268
Accrued utility revenue			900				2,300				(1,600	)
Deferred purchased gas costs			56,902				20,931				89,149
Accounts payable			(32,578	)			(29,297	)			(45,008	)
Accrued taxes			22,497				(21,837	)			(16,537	)
Other current assets and liabilities			32,733				(3,636	)			24,972
Gains on sale			(3,291	)			(2,068	)			(2,530	)
Changes in undistributed stock compensation			3,942				3,825				3,324
AFUDC and property-related changes			(1,221	)			(561	)			(871	)
Changes in other assets and deferred charges			(15,553	)			(5	)			(4,971	)
Changes in other liabilities and deferred credits			10,366				4,438				1,111
Net cash provided by operating activities			405,802				299,748				351,135
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions			(216,985	)			(300,217	)			(340,875	)
Restricted cash			(49,769	)			—				—
Changes in customer advances			(2,476	)			4,044				24,407
Receipt of exchange fund deposit			—				28,000				—
Miscellaneous inflows			7,933				17,656				5,257
Miscellaneous outflows			(3,620	)			(2,693	)			(20,724	)
Net cash used in investing activities			(264,917	)			(253,210	)			(331,935	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net			18,401				35,391				31,495
Dividends paid			(41,950	)			(38,705	)			(35,993	)
Issuance of long-term debt, net			49,834				103,875				128,594
Retirement of long-term debt			(15,654	)			(198,691	)			(142,091	)
Change in long-term portion of credit facility			(57,600	)			—				3,000
Change in short-term debt			(55,000	)			46,000				9,000
Net cash used in financing activities			(101,969	)			(52,130	)			(5,995	)
Change in cash and cash equivalents			38,916				(5,592	)			13,205
Cash at beginning of period			26,399				31,991				18,786
Cash at end of period		$	65,315			$	26,399			$	31,991
Supplemental information:
Interest paid, net of amounts capitalized		$	80,771			$	91,211			$	93,335
Income taxes paid (received)		$	(21,616	)		$	22,472			$	45,025

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME

 

		Southwest Gas Corporation Equity
		Common Stock						Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)				Retained Earnings				Non- controlling Interest				Total				Comprehensive Income (Loss)
		Shares			Amount
(In thousands, except per share amounts)
DECEMBER 31, 2006		41,770			$	43,400		$	698,258		$	(13,666	)		$	173,433			$	—			$	901,425
Common stock issuances		1,036				1,036			34,061															35,097
Net income																83,246								83,246			$	83,246
Net actuarial gain arising during the period, less amortization of unamortized benefit plan cost, net of $500,000 of tax (Note 9)												816												816				816
Dividends declared Common: $0.86 per share																(36,911	)							(36,911	)
2007 Comprehensive Income																											$	84,062
DECEMBER 31, 2007		42,806				44,436			732,319			(12,850	)			219,768				—				983,673
Common stock issuances		1,386				1,386			38,144															39,530
Net income																60,973								60,973			$	60,973
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of $4 million of tax (Note 9)												(6,576	)											(6,576	)			(6,576	)
Dividends declared Common: $0.90 per share																(39,759	)							(39,759	)
2008 Comprehensive Income																											$	54,397
DECEMBER 31, 2008		44,192				45,822			770,463			(19,426	)			240,982				—				1,037,841
Common stock issuances		900				900			21,876															22,776
Net income (loss)																87,482				(364	)			87,118			$	87,118
Noncontrolling interest capital investment																				323				323
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of $1.7 million of tax (Note 9)												(2,824	)											(2,824	)			(2,824	)
Dividends declared Common: $0.95 per share																(43,148	)							(43,148	)
2009 Comprehensive Income																											$	84,294
Comprehensive income (loss) attributable to noncontrolling interest																												(364	)
Comprehensive income attributable to Southwest Gas Corporation																											$	84,658
DECEMBER 31, 2009		45,092	*		$	46,722		$	792,339		$	(22,250	)		$	285,316			$	(41	)		$	1,102,086

 

*

At December 31, 2009, 2 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 651,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10).

The accompanying notes are an integral part of these statements.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1—Summary of Significant Accounting Policies

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

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

Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries, except for Southwest Gas Capital II (see Note 5). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with 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.

 

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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 $189 million and $169 million, as of December 31, 2009 and 2008, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets.

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

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

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

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

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

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

Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for salvage value, removal costs, and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense.

 

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Allowance for Funds Used During Construction (“AFUDC”). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The Company capitalized $2.2 million in 2009, $1.2 million in 2008, and $1.3 million in 2007 of AFUDC related to natural gas utility operations. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. The debt portion of AFUDC was $957,000, $635,000, and $619,000 for 2009, 2008, and 2007, respectively. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.

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

 

		2009				2008				2007
Change in COLI policies		$	8,546			$	(12,041	)		$	1,165
Interest income			271				2,212				4,448
Miscellaneous income and (expense)			(2,172	)			(3,577	)			(690	)
Total other income (deductions)		$	6,645			$	(13,406	)		$	4,923

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

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.

 

		2009		2008		2007
(In thousands)
Average basic shares		44,752		43,476		42,336
Effect of dilutive securities:
Stock options		14		60		147
Performance shares		216		193		210
Restricted stock units		80		46		21
Average diluted shares		45,062		43,775		42,714

Reclassifications. Certain reclassifications have been made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation. None of the reclassifications affected previously reported net income.

Accounting Standards Codification. In 2009, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—A Replacement of FASB Statement No. 162”, (the “Codification”) (previously Statement of Financial Accounting Standards (“SFAS”) No. 168) became effective. Accordingly, the Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification became the source of authoritative accounting principles recognized by the FASB to be applied by non -

 

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governmental entities in the preparation of financial statements in conformity with U.S. GAAP. The implementation of the Codification did not have an impact on the Company’s consolidated financial statements, as it became the single source of authoritative accounting principles and guidance, but did not modify any existing authoritative U.S. GAAP.

Recently Issued Accounting Standards Updates. In January 2010, the FASB issued “Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements” which requires new disclosures about transfers in and out of Levels 1 and 2 of the fair value hierarchy and more detailed information about the activity in Level 3 fair value measurements. To improve the degree of disaggregation in disclosures of the fair values of assets, the update changes the previous terminology from major categories of assets to classes of assets. Disclosure of the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements are now required for fair value measurements that fall in either Level 2 or Level 3. For the Company, the update will be effective prospectively beginning January 2010, except that the new Level 3 activity disclosures will be effective prospectively beginning January 2011. The adoption of the update is not expected to have a material impact on the disclosures of the Company.

In December 2009, the FASB issued “Transfers and Servicing (Topic 860)—Accounting for Transfers of Financial Assets” (previously issued in June 2009 as SFAS No. 166) which eliminates the qualifying special purpose entity concept and the related exception from consolidation, limits derecognition of financial assets when control still exists, and requires enhanced disclosures. For the Company, the update will be effective prospectively for new transfers of financial assets beginning January 2010. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.

In December 2009, the FASB issued “Consolidations (Topic 810)—Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (previously issued in June 2009 as SFAS No. 167) which changes the methodology for determining the primary beneficiary of a variable interest entity. This methodology change could cause an entity to consolidate a previously unconsolidated variable interest entity or deconsolidate a previously consolidated variable interest entity if the primary beneficiary has changed under the new guidance. Entities will have the option to adopt retrospectively or through cumulative effect. Enhanced disclosures are also required. This Accounting Standard Update will be effective for the Company in January 2010. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.

Subsequent Events. Management of the Company monitors significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which management is aware were evaluated through February 26, 2010, the date these financial statements were issued.

 

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Note 2—Utility Plant

Net utility plant as of December 31, 2009 and 2008 was as follows (thousands of dollars):

 

December 31,		2009				2008
Gas plant:
Storage		$	20,326			$	19,094
Transmission			271,467				262,271
Distribution			3,716,881				3,615,253
General			270,825				228,282
Other			138,787				133,827
			4,418,286				4,258,727
Less: accumulated depreciation			(1,431,106	)			(1,347,093	)
Acquisition adjustments, net			1,451				1,632
Construction work in progress			45,872				70,041
Net utility plant		$	3,034,503			$	2,983,307

Depreciation and amortization expense on gas plant was $162 million in both 2009 and 2008 and $155 million in 2007. Despite the increase in gross gas plant, depreciation expense was flat between 2009 and 2008 due to lower depreciation rates in Nevada and California rate jurisdictions.

In October 2007, the Company sold its Southern Nevada Division operations facility for $35 million. Of the proceeds, $28 million was held by JP Morgan Property Exchange, Inc. at December 31, 2007 to facilitate like-kind exchange tax treatment for the new land and facilities to be developed. The funds were returned to Southwest in April 2008. The gain on the sale (approximately $20.5 million) was deferred and recorded as a regulatory liability. In mid 2009, the Company finished building two separate facilities in southern Nevada to better serve the customer base in Las Vegas. In the 2009 Nevada general rate case, the Company received approval to offset $12.8 million of the deferred gain against the cost of the land purchased for new facilities and eliminate approximately $5.9 million of deferred costs associated with a government-mandated pipe inspection program. The remaining $1.8 million will be accreted to income over four years.

Operating Leases and Rentals. Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The leases provide for current terms which expire in 2017 and 2014, respectively, with optional renewal terms available at the expiration dates. The rental payments for the corporate headquarters office complex are $2 million in each of the years 2010 through 2014 and $6 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.3 million in 2010, $1.4 million in each of the years 2011 through 2013, and $243,000 in 2014 when the lease expires. In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. Rentals included in operating expenses for all operating leases were $19.9 million in 2009, $23.4 million in 2008, and $23.9 million in 2007. These amounts include NPL lease expenses of approximately $11.3 million in 2009, $13.9 million in 2008, and $15.9 million in 2007, for various short-term operating leases of equipment and temporary office sites.

 

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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, 2009 (thousands of dollars):

 

Year Ending December 31,
2010		$	5,050
2011			4,490
2012			4,020
2013			3,977
2014			2,605
Thereafter			6,046
Total minimum lease payments		$	26,188

Note 3—Receivables and Related Allowances

Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. At December 31, 2009, the gas utility customer accounts receivable balance was $130 million. Approximately 54 percent of the gas utility customers were in Arizona, 36 percent in Nevada, and 10 percent in California. Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Provisions for uncollectible accounts are recorded monthly, as needed, and are included in the ratemaking process as a cost of service. Activity in the allowance for uncollectibles is summarized as follows (thousands of dollars):

 

		Allowance for Uncollectibles
Balance, December 31, 2006		$	3,021
Additions charged to expense			7,178
Accounts written off, less recoveries			(7,252	)
Balance, December 31, 2007			2,947
Additions charged to expense			7,047
Accounts written off, less recoveries			(6,206	)
Balance, December 31, 2008			3,788
Additions charged to expense			6,658
Accounts written off, less recoveries			(6,493	)
Balance, December 31, 2009		$	3,953

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.

 

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

 

December 31,		2009				2008
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)		$	224,261			$	208,830
Unrealized loss on non-trading derivatives (Swaps) (2)			1,496				14,440
Deferred purchased gas costs (3)			3,251				—
Accrued purchased gas costs (4)			12,500				37,400
Unamortized premium on reacquired debt (5)			17,095				17,772
Other (7)			28,055				29,223
			286,658				307,665
Regulatory liabilities:
Deferred purchased gas costs (3)			(93,226	)			(33,073	)
Accumulated removal costs			(189,000	)			(169,000	)
Unrealized gain on non-trading derivatives (Swaps) (2)			(2,618	)			(292	)
Deferred gain on southern Nevada division operations facility (6)			(1,686	)			(20,522	)
Unamortized gain on reacquired debt (6)			(13,543	)			(14,099	)
Other (6)			(2,486	)			(1,668	)
Net regulatory assets (liabilities)		$	(15,901	)		$	69,011

 

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

(2)

Regulatory asset included in Prepaids and other current assets ($1.4 million and $14.4 million) in 2009 and 2008, respectively. Regulatory asset included in Deferred charges and other assets ($75,000) in 2009. Regulatory liability included in Other deferred credits ($58,000 and $292,000) in 2009 and 2008, respectively. Regulatory liability included in Other current liabilities ($2.6 million) in 2009. The actual amounts, when realized at settlement, become a component of gas costs. (See Note 12)

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

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

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

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

(7)

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

Note 5—Preferred Trust Securities and Subordinated Debentures

In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the dis -

 

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tribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures became redeemable at the option of the Company in August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest. In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Trust Securities. As of December 31, 2009, 4.1 million Preferred Trust Securities were outstanding.

The Company has the right to defer payments of interest on the Subordinated Debentures by extending the interest payment period at any time for up to 20 consecutive quarters (each, an “Extension Period”). If interest payments are so deferred, distributions to Preferred Trust Securities holders will also be deferred. During such Extension Period, distributions will continue to accrue with interest thereon (to the extent permitted by applicable law) at an annual rate of 7.70% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Debentures. If the Company exercises the right to extend an interest payment period, the Company shall not during such Extension Period (i) declare or pay dividends on, or make a distribution with respect to, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, or (ii) make any payment of interest, principal, or premium, if any, on or repay, repurchase, or redeem any debt securities issued by the Company that rank equal with or junior to the Subordinated Debentures; provided, however, that restriction (i) above does not apply to any stock dividends paid by the Company where the dividend stock is the same as that on which the dividend is being paid. The Company has no present intention of exercising its right to extend the interest payment period on the Subordinated Debentures.

Although the Company owns 100 percent of the common voting securities of Trust II, under U.S. GAAP, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. As a result, the $103.1 million Subordinated Debentures are shown on the balance sheet of the Company, net of the $3.1 million Common Securities, as Subordinated debentures due to Southwest Gas Capital II. Payments and amortizations associated with the Subordinated Debentures are classified on the consolidated statements of income as Net interest deductions on subordinated debentures. The estimated market values of the subordinated debentures at December 31, 2009 and 2008 were $102 million and $85 million, respectively.

 

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

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.

 

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Note 6—Long-Term Debt

 

December 31,		2009							2008
		Carrying Amount				Market Value			Carrying Amount				Market Value
(Thousands of dollars)
Debentures:
Notes, 8.375%, due 2011		$	200,000			$	213,012		$	200,000			$	206,200
Notes, 7.625%, due 2012			200,000				219,240			200,000				203,880
8% Series, due 2026			75,000				87,005			75,000				79,163
Medium-term notes, 7.59% series, due 2017			25,000				27,858			25,000				25,560
Medium-term notes, 7.78% series, due 2022			25,000				28,275			25,000				25,793
Medium-term notes, 7.92% series, due 2027			25,000				28,848			25,000				26,245
Medium-term notes, 6.76% series, due 2027			7,500				7,723			7,500				7,004
Unamortized discount			(2,196	)						(2,837	)
			555,304							554,663
Revolving credit facility and commercial paper, due 2012			92,400				92,400			150,000				150,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028			50,000				50,000			50,000				50,000
2003 Series A, due 2038			50,000				50,000			50,000				50,000
2008 Series A, due 2038			50,000				50,000			50,000				50,000
2009 Series A, due 2039			50,000				50,000			—				—
Fixed-rate bonds:
6.10% 1999 Series A, due 2038			12,410				11,443			12,410				9,375
5.95% 1999 Series C, due 2038			14,320				12,922			14,320				10,585
5.55% 1999 Series D, due 2038			8,270				7,038			8,270				5,752
5.45% 2003 Series C, due 2038 (rate resets in 2013)			30,000				31,422			30,000				32,966
5.25% 2003 Series D, due 2038			20,000				16,701			20,000				15,859
5.80% 2003 Series E, due 2038 (rate resets in 2013)			15,000				15,683			15,000				15,006
5.25% 2004 Series A, due 2034			65,000				55,979			65,000				43,929
5.00% 2004 Series B, due 2033			31,200				26,096			31,200				24,278
4.85% 2005 Series A, due 2035			100,000				79,469			100,000				62,862
4.75% 2006 Series A, due 2036			24,855				19,139			24,855				18,316
Unamortized discount			(3,644	)						(3,605	)
			517,411							467,450
Other			5,569				5,712			21,194				20,993
			1,170,684							1,193,307
Less: current maturities			(1,327	)						(7,833	)
Long-term debt, less current maturities		$	1,169,357						$	1,185,474

The Company has a $300 million credit facility scheduled to expire in May 2012. The Company uses $150 million of the $300 million as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the facility are calculated at either the London Interbank Offering Rate plus an appli -

 

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cable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. At December 31, 2009, no borrowings were outstanding on the short-term portion of the credit facility (see Note 7—Short-Term Debt) and $92.4 million was outstanding on the long-term portion. The effective interest rates on the borrowings on the long-term portion of the credit facility were 0.87% and 1.45% at December 31, 2009 and 2008, respectively.

In December 2009, the Company issued $50 million in Clark County, Nevada variable-rate 2009 Series A Industrial Development Revenue Bonds (“IDRBs”), supported by a letter of credit with JPMorgan Chase Bank. The Series 2009A IDRBs were issued at par and are due December 1, 2039. At December 31, 2009, $49.8 million in proceeds from the issuance of the IDRBs remained in trust and are shown as restricted cash on the consolidated balance sheet. The IDRBs were issued to finance all or a portion of the cost of the acquisition, construction, and installation of projects consisting of the upgrade, improvement, addition, and replacement of facilities for local furnishing of natural gas in Clark County, Nevada.

The effective interest rates on the 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs were 1.14%, 3.76%, and 3.68%, respectively, at December 31, 2009. The effective interest rate on the 2003 Series A and 2008 Series A variable-rate IDRBs was 1.85% and 2.29%, respectively, at December 31, 2008. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 1.12% and 1.74% at December 31, 2009 and 2008, respectively. In Nevada, interest fluctuations due to changing interest rates on the 2003 Series A and 2008 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.

The fair value of the revolving credit facility and the variable-rate IDRBs approximates carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for December 31, 2009 and 2008, as applicable, and other secondary sources which are customarily consulted for data of this kind. Management believes the fair values for certain securities disclosed for 2009 and 2008 reflect the impacts of a constrained securities market and may differ significantly from those determined in a normal functioning credit market.

Estimated maturities of long-term debt for the next five years are $1.3 million, $201.4 million, $293.2 million, $91,000, and $97,000, respectively.

No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2009, 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 and has at least $600 million of cushion in equity relating to the minimum net worth requirement.

Note 7—Short-Term Debt

As discussed in Note 6, Southwest has a $300 million credit facility that expires in May 2012, of which $150 million has been designated by management for working capital purposes (and related outstanding amounts, if any, are shown as short-term debt). Southwest had no short-term borrowings outstanding on the credit facility at December 31, 2009 and $55 million at December 31, 2008. The weighted-average interest rate on the borrowings at December 31, 2008 was 1.04%.

 

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Note 8—Commitments and Contingencies

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

Note 9—Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is three and one-half percent of an employee’s annual compensation. The cost of the plan was $4.5 million in 2009, $4.4 million in 2008, and $3.8 million in 2007. NPL has a separate plan, the cost and liability of which are not significant.

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

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.

 

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

 

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

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

U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on December 31 of each year and expected to be available during the period to maturity of the 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 a significant decline in market interest rates for high-quality fixed income investments, the Company lowered the discount rate from 6.75% at December 31, 2008 to 6.00% at December 31, 2009. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was lowered to 3.25% from 3.75%. The asset return assumption remains at 8.00%. Favorable asset returns were experienced during 2009 relative to the assumed rate of return. This partially offset the significant losses experienced in 2008. The combined asset return experience, however, coupled with the reduction in the discount rate will significantly increase the expense level for 2010. Pension expense for 2010 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.

 

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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.

 

		2009												2008
		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)		$	523,011			$	31,786			$	35,915			$	509,862			$	32,605			$	36,504
Service cost			15,390				195				729				16,108				97				730
Interest cost			34,527				2,065				2,370				32,491				2,041				2,324
Actuarial loss (gain)			55,356				3,785				4,546				(15,199	)			(594	)			(2,529	)
Benefits paid			(22,008	)			(2,492	)			(1,238	)			(20,251	)			(2,363	)			(1,114	)
Benefit obligation at end of year (PBO/PBO/APBO)			606,276				35,339				42,322				523,011				31,786				35,915
Change in plan assets
Market value of plan assets at beginning of year			323,460				—				19,436				415,263				—				26,473
Actual return on plan assets			69,523				—				4,540				(105,552	)			—				(7,657	)
Employer contributions			22,000				2,492				1,535				34,000				2,363				620
Benefits paid			(22,008	)			(2,492	)			—				(20,251	)			(2,363	)			—
Market value of plan assets at end of year			392,975				—				25,511				323,460				—				19,436
Funded status at year end		$	(213,301	)		$	(35,339	)		$	(16,811	)		$	(199,551	)		$	(31,786	)		$	(16,479	)
Weighted-average assumptions (benefit obligation)
Discount rate			6.00	%			6.00	%			6.00	%			6.75	%			6.75	%			6.75	%
Weighted-average rate of compensation increase			3.25	%			3.25	%			3.25	%			3.75	%			3.75	%			3.75	%

The accumulated benefit obligation for the retirement plan was $530 million and $457 million, and for the SERP was $31.5 million and $28.4 million at December 31, 2009 and 2008, respectively.

Estimated funding for the plans above during calendar year 2010 is approximately $25 million of which $24 million pertains to the retirement plan. The Pension Protection Act of 2006 provides for benefit restrictions to future retirees if the funded status of the retirement plan, determined in accordance with IRS rules, falls below certain thresholds (80%—modest restrictions, 60%—severe restrictions). The funded status is determined on the date of the plan year-end (July 31 for the Company). Management monitors the funded status of the plan and could, at its discretion, increase plan funding levels above the minimum in order to avoid or minimize benefit restrictions. The funded status under IRS rules was above 80% at the end of the most recent plan year, July 31, 2009.

Pension benefits expected to be paid for each of the next five years beginning with 2010 are the following: $25 million, $27 million, $28 million, $30 million, and $32 million. Pension benefits expected to be paid during 2015 to 2019 total $191 million. Retiree welfare benefits expected to be paid for each of the next five years

 

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beginning with 2010 are the following: $1.6 million, $1.8 million, $2 million, $2.2 million, and $2.3 million. Retiree welfare benefits expected to be paid during 2015 to 2019 total $14 million. SERP benefits expected to be paid for each of the next five years beginning with 2010 are approximately $2.5 million. SERP benefits expected to be paid during 2015 to 2019 total $12 million. No assurance can be made that actual funding and benefits paid will match these estimates.

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

Components of net periodic benefit cost

 

		Qualified Retirement Plan												SERP												PBOP
		2009				2008				2007				2009				2008				2007				2009				2008				2007
(Thousands of dollars)
Service cost		$	15,390			$	16,108			$	16,491			$	195			$	97			$	153			$	729			$	730			$	811
Interest cost			34,527				32,491				29,244				2,065				2,041				1,948				2,370				2,324				2,304
Expected return on plan assets			(35,221	)			(34,714	)			(33,030	)			—				—				—				(1,603	)			(2,138	)			(2,144	)
Amortization of prior service costs (credits)			(2	)			(11	)			(11	)			—				—				—				—				—				—
Amortization of transition obligation			—				—				—				—				—				—				867				867				867
Amortization of net actuarial loss			4,253				3,104				5,007				909				997				1,131				434				—				57
Net periodic benefit cost		$	18,947			$	16,978			$	17,701			$	3,169			$	3,135			$	3,232			$	2,797			$	1,783			$	1,895
Weighted-average assumptions (net benefit cost)
Discount rate			6.75	%			6.50	%			6.00	%			6.75	%			6.50	%			6.00	%			6.75	%			6.50	%			6.00	%
Expected return on plan assets			8.00	%			8.00	%			8.50	%			8.00	%			8.00	%			8.50	%			8.00	%			8.00	%			8.50	%
Weighted-average rate of compensation increase			3.75	%			4.00	%			3.75	%			3.75	%			4.00	%			3.75	%			3.75	%			4.00	%			3.75	%

 

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

 

		2009																2008
		Total				Qualified Retirement Plan				SERP				PBOP				Total				Qualified Retirement Plan				SERP				PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)		$	26,448			$	21,054			$	3,785			$	1,609			$	131,738			$	125,067			$	(595	)		$	7,266
Amortization of prior service credit (b)			2				2				—				—				11				11				—				—
Amortization of transition obligation (b)			(867	)			—				—				(867	)			(867	)			—				—				(867	)
Amortization of net actuarial loss (b)			(5,596	)			(4,253	)			(909	)			(434	)			(4,101	)			(3,104	)			(997	)			—
Regulatory adjustment			(15,431	)			(15,123	)			—				(308	)			(116,175	)			(109,776	)			—				(6,399	)
Recognized in other comprehensive (income) loss		$	4,556			$	1,680			$	2,876			$	—			$	10,606			$	12,198			$	(1,592	)		$	—
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss		$	29,469			$	20,627			$	6,045			$	2,797			$	32,502			$	29,176			$	1,543			$	1,783

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

 

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Related Tax Effects Allocated to Each Component of Other Comprehensive Income

 

		2009												2008
		Before-Tax Amount				Tax (Expense) or Benefit (1)				Net-of-Tax Amount				Before-Tax Amount				Tax (Expense) or Benefit (1)				Net-of-Tax Amount
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial loss (gain)		$	26,448			$	(10,050	)		$	16,398			$	131,738			$	(50,060	)		$	81,678
Amortization of prior service credit			2				(1	)			1				11				(4	)			7
Amortization of transition obligation			(867	)			329				(538	)			(867	)			329				(538	)
Amortization of net loss			(5,596	)			2,126				(3,470	)			(4,101	)			1,558				(2,543	)
Regulatory adjustment			(15,431	)			5,864				(9,567	)			(116,175	)			44,147				(72,028	)
Other comprehensive (income) loss		$	4,556			$	(1,732	)		$	2,824			$	10,606			$	(4,030	)		$	6,576

 

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

The estimated net loss that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year is $10.5 million for the qualified retirement plan and $1.1 million for the SERP. The estimated amounts for the PBOP that will be amortized from regulatory assets into net periodic benefit cost over the next year are $700,000 related to net loss and $870,000 for the transition obligation.

 

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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 fair values of the assets of the qualified pension plan and the PBOP as of December 31, 2009. The SERP has no assets.

 

		December 31, 2009
		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		$	39			$	1			$	40
Common stock			175,247				5,719				180,966
Real estate investment trusts			2,731				89				2,820
Mutual funds			42,070				12,604				54,674
Government fixed income			6,580				215				6,795
Preferred securities			169				5				174
Futures contracts			(51	)			(2	)			(53	)
Total Level 1 Assets (1)		$	226,785			$	18,631			$	245,416
Level 2—Significant other observable inputs
Cash equivalents		$	3			$	—			$	3
Commercial paper			1,414				46				1,460
Government fixed income and mortgage backed			36,078				1,177				37,255
Corporate fixed income			40,646				1,326				41,972
Pooled funds and mutual funds			9,588				1,767				11,355
State and local obligations			262				9				271
Total Level 2 assets (2)		$	87,991			$	4,325			$	92,316
Level 3—Significant unobservable inputs
Commingled equity funds		$	75,418			$	2,461			$	77,879
Guaranteed investment contracts/guaranteed annuity contracts			5,673				—				5,673
Total Level 3 assets (3)		$	81,091			$	2,461			$	83,552
Total (4)		$	395,867			$	25,417			$	421,284

 

(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 are 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.

 

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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

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.

(4)

The assets in the above table exceed the market value of plan assets shown in the funded status table by a net $2.8 million (qualified retirement plan—$2.9 million, PBOP—($100,000)), which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

 

		Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
		Commingled Equity Funds				Guaranteed Investment Contracts/Guaranteed Annuity Contracts				Total
(Thousands of dollars):
Beginning balance at December 31, 2008		$	57,017			$	6,042			$	63,059
Actual return on plan assets:
Relating to assets still held at the reporting date			20,466				243				20,709
Relating to assets sold during the period			816				—				816
Purchases, sales, and settlements			(420	)			(612	)			(1,032	)
Transfers in and/or out of Level 3			—				—				—
Ending balance at December 31, 2009		$	77,879			$	5,673			$	83,552

Note 10—Stock-Based Compensation

At December 31, 2009, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income for the years ended December 31, 2009, December 31, 2008, and December 31, 2007 were $5.2 million (net of related tax benefits of $3.2 million), $4.9 million (net of related tax benefits of $3 million), and $4.9 million (net of related tax benefits of $3 million), respectively.

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

 

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

 

		2009					2008					2007
		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		731			$27.12		798			$26.85		957			$26.26
Granted during the year		—			—		—			—		—			—
Exercised during the year		(66	)		23.18		(64	)		23.70		(158	)		23.24
Forfeited during the year		—			—		(3	)		27.72		(1	)		33.07
Expired during the year		(14	)		28.88		—			—		—			—
Outstanding at year end		651			$27.49		731			$27.12		798			$26.85
Exercisable at year end		651			$27.49		663			$26.55		561			$25.50

The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding options was $1.7 million, $661,000, and $3.1 million at December 31, 2009, 2008, and 2007, respectively. The aggregate intrinsic value of exercisable options was $1.7 million, $661,000, and $2.7 million at December 31, 2009, 2008, and 2007, respectively. The aggregate intrinsic value of exercised options was $294,000, $339,000, and $1 million during 2009, 2008, and 2007, respectively. The market value of Southwest Gas stock was $28.53, $25.22, and $29.77 at December 31, 2009, 2008, and 2007, respectively.

The weighted-average remaining contractual life for outstanding options was 5.3 years for 2009. All outstanding options are exercisable. The following table summarizes information about stock options outstanding at December 31, 2009 (thousands of options):

 

		Options Outstanding and Exercisable
Range of Exercise Price		Number outstanding		Weighted- average remaining contractual life		Weighted- average exercise price
$17.94 to $23.40		196		3.8 Years		$22.65
$24.50 to $26.10		209		5.4 Years		$25.93
$29.08 to $33.07		246		6.5 Years		$32.66

 

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The total grant date fair value of options vested was $405,000, $824,000, and $1.2 million during 2009, 2008, and 2007, respectively. The Company received $1.5 million in cash from the exercise of options during 2009 and a corresponding tax benefit of $109,000 which was recorded in additional paid-in capital.

The following table summarizes the final vesting of the Company’s options during 2009 (thousands of options):

 

		Number of options			Weighted- average grant date fair value
Nonvested at the beginning of the year		68			$	5.93
Granted		—				—
Vested		(68	)			5.93
Forfeited		—				—
Nonvested at December 31, 2009		—			$	—

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

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2009 (thousands of shares):

 

		Performance Shares			Weighted- average grant date fair value			Restricted Stock/Units			Weighted- average grant date fair value
Nonvested at beginning of year		267			$	31.38		84			$	31.15
Granted		131				24.46		95				24.46
Dividends		13						6
Forfeited		(2	)			29.33		(1	)			26.78
Vested and issued*		(89	)			27.75		(38	)			31.02
Nonvested at December 31, 2009		320			$	29.20		146			$	26.47

 

*	Includes shares converted for taxes.

The average grant date fair value of performance shares granted in 2008 and 2007 was $29.31 and $38.21, respectively. The average grant date fair value of restricted stock/units granted in 2008 and 2007 was $27.25 and $38.48, respectively.

 

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Note 11—Income Taxes

As of December 31, 2009 and 2008, the Company had $1.4 million of uncertain tax liabilities which, if recognized, would favorably impact the effective tax rate. There was no change to the balance of unrecognized tax benefits during 2009 and the Company does not expect a significant increase or decrease in its unrecognized tax benefits in the next twelve months. The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. Tax-related interest income of $200,000, $900,000, and $1 million is included in the consolidated statements of income for 2009, 2008, and 2007, respectively. Tax-related interest payable of $100,000 (at December 31, 2009) and interest receivable of $700,000 (at December 31, 2008) is included in the consolidated balance sheets.

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 and by the various state taxing authorities for years after 2004.

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

 

		2009			2008
Unrecognized tax benefits at beginning of year		$	1,445		$	1,445
Gross increases—tax positions in prior period			—			—
Gross decreases—tax positions in prior period			—			—
Gross increases—current period tax positions			—			—
Gross decreases—current period tax positions			—			—
Settlements			—			—
Lapse of statute of limitations			—			—
Unrecognized tax benefits at end of year		$	1,445		$	1,445

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

 

Year Ended December 31,		2009				2008			2007
Current:
Federal		$	(1,020	)		$	5,420		$	37,668
State			3,101				1,106			6,989
			2,081				6,526			44,657
Deferred:
Federal		$	41,410				32,569			2,813
State			1,426				1,740			308
			42,836				34,309			3,121
Total income tax expense		$	44,917			$	40,835		$	47,778

 

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

 

Year Ended December 31,		2009				2008				2007
Deferred federal and state:
Property-related items		$	46,201			$	53,978			$	26,300
Purchased gas cost adjustments			(4,167	)			(15,918	)			(24,972	)
Employee benefits			(452	)			(1,884	)			2,263
All other deferred			2,122				(999	)			398
Total deferred federal and state			43,704				35,177				3,989
Deferred ITC, net			(868	)			(868	)			(868	)
Total deferred income tax expense		$	42,836			$	34,309			$	3,121

The consolidated effective income tax rate for the period ended December 31, 2009 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,		2009			2008			2007
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		2.5			2.4			2.7
Property-related items		0.2			0.2			0.4
Effect of income tax settlements		(0.2	)		(0.9	)		(0.4	)
Tax credits		(0.7	)		(0.9	)		(0.7	)
Company owned life insurance		(2.5	)		4.0			(0.5	)
All other differences		(0.3	)		0.3			—
Consolidated effective income tax rate		34.0	%		40.1	%		36.5	%

 

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

 

December 31,		2009				2008
Deferred tax assets:
Deferred income taxes for future amortization of ITC		$	4,817			$	5,353
Employee benefits			41,877				39,693
Alternative minimum tax credit			19,894				20,457
Other			7,129				6,686
			73,717				72,189
Deferred tax liabilities:
Property-related items, including accelerated depreciation			456,795				410,588
Regulatory balancing accounts			1,151				5,317
Property-related items previously flowed through			5,014				6,161
Unamortized ITC			7,728				8,595
Debt-related costs			5,011				5,143
Other			11,721				9,022
			487,420				444,826
Net deferred tax liabilities		$	413,703			$	372,637
Current		$	(22,410	)		$	(14,902	)
Noncurrent			436,113				387,539
Net deferred tax liabilities		$	413,703			$	372,637

Note 12—Derivatives and Fair Value Measurements

In managing its natural gas supply portfolios, Southwest has historically entered into fixed- and variable-price contracts, which qualify as derivatives. In 2008, Southwest also began utilizing fixed-for-floating swap contracts (“Swaps”) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business 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 approximately 50 percent of its natural gas portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during timeframes ranging from January 2010 through June 2011. Under such contracts, Southwest pays the counterparty at a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts (approximately 13.6 million dekatherms at December 31, 2009 and 6.5 million dekatherms at December 31, 2008). Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.

 

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

Derivatives not designated as hedging instruments:

 

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

 

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

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

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

Derivatives not designated as hedging instruments:

 

December 31, 2009
		Balance Sheet Location		Asset Derivatives			Liability Derivatives				Net Total
Swaps		Deferred charges and other assets		$	85		$	(27	)		$	58
Swaps		Prepaids and other current assets			2,921			(361	)			2,560
Swaps		Other current liabilities			309			(1,730	)			(1,421	)
Swaps		Other deferred credits			25			(100	)			(75	)
Total				$	3,340		$	(2,218	)		$	1,122
December 31, 2008
		Balance Sheet Location		Asset Derivatives			Liability Derivatives				Net Total
Swaps		Deferred charges and other assets		$	380		$	(88	)		$	292
Swaps		Other current liabilities			—			(14,440	)			(14,440	)
Total				$	380		$	(14,528	)		$	(14,148	)

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 settle,

 

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Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under the related purchased gas adjustment (“PGA”) mechanism in determining its deferred PGA balances. During the year ended December 31, 2009, Southwest paid counterparties $19.7 million in settlements of matured Swaps. Neither changes in the fair value of the Swaps nor settled amounts have a direct effect on earnings or other comprehensive income. At December 31, 2009, regulatory assets/liabilities offsetting the amounts in the above table were recorded in Prepaids and other current assets ($1.4 million), Other current liabilities ($2.6 million), Other deferred credits ($58,000), and Deferred charges and other assets ($75,000). At December 31, 2008, regulatory assets/liabilities offsetting the amounts in the above table were recorded in Prepaids and other current assets ($14.4 million) and Other deferred credits ($292,000).

The estimated fair values of Southwest’s Swaps were determined at December 31, 2009 and 2008 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.

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.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2009 and 2008.

Level 2—Significant other observable inputs

 

		December 31, 2009				December 31, 2008
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets—swaps		$	2,560			$	—
Deferred charges and other assets—swaps			58				292
Liabilities at fair value:
Other current liabilities—swaps			(1,421	)			(14,440	)
Other deferred credits—swaps			(75	)			—
Net Assets (Liabilities)		$	1,122			$	(14,148	)

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

In January 2010, Southwest entered into two forward-starting interest rate swap (“FSIRS”) agreements to hedge the risk of interest rate variability during the period leading up to the planned issuance of 10-year fixed-rate debt in December 2010 and March 2012, to replace a total of $400 million of debt maturing in February

 

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2011 and May 2012, respectively. The counterparties to both agreements comprise four major banking institutions. The first FSIRS has a notional amount of $125 million (with Southwest as the fixed-rate payer at a rate of 4.26%) and has a mandatory termination date on or before December 7, 2010. The second FSIRS has a notional amount of $100 million (with Southwest as the fixed-rate payer at a rate of 4.78%) and has a mandatory termination date on or before March 20, 2012. Southwest has designated the FSIRS agreements as cash flow hedges of forecasted future interest payments.

Note 13—Segment Information

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

The accounting policies of the reported segments are the same as those described within Note 1—Summary of Significant Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2009 and 2008, accounts receivable for these services totaled $5.3 million and $6.6 million, respectively, which were not eliminated during consolidation.

The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2009 is as follows (thousands of dollars):

 

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

 

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2008		Gas Operations			Construction Services			Adjustments (a)				Total
Revenues from unaffiliated customers		$	1,791,395		$	290,218						$	2,081,613
Intersegment sales			—			63,130							63,130
Total		$	1,791,395		$	353,348						$	2,144,743
Interest revenue		$	2,107		$	105						$	2,212
Interest expense		$	90,825		$	1,823						$	92,648
Depreciation and amortization		$	166,337		$	27,382						$	193,719
Income tax expense		$	35,600		$	5,235						$	40,835
Segment income		$	53,747		$	7,226						$	60,973
Segment assets		$	3,680,327		$	140,057						$	3,820,384
Capital expenditures		$	279,254		$	20,963						$	300,217
2007		Gas Operations			Construction Services			Adjustments (a)				Total
Revenues from unaffiliated customers		$	1,814,766		$	265,937						$	2,080,703
Intersegment sales			—			71,385							71,385
Total		$	1,814,766		$	337,322						$	2,152,088
Interest revenue		$	4,366		$	82						$	4,448
Interest expense		$	94,163		$	2,036						$	96,199
Depreciation and amortization		$	157,090		$	25,424						$	182,514
Income tax expense		$	40,914		$	6,864						$	47,778
Segment income		$	72,494		$	10,752						$	83,246
Segment assets		$	3,518,304		$	152,096		$	(212	)		$	3,670,188
Capital expenditures		$	312,412		$	28,463						$	340,875

 

(a)	Construction services segment assets include income taxes payable of $1.4 million in 2009 and $212,000 in 2007, which were netted against gas operations segment income taxes receivable, net during consolidation.

 

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Note 14—Quarterly Financial Data (Unaudited)

 

		Quarter Ended
		March 31		June 30			September 30			December 31
(Thousands of dollars, except per share amounts)
2009
Operating revenues		$689,862		$387,648			$317,509			$498,805
Operating income		102,729		14,685			522			90,455
Net income (loss)		49,981		(594	)		(8,297	)		46,392
Basic earnings (loss) per common share*		1.13		(0.01	)		(0.18	)		1.03
Diluted earnings (loss) per common share*		1.12		(0.01	)		(0.18	)		1.02
2008
Operating revenues		$813,607		$447,304			$374,422			$509,410
Operating income		104,685		18,256			2,900			82,021
Net income (loss)		49,152		(2,725	)		(16,686	)		31,232
Basic earnings (loss) per common share*		1.14		(0.06	)		(0.38	)		0.71
Diluted earnings (loss) per common share*		1.14		(0.06	)		(0.38	)		0.71
2007
Operating revenues		$793,716		$426,537			$371,524			$560,311
Operating income		101,325		18,405			8,569			94,001
Net income (loss)		49,764		(337	)		(9,318	)		43,137
Basic earnings (loss) per common share*		1.19		(0.01	)		(0.22	)		1.01
Diluted earnings (loss) per common share*		1.17		(0.01	)		(0.22	)		1.00

 

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

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

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2009. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 25, 2010

 

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SOUTHWEST GAS CORPORATION 2009

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

Los Angeles, California

February 25, 2010

 

P70