SOUTHWEST GAS CORP - FORM 10-K - EX-13.01

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Exhibit 13.01

Consolidated Selected Financial Statistics


Year Ended December 31,	2014			2013			2012			2011			2010
(Thousands of dollars, except per share amounts)
Operating revenues	$	2,121,707		$	1,950,782		$	1,927,778		$	1,887,188		$	1,830,371
Operating expenses		1,837,224			1,676,567			1,656,254			1,637,108			1,598,254

Operating income	$	284,483		$	274,215		$	271,524		$	250,080		$	232,117

Net income	$	141,126		$	145,320		$	133,331		$	112,287		$	103,877

Total assets at year end	$	5,214,515		$	4,565,174		$	4,488,057		$	4,276,007		$	3,984,193

Capitalization at year end
Total equity	$	1,486,266		$	1,412,395		$	1,308,498		$	1,225,031		$	1,166,996
Redeemable noncontrolling interest		20,042			—			—			—			—
Long-term debt, excluding current maturities		1,637,592			1,381,327			1,268,373			930,858			1,124,681

	$	3,143,900		$	2,793,722		$	2,576,871		$	2,155,889		$	2,291,677

Current maturities of long-term debt	$	19,192		$	11,105		$	50,137		$	322,618		$	75,080
Common stock data
Common equity percentage of capitalization		47.3	%		50.6	%		50.8	%		56.8	%		50.9	%
Return on average common equity		9.7	%		10.6	%		10.4	%		9.3	%		9.1	%
Basic earnings per share	$	3.04		$	3.14		$	2.89		$	2.45		$	2.29
Diluted earnings per share	$	3.01		$	3.11		$	2.86		$	2.43		$	2.27
Dividends declared per share	$	1.46		$	1.32		$	1.18		$	1.06		$	1.00
Payout ratio		48	%		42	%		41	%		43	%		44	%
Book value per share at year end	$	32.03		$	30.51		$	28.39		$	26.68		$	25.60
Market value per share at year end	$	61.81		$	55.91		$	42.41		$	42.49		$	36.67
Market value per share to book value per share		193	%		183	%		149	%		159	%		143	%
Common shares outstanding at year end (000)		46,523			46,356			46,148			45,956			45,599
Number of common shareholders at year end		14,749			15,359			16,028			16,834			17,821
Ratio of earnings to fixed charges		3.58			3.90			3.61			3.21			2.87


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Natural Gas Operations


Year Ended December 31,	2014			2013			2012			2011			2010
(Thousands of dollars)
Operating revenue		1,382,087			1,300,154			1,321,728			1,403,366			1,511,907
Net cost of gas sold		505,356			436,001			479,602			613,489			736,175

Operating margin		876,731			864,153			842,126			789,877			775,732
Expenses
Operations and maintenance		383,732			384,914			369,979			358,498			354,943
Depreciation and amortization		204,144			193,848			186,035			175,253			170,456
Taxes other than income taxes		47,252			45,551			41,728			40,949			38,869

Operating income	$	241,603		$	239,840		$	244,384		$	215,177		$	211,464

Contribution to consolidated net income	$	116,872		$	124,169		$	116,619		$	91,420		$	91,382

Total assets at year end	$	4,657,709		$	4,272,029		$	4,204,948		$	4,048,613		$	3,845,111

Net gas plant at year end	$	3,658,383		$	3,486,108		$	3,343,794		$	3,218,944		$	3,072,436

Construction expenditures and property additions	$	350,025		$	314,578		$	308,951		$	305,542		$	188,379

Cash flow, net
From operating activities	$	288,534		$	265,290		$	344,441		$	216,745		$	342,522
From (used in) investing activities		(328,645	)		(304,189	)		(296,886	)		(289,234	)		(178,685	)
From (used in) financing activities		23,413			44,947			(43,453	)		(2,327	)		(107,779	)

Net change in cash	$	(16,698	)	$	6,048		$	4,102		$	(74,816	)	$	56,058

Total throughput (thousands of therms)
Residential		617,377			741,327			655,046			718,765			704,693
Small commercial		276,582			298,045			270,665			303,923			300,940
Large commercial		94,391			102,761			116,582			112,256			111,833
Industrial/Other		32,374			50,210			47,830			50,208			58,922
Transportation		906,691			1,037,916			998,095			941,544			998,600

Total throughput		1,927,415			2,230,259			2,088,218			2,126,696			2,174,988

Weighted average cost of gas purchased ($/therm)	$	0.55		$	0.42		$	0.42		$	0.58		$	0.62
Customers at year end		1,930,000			1,904,000			1,876,000			1,859,000			1,837,000
Employees at year end		2,196			2,220			2,245			2,298			2,349
Customer to employee ratio		879			858			836			809			782
Degree days – actual		1,416			1,918			1,740			2,002			1,998
Degree days – ten-year average		1,816			1,876			1,866			1,888			1,876


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

About Southwest Gas Corporation

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

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

As of December 31, 2014, Southwest had 1,930,000 residential, commercial, industrial, and other natural gas customers, of which 1,033,000 customers were located in Arizona, 708,000 in Nevada, and 189,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2014, 55% of operating margin was earned in Arizona, 34% in Nevada, and 11% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.

Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting changes in operating margin are general rate relief (including impact of infrastructure trackers) and customer growth. All of Southwest’s service territories have decoupled rate structures, which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of weather variability and conservation on margin, allowing the Company to aggressively pursue energy efficiency initiatives.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co. (“NPL”), completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating Centuri Construction Group Inc. (“Centuri” or the “construction services” segment), a direct subsidiary of Carson Water Company. In addition, two direct subsidiaries were created under Centuri: Vistus Construction Group Inc. (“Vistus,” U.S. operations) and Lynxus Construction Group Inc. (“Lynxus,” Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line Contractors Ltd. and W.S. Nicholls Construction Inc. are subsidiaries of Lynxus. References to the name Centuri or the term construction services will relate to results or activities of the businesses, individually or in the aggregate, included in the Centuri organization.

Centuri, a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems,


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and develops industrial construction solutions. Centuri operates in 20 major markets in the United States (primarily under the NPL name) and in 2 major markets in Canada (under the Link-Line and W.S. Nicholls names). Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented or modified pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the U.S. Generally, revenues are lowest during the first quarter of the year due to less favorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. This is expected in both the U.S. and Canadian markets. In certain circumstances, such as with large, longer duration bid contracts, or unit-price contracts with revenue caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid.

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. As reflected in the table below, the natural gas operations segment accounted for an average of 85% of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.

Summary Operating Results


Year ended December 31,	2014		2013		2012
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations	$	116,872	$	124,169	$	116,619
Construction services		24,254		21,151		16,712

Consolidated	$	141,126	$	145,320	$	133,331

Average number of common shares outstanding		46,494		46,318		46,115

Basic earnings per share
Consolidated	$	3.04	$	3.14	$	2.89

Natural Gas Operations
Operating margin	$	876,731	$	864,153	$	842,126

2014 Overview

Consolidated results for 2014 decreased compared to 2013 due to lower results from the natural gas operations segment, partially offset by improved results from the construction services segment. Basic earnings per share were $3.04 in 2014 compared to basic earnings per share of $3.14 in 2013.

Natural gas operations highlights include the following:

•

Operating margin increased $13 million, or 1%, compared to the prior year

•

Operating expenses increased $11 million, or 2%, between years

•

Net financing costs increased $6 million between 2014 and 2013


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•

COLI income decreased from $12.4 million to $5.3 million between years

•

Credit facility expiration date extended two years to March 2019

•

Decision reached in the California general rate case

•

Settlement reached in the Paiute Pipeline Company rate case

•

The Company’s credit rating was upgraded from Baa1 to A3 by Moody’s Investors Service in January 2014 and downgraded from A- to BBB+ by Standard and Poor’s in October 2014

Construction services highlights include the following:

•

Completed acquisition of three construction services businesses in October 2014

•

Revenues in 2014 increased $89 million, or 14%, compared to 2013

•

Construction expenses increased $75 million or 13%, compared to 2013, and included $5 million in transaction costs

•

Contribution to net income increased $3 million compared to 2013

Customer Growth. Southwest completed 20,000 first-time meter sets, but realized 26,000 net new customers during 2014, an increase of 1.4%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for 2015.

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 $241 million at December 31, 2014. 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 $99 million at December 31, 2014 and is included in the caption “Other property and investments” on the balance sheet. The Company currently intends to hold the COLI policies for their duration. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. As indicated in Note 1 of the Notes to Consolidated Financial Statements, income due to changes in cash surrender values of COLI policies (including incremental death benefits) was $5.3 million in 2014 and $12.4 million in 2013. Management currently expects average returns of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized.

Liquidity. Southwest believes its liquidity position is solid. Southwest has a $300 million credit facility maturing in March 2019. The facility is provided through a consortium of eight major banking institutions. The maximum amount outstanding on the credit facility (including a commercial paper program) during 2014 was $165 million. In November 2014, the Company redeemed the $65 million 5.25% 2004 Series A Industrial Development Revenue Bonds (“IDRBs”) using the credit facility to fund the redemption. At December 31, 2014, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $5 million was outstanding on the short-term portion of the credit facility. Southwest has no significant debt maturities prior to 2017.


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Construction Services. Centuri’s contribution to net income for 2014 was $24.3 million, a $3.1 million increase over the results for 2013. Acquisition costs of $5 million were included in construction expenses in 2014. Gains on sale of equipment in the current year were $6.2 million compared to $4.1 million in the prior year. The prior year also included $4 million in legal-related expenses.

Results of Natural Gas Operations


Year Ended December 31,	2014		2013		2012
(Thousands of dollars)
Gas operating revenues	$	1,382,087	$	1,300,154	$	1,321,728
Net cost of gas sold		505,356		436,001		479,602

Operating margin		876,731		864,153		842,126
Operations and maintenance expense		383,732		384,914		369,979
Depreciation and amortization		204,144		193,848		186,035
Taxes other than income taxes		47,252		45,551		41,728

Operating income		241,603		239,840		244,384
Other income (deductions)		7,165		12,261		4,165
Net interest deductions		68,299		62,555		66,957

Income before income taxes		180,469		189,546		181,592
Income tax expense		63,597		65,377		64,973

Contribution to consolidated net income	$	116,872	$	124,169	$	116,619

2014 vs. 2013

Contribution to consolidated net income from natural gas operations decreased by $7.3 million between 2014 and 2013. Increases in net interest deductions, as well as a decrease in other income, offset improved operating income.

Operating margin increased $13 million between years including a combined $8 million of rate relief in the California jurisdiction and Paiute Pipeline Company (see Rates and Regulatory Proceedings). New customers contributed $8 million of the increase during 2014 as approximately 26,000 net new customers were added during the last twelve months. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues declined by $3 million.

Operations and maintenance expense decreased $1.2 million, or less than 1%, between years primarily due to declines in employee-related costs, partially offset by a $5 million legal accrual in the first quarter of 2014 and higher general costs. A planned $9 million reduction in pension costs and a $3 million reduction in employer-sponsored medical costs, due to positive claims experience between years resulted in a favorable impact to 2014 operations and maintenance expense of approximately $9.5 million.

Depreciation and amortization expense increased $10.3 million, or 5%. Average gas plant in service for the current year increased $297 million, or 6%, as compared to the prior year. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business, partially offset by depreciation rate decreases resulting from the most recent California general rate case decision. Amortization primarily associated with software-related intangible assets increased approximately


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$1.3 million. Amortization associated with the recovery of regulatory assets increased approximately $1.2 million overall (primarily due to Arizona demand-side management, or “DSM,” programs).

Taxes other than income taxes increased $1.7 million between periods due to higher property taxes in Arizona and Nevada.

Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, decreased $5.1 million between 2014 and 2013. The current year reflects $5.3 million of income associated with COLI policy cash surrender value increases, while the prior year included $12.4 million of COLI-related income. Interest income increased $2.1 million between years. Under-collected PGA balances and the associated interest income thereon rose significantly in the current year (see PGA Filings for more information).

Net interest deductions increased $5.7 million between years, primarily due to the issuance of $250 million of long-term debt in the fourth quarter of 2013. The increase was mitigated by higher interest expense in the prior year associated with PGA balances, which were in an over-collected status for the majority of 2013.

2013 vs. 2012

Contribution to consolidated net income from natural gas operations increased by $8 million between 2013 and 2012. The improvement was primarily due to increases in operating margin and other income and a decrease in net interest deductions, partially offset by higher operating expenses.

Operating margin increased $22 million between years. Rate relief provided $8 million of the increase in operating margin (including general rate relief in Nevada and net attrition amounts in California). New customers contributed $7 million of the increase in operating margin during 2013. Incremental margin from customers outside the decoupling mechanisms and other miscellaneous revenues (including amounts associated with recoveries of Arizona regulatory assets) contributed the remainder of the increase.

Operations and maintenance expense increased $14.9 million, or 4%, between years primarily due to higher general costs, employee-related costs (including a majority of the $6.4 million increase in pension costs), uncollectible expense, and pipeline integrity management programs, partially offset by lower legal claims and expenses.

Depreciation and amortization expense increased $7.8 million, or 4%. Average gas plant in service for 2013 increased $230 million, or 5%, compared to 2012. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in Nevada (effective November 2012). Amortization associated with the recovery of Arizona regulatory assets, new conservation and energy efficiency programs in Nevada, and other amortization collectively increased $6.2 million.

Taxes other than income taxes increased $3.8 million between periods due to higher property taxes in Arizona and changes resulting from the last Nevada general rate case, whereby modified business and mill taxes became components of operating expenses.

Other income increased $8.1 million between 2013 and 2012. Cash surrender values of COLI policies (including net death benefits recognized) increased $12.4 million in 2013, while COLI-related income was $6.6 million in the prior year. In addition, Arizona non-recoverable pipe replacement costs were $2.5 million lower in 2013 as compared to 2012 because this pipe replacement activity was substantially completed in 2012.


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Net interest deductions decreased $4.4 million between 2013 and 2012 primarily due to cost savings from refinancing, redemptions, and lower interest expense associated with deferred PGA balances payable. The decrease was partially offset by the October 2013 issuance of $250 million of 4.875% senior notes. The prior year included a temporary increase in debt outstanding for approximately two months associated with debt refinancing that occurred in the first half of 2012.

Outlook for 2015

Operating margin for 2015 is expected to be favorably influenced by customer growth similar to 2014. Incremental margin (attrition) associated with the 2014 California rate case decision as well as the Paiute rate case decision, and new rates established to recover Nevada infrastructure programs (see Rates and Regulatory Proceedings) collectively should approximate the customer growth amount. Combined, total operating margin is estimated to increase nearly 2%.

Operations and maintenance expense will be negatively impacted by a proportionate share (approximately 80%) of an expected $10 million increase in pension costs. Other costs, net, are expected to be relatively flat. Depreciation and general taxes should increase consistent with the growth in gas plant in service (approximately 5% to 6%). Overall, operating expenses are anticipated to increase by 3% to 4% compared to 2014.

COLI-related income was $5.3 million in 2014, which is at the upper end of the expected range of average returns, as Southwest generally anticipates longer term normal changes in COLI cash surrender values to range from $3 million to $5 million on an annual basis. However, individual quarterly and annual periods will continue to be subject to volatility.

Southwest anticipates that net interest deductions for 2015 will approximate the $68 million recorded in 2014.

Results of Construction Services


Year Ended December 31,	2014			2013			2012
(Thousands of dollars)
Construction revenues	$	739,620		$	650,628		$	606,050
Operating expenses:
Construction expenses		647,857			573,284			541,523
Depreciation and amortization		48,883			42,969			37,387

Operating income		42,880			34,375			27,140
Other income (deductions)		(58	)		39			246
Net interest deductions		3,770			1,145			1,063

Income before income taxes		39,052			33,269			26,323
Income tax expense		14,776			12,565			10,303

Net income		24,276			20,704			16,020
Net income (loss) attributable to noncontrolling interests		22			(447	)		(692	)

Contribution to consolidated net income attributable to Centuri	$	24,254		$	21,151		$	16,712

2014 vs. 2013

Contribution to consolidated net income from construction services for 2014 increased $3.1 million compared to 2013.


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Revenues increased $89.0 million, or 14%, when compared to 2013 primarily due to additional pipe replacement work in 2014 and the inclusion of the acquired companies’ revenues ($54.3 million) beginning in the fourth quarter. Construction revenues include Centuri contracts with Southwest totaling $92.2 million in 2014 and $88.2 million in 2013. Centuri accounts for services provided to Southwest at contractual (market) prices at contract inception.

Construction expenses increased $74.6 million, or 13%, due primarily to additional pipe replacement work in 2014 and the inclusion of the acquired companies’ construction costs ($49.4 million). General and administrative expense (included in construction expenses) increased $9.5 million including $3.7 million from the recently acquired companies, acquisition costs ($5 million), and changes that were implemented to match the increased size of the business and its complexity. In addition, construction services recorded approximately $4 million in 2013 associated with a legal settlement which was resolved in February 2014. Gains on sale of equipment (reflected as an offset to construction expenses) were $6.2 million and $4.1 million in 2014 and 2013, respectively. Depreciation and amortization expense increased $5.9 million between 2014 and the prior year due to the amortization on finite-lived intangible assets recognized from the acquisition ($1.5 million) and additional equipment purchased to support growth in the volume of work being performed.

Net interest deductions were $3.8 million in 2014 compared to $1.1 million in 2013. The increase was due primarily to interest expense and amortization of debt issuance costs associated with the $300 million secured revolving credit and term loan facility entered into coincident with the recent acquisition.

During the past several years, construction services has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2014 and 2013, revenues from replacement work were 67% and 70%, respectively, of total revenues. Governmental pipeline safety-related programs and U.S. tax bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. Centuri continues to successfully bid on pipe replacement projects throughout the United States and Canada.

2013 vs. 2012

Contribution to consolidated net income from construction services for 2013 increased $4.4 million compared to 2012. The increase was primarily due to a $15 million pretax loss recognized on a large fixed-price contract in 2012, partially offset by lower gains on the sale of equipment and higher general and administrative expenses (included in Construction expenses) in 2013.

Revenues increased $44.6 million, or 7%, when compared to 2012 due primarily to an increase in utility customer contracts for pipe replacement work, partially offset by the winding down of a portion of work related to the large fixed-price contract noted above. Construction revenues include NPL contracts with Southwest totaling $88.2 million in 2013 and $83.4 million in 2012. Construction services accounts for services provided to Southwest at contractual (market) prices at contract inception.

Construction expenses increased $31.8 million, or 6%, primarily due to additional pipe replacement work in 2013 as compared to 2012. Despite these increases, the construction expense variance between years was favorably impacted as 2012 included a $15 million pretax loss associated with the above-noted large fixed-price contract. General and administrative expense (included in construction expenses) increased approximately $6 million due to changes that were implemented to match the increased size of the business and its complexity. In addition, the construction services segment recorded approximately $4 million in 2013 associated with a legal settlement which


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was resolved in February 2014. Depreciation and amortization expense increased $5.6 million between 2013 and 2012 due to additional equipment purchased to support growth in the volume of work being performed. Gains on sale of equipment (reflected as an offset to construction expenses) were $4.1 million and $8 million in 2013 and 2012, respectively.

During the past several years, the constructions services segment has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2013 and 2012, revenues from replacement work were 70% and 75%, respectively, of total revenues. Governmental pipeline safety-related programs and bonus depreciation incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.

Outlook for 2015

Centuri’s revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, changes in foreign currency exchange rates and the credit market. Typically, revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions. Revenues typically improve as more favorable weather conditions occur during the summer and fall months. The current low interest rate environment, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on Centuri’s results.

The recent acquisition has expanded the construction services operating base. Comparative results for 2015 will be favorably impacted by elimination of the acquisition costs ($5 million) recognized in 2014 as well as a full year of results associated with the acquisition (compared to one quarter in 2014). In 2015, Centuri revenues are expected to range between $950 million and $1 billion, and operating income is expected to approximate 6% of revenues (including the impacts of amortization, resulting from acquired intangibles, of approximately $5 million). Based on interest rates under Centuri’s secured revolving credit and term loan facility as of December 2014, we anticipate 2015 related net interest deductions to be between $6.5 million and $7.5 million. These collective expectations are before consideration of the portion of earnings attributable to the noncontrolling interest. Additionally, foreign exchange rates and the interest rate environment could influence their achievement.

Rates and Regulatory Proceedings

General Rate Relief and Rate Design

Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change, and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management has worked with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such rate structures were in place in all of Southwest’s operating areas during 2012 to 2014.

Nevada Jurisdiction

General Rate Case Status. The most recent general rate case decision was received from the Public Utility Commission of Nevada (“PUCN”) in November 2012, and was amended in a Rehearing Decision in March 2013. The


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Rehearing Decision addressed issues raised by Southwest regarding capital structure. After taking into account modifications made as a result of the Rehearing Decision, the Company was authorized an annual revenue increase of $6.8 million, an overall rate of return of 6.56%, and a 10% return on 42.7% common equity in southern Nevada; and an annual revenue increase of $700,000, an overall rate of return of 7.88%, and a 9.30% return on 59.1% common equity in northern Nevada, while retaining an alternative capital structure rather than what was proposed by Southwest. The PUCN decision also included a reduction in annualized depreciation expense of $5.2 million and $1.7 million in southern and northern Nevada, respectively. In addition, the PUCN decision reclassified approximately $2.5 million of modified business and mill taxes from pass-through items to operating expenses.

Infrastructure Replacement Mechanisms. In January 2013, the PUCN authorized the opening of a new docket to review the merits of a mechanism to defer and recover certain costs associated with accelerated replacement of early vintage plastic (“EVPP”) and steel pipe, which was originally requested in the general rate case filed in April 2012. In January 2014, the PUCN concluded the rulemaking process by approving final rules, with only slight modifications to earlier proposed rules. The regulations provide for the establishment of regulatory assets that recover the depreciation expense and authorized pre-tax rate of return of infrastructure replacement investments between rate cases, which also allows Southwest to develop rates to recover the associated amounts in a future general rate case proceeding, at which time the plant will be “rolled into” rate base naturally.

Separately, in March 2013, Southwest submitted a petition to the PUCN requesting authority to defer certain costs associated with the proposed accelerated 2013 replacement of certain EVPP to coincide with bonus depreciation tax relief extended by The American Taxpayer Relief Act of 2012. In June 2013, a stipulation (the “Stipulation”), which provided regulatory asset treatment for specific infrastructure replacement projects occurring during 2013 in the amount of $2 million in northern Nevada and approximately $13.6 million in southern Nevada, was reached by all parties and was approved by the PUCN. While the above-noted infrastructure replacement regulation was being finalized, the Company submitted a filing to the PUCN in November 2013 requesting authority to replace $18.9 million of EVPP in 2014; the PUCN approved the request in January 2014. The new rules (noted in the paragraph above) enabled the Company to make a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying projects for replacement beginning in January 2015. The PUCN issued a final decision on this application in October 2014, approving EVPP replacement expenditures of $14.4 million in 2015. Also in October 2014, Southwest filed its first GIR rate application to request a surcharge to recover cumulative deferrals through August 2014, which were established through five separate regulatory dockets. This surcharge was made effective for both the southern and northern Nevada rate jurisdictions in January 2015.

Effectively, as a result of these mechanisms, the increase in depreciation expense, ordinarily arising from related capital expenditures, will be netted to zero for approved projects by the deferral process, between general rate cases. Incremental earnings associated with the equity portion of return related to these infrastructure replacements will materialize through billed rates, now that a surcharge has been established. The surcharge is expected to provide approximately $2 million in incremental operating margin in 2015 (part of which will be offset by higher amortization expense due to the favorable impacts previously recognized in deferring depreciation on the underlying plant). The actual amount achieved will be dependent upon actual volumes sold, as the surcharge is assessed through volumetric rates.


18 \| Southwest Gas Corporation

California Jurisdiction

General Rate Case. In December 2012, Southwest filed a general rate case application, based on a 2014 future test year, with the California Public Utilities Commission (“CPUC”) requesting an annual revenue increase of approximately $11.6 million for its California rate jurisdictions. Southwest sought to continue a Post-Test Year (“PTY”) Ratemaking Mechanism, which allows for annual attrition increases. The application included a request to establish a Customer-Owned Yardline (“COYL”) program and an Infrastructure Reliability and Replacement Adjustment Mechanism (“IRRAM”) to facilitate and complement projects involving the enhancement and replacement of gas infrastructure, promoting timely cost recovery for qualifying non-revenue producing capital expenditures.

In June 2014, the CPUC issued a final decision in this proceeding (“CPUC decision”), authorizing a $7.1 million overall revenue increase and PTY attrition increases of 2.75% annually for 2015 to 2018. A depreciation reduction of $3.1 million as requested by Southwest, was also approved. The CPUC decision also provides for a two-way pension balancing account to track differences between authorized and actual pension funding amounts, a limited COYL inspection program for schools, and an IRRAM to recover the costs associated with the new limited COYL program. New rates associated with the CPUC decision were effective June 2014.

In November 2014, Southwest made its annual PTY attrition filing, requesting annual revenue increases of $1.8 million in southern California, $486,000 in northern California and $243,000 for South Lake Tahoe. This filing was approved in December 2014 and rates were made effective in January 2015.

Greenhouse Gas (“GHG”) Compliance. California Assembly Bill Number 32 and the regulations promulgated by the California Air Resources Board (“CARB”), require Southwest, as a covered entity, to comply with all of the requirements associated with the California GHG Emissions Reporting Program and the California Cap and Trade Program. The objective of these programs is to reduce California statewide GHG emissions to 1990 levels by 2020. Southwest must report its annual GHG emissions by April of each year and third-party verification of those reported amounts is required by September of each year. Starting with 2015, the CARB will annually allocate to Southwest a certain number of allowances based on Southwest’s reported 2011 GHG emissions. Southwest received its allocation for 2015 in the third quarter of 2014. Of those allowances, Southwest must consign 25% into quarterly allowance auctions and the remaining allowances can be used to meet the triennial compliance obligation to cover the quantity of GHG emissions that occur during each triennial compliance period. The amount Southwest must consign increases by 5% annually. Given those levels of consignment, Southwest must also purchase allowances to meet its triennial compliance period obligations. Those purchases can be made through auctions or reserve sales that are hosted by the CARB, or through over the counter (“OTC”) purchases with other market participants. In addition to allowances, Southwest can purchase up to 8% of its annual GHG emissions with offsets, which are credits available in the OTC market from industries that generate reductions in greenhouse gas emissions.

There are two triennial compliance periods; one ending in 2017 and the other ending in 2020. To meet its compliance obligations, during each triennial compliance period, Southwest must surrender a combination of allowances and offsets equal to 30% of its annual reported GHG emissions for the prior year by November 1 of each year (2016 through 2020). Also by November 1 of the year following each of those triennial compliance periods (2018 and 2021), Southwest must surrender a sufficient number of allowances and offsets to meet the amount of GHG emissions reported during that triennial compliance period, less the amount previously surrendered.


		Southwest Gas Corporation \| 19

By September of each year, Southwest must inform the CARB of the percentage of Southwest’s annual allocation that are to be placed in Southwest’s Limited Use Holding Account (“LUHA”) for consignment to the quarterly auctions. In August 2014, Southwest filed the necessary paperwork with the CARB to place 25% of the allocated allowances in the LUHA. In December 2014, Southwest applied to participate in the quarterly auction to be held in February 2015 the results of which are still pending.

In January 2015, Southwest made a filing with the CPUC to establish two new balancing accounts required to comply with the GHG program. These accounts will be used to track and record costs incurred and revenue from consignment of the Company’s GHG allowances for auction and to separately track GHG administrative costs. An entry is expected during the first quarter of 2015 to record the amount required, in order to participate in the February 2015 auction, along with any associated costs. The recovery of these costs and the mechanism to return revenues received from consignment of the GHG allowances will be determined in Phase II of the CPUC Rulemaking, expected to occur during 2015.

Arizona Jurisdiction

General Rate Case Status. The most recent general rate case decision (“ACC decision”) from the Arizona Corporation Commission (“ACC”) in Southwest’s Arizona rate jurisdiction was made effective in January 2012 and authorized an increase of $52.6 million, which included a return on common equity of 9.50%, a fair value rate of return of 6.92% and a capital structure consisting of 47.7% long-term debt and 52.3% common equity. The ACC decision also approved a full revenue decoupling mechanism with a monthly weather adjuster. In addition, Southwest agreed not to file a general rate case prior to April 30, 2016.

Proposed LNG (“Liquefied Natural Gas”) Facility. In January 2014, Southwest filed an application with the ACC seeking preapproval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona and to recover the actual costs, including the establishment of a regulatory asset. This facility is intended to enhance service reliability and flexibility in natural gas deliveries in the southern Arizona area by providing a local storage option, operated by Southwest and connected directly to its distribution system. Southwest requested approval of the actual cost of the project (including those facilities necessary to connect the proposed storage tank to Southwest’s existing distribution system) not to exceed $55 million. Two options were presented in the ACC filing to fill the storage tank; either transferring LNG from tanker trucks or to liquefy the natural gas onsite. The liquefaction option would have required the installation of equipment during the construction of the facility, at an additional cost of approximately $24 million and an estimated additional six months to construct. In December 2014, Southwest received an order from the ACC (“Order”) granting pre-approval of Southwest’s application to construct the LNG facility, excluding the liquefaction option, and the deferral of costs, limited to $50 million. The authorization to defer costs expires on November 1, 2017 (from which point, expenditures incurred would not be eligible for deferral) and also requires any unquantified cost savings to be deferred. These deferred costs and benefits will be evaluated in a future rate proceeding. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. Construction progress reports are required every six months until completion. Completion of the siting requirements for flammable vapor dispersion is also a condition of approval for the facility. Construction is expected to be complete within approximately 24 to 30 months from the date of approval.

Customer-Owned Yardline (“COYL”) Program. The Company received approval, in connection with its most recent Arizona general rate case, to implement a program to conduct leak surveys, and if leaks were present, to replace and relocate service lines and meters for approximately 100,000 Arizona customers whose meters are setoff from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously


20 \| Southwest Gas Corporation

responsible for the cost of maintaining these lines and were subject to the immediate cessation of natural gas service if low-pressure leaks occurred. To facilitate this program, the Company was authorized to collect estimated leak survey costs in rates commencing in 2012. Effective June 2013, the ACC authorized a surcharge to recover the costs of depreciation and pre-tax return the Company would have received if the additional pipe replacement costs themselves had been included in rate base concurrent with the most recent Arizona rate case. The surcharge is revised annually as the program progresses, with the undepreciated plant balance to be incorporated in rate base at the time of the next Arizona general rate case. In November 2013, the Company filed a request to modify or clarify the COYL provision to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. This request was approved by the ACC in January 2014. A revised surcharge request, filed in February 2014, was approved effective June 2014. With the completion of Phase I customer contact, resources are now focused on contacting customers within replacement project areas to participate in the Phase II meter relocation.

Federal Energy Regulatory Commission (“FERC”) Jurisdiction.

General Rate Case. Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary of Southwest, filed a general rate case with the FERC in February 2014. The filing fulfilled an obligation from the settlement agreement reached in the 2009 Paiute general rate case. The application requested an increase in operating revenues of approximately $9 million, and included a proposed change in rate design, which would compensate Paiute with a higher return if shippers desire to maintain shorter-lived contracts and, therefore, would incent shippers to sign longer term service agreements.

In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle its general rate case. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement, which was filed with the FERC in November 2014, would result in a revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. This increase is based on an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed not to file a rate case prior to May 2016, but no later than May 2019.

In October 2014, Paiute requested, and was granted, the authority to place the settlement rates into effect on an interim basis effective September 2014. In February 2015, the FERC issued a letter order approving the settlement as filed. Tariff charges in compliance with the settlement will be filed within 30 days of the final approval, in March 2015.

Elko County Expansion Project. During the second and third quarters of 2013, Paiute notified present and potential shippers of its plans to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area. This additional capacity is required to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. Through the “open season” process, shippers responded with substantial interest. Dependent upon several variables, including the ultimate route of the project, the price of labor and materials, and factors such as environmental impacts, the cost to complete this project has been estimated at approximately $35 million and has a targeted in-service date of November 2015 (contingent upon FERC action). In October 2013, Paiute submitted a filing with the FERC requesting that its Staff initiate a pre-filing review of the proposed expansion project; a certificate application for the project was filed in June 2014. In October 2014, the FERC issued a notice of schedule for environmental review for this project. A preliminarily favorable environmental assessment of the proposed project was issued by the FERC in January 2015. Based on the FERC’s schedule, and the resulting associated deadlines, the FERC is expected to issue a decision on Paiute’s certificate application in the first half of 2015.


		Southwest Gas Corporation \| 21

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- or under-collections. At December 31, 2014, under-collections in all three states resulted in an asset of $87.6 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).

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


	2014		2013
Arizona	$	48.4	$	3.2
Northern Nevada		10.2		4.4
Southern Nevada		20.4		4.1
California		8.6		6.5

	$	87.6	$	18.2

Arizona PGA Filings. In May 2014, Southwest filed an application to provide for monthly adjustments to the surcharge component of the Gas Cost Balancing Account to allow for more timely refunds to/recoveries from ratepayers, which was approved in July 2014. As part of this filing, the ACC also approved an initial surcharge of $0.06 per therm effective August 2014.

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

Nevada Annual Rate Adjustment (“ARA”) Application. In June 2014, Southwest filed its ARA application with the PUCN to establish revised Base Tariff General Rates (“BTGR”), in addition to adjustments to the Variable Interest Expense rate, the Unrecovered Gas Cost Expense rates, and other rate-related items, all of which was approved effective January 2015. In November 2014, Southwest filed to adjust its quarterly Deferred Energy Account Adjustment (“DEAA”), which is based upon a twelve-month rolling average, in addition to requesting adjusted Base Tariff Energy (“BTER”) rates, both of which were also approved effective January 2015.

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 Swaps under its collective volatility mitigation programs for a portion (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) of its annual normal weather supply needs. For the 2014/2015 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $4 to $5 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.


22 \| Southwest Gas Corporation

In late 2013, the Company suspended further fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Nevada VMP suspension is forward looking and did not impact Nevada VMP purchase transactions that occurred prior to the suspension. Agreements, under the Nevada VMP program, made prior to the suspension will terminate following the March 2015 delivery month. The Company evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.

Capital Resources and Liquidity

Over the past three years, cash on hand and cash flows from operations have generally provided the majority of cash used in investing activities (primarily construction expenditures and property additions). Certain pipe replacement work was accelerated during these years to take advantage of bonus depreciation tax incentives and to fortify system integrity and reliability. During the same three-year period, the Company was able to establish long-term cost savings from debt refinancing and strategic debt redemptions. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs. A tax extenders bill, the Tax Increase Prevention Act of 2014, was signed into law, in late December 2014, retroactive to the beginning of the 2014, and did not extend into 2015.

Cash Flows

Operating Cash Flows. Cash flows provided by consolidated operating activities were comparable between 2014 and 2013. Both periods were impacted by period net income and the impacts of adding back non-cash depreciation and amortization, as well as the impacts of working capital components overall.

Investing Cash Flows. Cash used in consolidated investing activities increased $207.6 million in 2014 as compared to 2013. The increase was primarily due to the acquisition of the construction services businesses (see Note 15 – Acquisition of Construction Services Businesses for net assets acquired), additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by Centuri due to the increased replacement construction work of its customers. In addition, the current year includes cash outlays for the July 2014 purchase of the corporate headquarters office complex, but also includes greater inflows associated with customer advances taken for utility construction.

Financing Cash Flows. Net cash provided by consolidated financing activities increased $190.1 million in 2014 as compared to 2013. The current year includes the repayment of $65 million of IDRBs and the prior year included the repayment of $53 million of IDRBs and $101 million repayment of amounts outstanding on Southwest’s revolving credit and commercial paper facility. The prior year includes the issuance of $250 million of 4.875% senior notes, and the current year includes $145 million ($140 million long-term and $5 million short-term) of proceeds from Southwest’s revolving credit and commercial paper facility. The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under Centuri’s line of credit. The majority of Centuri’s borrowings are associated with the acquisition of construction services businesses noted previously. In addition, the prior period included Centuri borrowing under note agreements with two banking institutions entered into during the second quarter of 2013. Dividends paid increased in 2014 as compared to 2013 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding.

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


		Southwest Gas Corporation \| 23

2014 Construction Expenditures

During the three-year period ended December 31, 2014, total gas plant increased from $4.8 billion to $5.6 billion, or at an average annual rate of 5%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as the Company set approximately 59,000 meters during the three-year period.

During 2014, construction expenditures for the natural gas operations segment were $350 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant to fortify system integrity and reliability. Cash flows from operating activities of Southwest were $288 million and provided approximately 70% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and, as needed, existing credit facilities.

2014 Financing Activity

In March 2014, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2017, but was extended to March 2019.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2017 will be approximately $1.3 billion. Of this amount, approximately $445 million is expected to be incurred in 2015. Southwest plans to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). Significant replacement activities are expected to continue during the next several years. See also Rates and Regulatory Proceedings for discussion of Nevada infrastructure, California IRRAM, Arizona COYL, a recently authorized LNG facility, and planned Paiute expansion. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 75% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including the cost of gas purchases, conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest’s service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.

Liquidity

Liquidity refers to the ability of an enterprise to generate sufficient amounts of cash through its operating activities and external financings 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.


24 \| Southwest Gas Corporation

On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses these mechanisms 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. During 2014, the net under-collected PGA balance increased $69.4 million resulting in an under-collection of $87.6 million at December 31, 2014. See PGA Filings for more information.

In March 2014, the Company amended its $300 million credit facility. The facility was previously scheduled to expire in March 2017 and was extended to March 2019. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the remaining $150 million for working capital purposes. The maximum amount outstanding during 2014 was $165 million ($150 million outstanding on the long-term portion of the credit facility (including $50 million on the commercial paper program), and $15 million outstanding on the short-term portion), which occurred in the fourth quarter. At December 31, 2014, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $5 million was outstanding on the short-term portion. The maximum amount outstanding on the credit facility (including the commercial paper program) during each of the first, second, and third quarters was $10 million, no borrowings, and $50 million, respectively. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, meeting the refund needs of over-collected balances, or temporarily funding capital expenditures. 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.

The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the commercial paper program are calculated at the then current commercial paper rate. At December 31, 2014, $50 million was outstanding on the commercial paper program, which is the maximum amount outstanding during the year.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. At December 31, 2014, $199 million was outstanding on the Centuri secured credit facility.

Credit Ratings

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

In October 2014, Standard & Poor’s Ratings Services (“S&P”) downgraded the Company’s unsecured long-term debt ratings from A- to BBB+ (with a stable outlook). S&P cited the Company’s acquisition of Link-Line, W. S. Nicholls, and Brigadier, which increases the relative size of the higher-risk construction services business segment. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal.

In January 2014, Moody’s Investors Service, Inc. (“Moody’s”) upgraded the Company’s senior unsecured ratings from Baa1 with a stable outlook to A3 with a stable outlook. Moody’s cited the Company’s improved regulatory


		Southwest Gas Corporation \| 25

environment in its service territories. Moody’s debt ratings range from Aaa (highest rating possible) to C (lowest quality, usually in default). Moody’s applies an A rating to obligations which are considered upper-medium grade obligations with low credit risk. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the A to indicate the approximate rank of a company within the range.

In May 2013, Fitch Ratings (“Fitch”) upgraded the Company’s senior unsecured ratings including IDRBs from A- (with a positive outlook) to A (with a stable outlook). Fitch cited the Company’s stronger credit metrics and improved business risk profile. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of A indicates low default risk and a strong ability to pay financial commitments.

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 agency. 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 if debt ratings deteriorated. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2014, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $1.9 billion in additional debt and meet the leverage ratio requirement. The Company has at least $900 million of cushion in equity relating to the minimum net worth requirement.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2014, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $88 million in additional debt and meet the leverage ratio requirement. Centuri has at least $35 million of cushion in equity relating to the minimum fixed charge ratio coverage requirement. Centuri’s revolving credit and term loan facility is secured by underlying assets of the construction services segment.

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 and capital leases, which are described in Note 2 – Utility Plant and Leases of the Notes to Consolidated Financial Statements, and included in the Contractual Obligations Table below.


26 \| Southwest Gas Corporation

Contractual Obligations

The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, capital 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, 2014 (millions of dollars):


	Payments due by period
Contractual Obligations	Total		2015		2016-2017		2018-2019		Thereafter
Operating activities:
Operating leases (Note 2)	$	16	$	6	$	7	$	2	$	1
Gas purchase obligations		190		115		73		1		1
Pipeline capacity/storage		1,087		129		200		114		644
Derivatives (Note 12)		5		5		—		—		—
Other commitments		13		7		5		1		—
Financing activities:
Long-term debt, including current maturities (Note 6)		1,657		19		65		321		1,252
Interest on long-term debt		1,020		65		127		123		705
Capital leases (Note 2)		5		2		3		—		—
Other		9		—		1		1		7

Total	$	4,002	$	348	$	481	$	563	$	2,610

Obligations for Operating Activities: The table above 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 159 million dekatherms. The fixed-price contracts range in price from approximately $4 to $5 per dekatherm. Variable-price contracts reflect minimum contractual obligations, with estimation in pricing.

Southwest has pipeline capacity/storage 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. Included in the pipeline capacity payments shown in the above table, are payments associated with storage that Southwest has contracted for in southern California and Arizona. The terms of these contracts extend through 2024 and 2019, respectively.

Obligations for Financing Activities: Contractual obligations for financing activities primarily related to debt obligations consisting of scheduled principal and interest payments over the life of the debt. Capital leases represent multi-year obligations for equipment. Interest rates in effect at December 31, 2014 on variable rate long-term debt were assumed to remain in effect in the future periods disclosed in the table.

Pension: Estimated funding for pension and other postretirement benefits during calendar year 2015 is $36 million and is not included in the table above.


		Southwest Gas Corporation \| 27

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition and going concern. See Note 1 – Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on the Company’s financial position, results of operations, and disclosures.

Application of Critical Accounting Policies

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

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. It is also permitted to recognize, in its regulatory assets, amounts associated with its various revenue decoupling mechanisms, as long as it continues to meet the requirements of alternative revenue programs permitted under U.S. Generally Accepted Accounting Principles. The Company reviews its regulatory assets to assess their ultimate recoverability within the approved regulatory guidelines. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset (which would be recognized as current-period expense). Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.

Accrued Utility Revenues

Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, margin associated with natural gas service that has been provided but not yet billed is accrued. This accrued utility revenue is estimated each month based primarily on applicable rates, number of customers, rate structure, analyses reflecting significant historical trends, seasonality, and experience. The interplay of these assumptions can impact the variability of the accrued utility revenue estimates. All Company rate jurisdictions have decoupled rate structures, limiting variability due to extreme weather conditions.


28 \| Southwest Gas Corporation

Accounting for Income Taxes

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

Accounting for Pensions and Other Postretirement Benefits

Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Company’s pension obligations and costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans. For example, a change of 0.25% in the discount rate assumption would change the pension plan projected benefit obligation by approximately $36 million and future pension expense by $3.8 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $11.1 million and expense by $2.2 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.9 million (but has no impact on the pension obligation).

At December 31, 2014, the Company lowered the discount rate to 4.25% from a rate of 5.00% at December 31, 2013. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation decreased to 2.75% at December 31, 2014 from 3.25% in the prior year. The asset return assumption of 7.75% to be used for 2015 expense did not change from the rate used in the previous year. A change to a new actuarial mortality table, which takes into account longer life spans for plan participants will significantly increase the expense level for 2015. Pension expense for 2015 is estimated to increase by $10 million compared to 2014 because of the new mortality assumption and lower discount rate. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

Business Combinations

The amount of goodwill initially recognized in a business combination is based on the excess of the purchase price of the acquired company over the fair value of the other assets acquired and liabilities assumed. The determination of these fair values requires management to make significant estimates and assumptions. For example,


		Southwest Gas Corporation \| 29

assumptions with respect to the timing and amount of future revenues and expenses associated with an asset are used to determine its fair value but the actual timing and amount may differ materially resulting in impairment of the asset’s recorded value. In some cases, the Company engages independent third-party valuation firms to assist in determining the fair values of acquired assets and liabilities assumed. Critical estimates in valuing certain intangible assets include but are not limited to future expected cash flows of the acquired business, trademarks, customer relationships, technology obsolescence, and discount rates. In addition, uncertain tax positions and tax-related valuation allowances assumed in connection with a business combination are initially estimated at the acquisition date. These items are reevaluated quarterly, based upon facts and circumstances that existed at the acquisition date with any adjustments to the preliminary estimates being recorded to goodwill, provided that the Company is within the twelve-month measurement period. Subsequent to the measurement period or the final determination of the estimated value of the tax allowance or contingency, whichever comes first, changes to these uncertain tax positions and tax-related valuation allowances will affect the provision for income taxes in the Consolidated Statements of Income, and could have a material impact on the Company’s results of operations and financial position. Goodwill is evaluated for impairment no less frequently than annually. The fair value assigned to the intangible assets acquired and liabilities assumed, and the determination of goodwill associated with the current acquisition, are described in Note 15 – Acquisition of Construction Services Businesses.

Certifications

The Securities and Exchange Commission (“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, 2014 are included as exhibits to the 2014 Annual Report on Form 10-K filed with the SEC.

Forward-Looking Statements

This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote,” “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest savings, the Company’s COLI strategy, annual COLI returns, replacement market and new construction market, bonus depreciation tax deductions, amount and timing for completion of estimated future construction expenditures, including the LNG facility in southern Arizona and the proposed Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, incremental operating margin in 2015, net earnings impacts from gas infrastructure replacement surcharges, operating expense increases in 2015, funding sources of cash requirements, sufficiency of working capital and current credit facility, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, future Centuri operating revenues, operating income, amortization and interest expense, Centuri’s projected financial performance and related market growth potential, Centuri proforma financial results, pension and post-retirement benefits, certain benefits of tax acts, the effect of any rate changes or regulatory proceedings, including the Paiute Pipeline Company general rate case filing, infrastructure replacement mechanisms and the COYL program, statements


30 \| Southwest Gas Corporation

regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, 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, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms or other regulatory assets, 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, 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, results of Centuri bid work, impacts of structural and management changes at Centuri, Centuri construction expenses, differences between actual and originally expected outcomes of Centuri bid or other fixed-price construction agreements, competition, our ability to raise capital in external financings, the true-up of amounts acquired in connection with the recent acquisition, including income taxes and ongoing evaluations in regard to goodwill. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating 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, 2014.

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

Common Stock Price and Dividend Information


	2014				2013				Dividends Declared
	High		Low		High		Low		2014		2013
First quarter	$	55.33	$	51.70	$	48.11	$	42.02	$	0.365	$	0.330
Second quarter		55.69		50.96		51.52		45.11		0.365		0.330
Third quarter		53.34		47.21		50.99		45.70		0.365		0.330
Fourth quarter		64.20		48.23		56.03		48.76		0.365		0.330

									$	1.460	$	1.320

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 17, 2015, there were 14,686 holders of record of common stock, and the market price of the common stock was $56.73.

In reviewing dividend policy, the Board of Directors (“Board”) considers the adequacy and sustainability of earnings and cash flows of the Company and its subsidiaries; the strength of the Company’s capital structure; the sustainability of the dividend through all business cycles; and whether the dividend is within a normal payout range


		Southwest Gas Corporation \| 31

for its respective businesses. The quarterly common stock dividend declared was 29.5 cents per share throughout 2012, 33 cents per share throughout 2013, and 36.5 cents per share throughout 2014. As a result of its ongoing review of dividend policy, in February 2015, the Board increased the quarterly dividend from 36.5 cents to 40.5 cents per share, effective with the June 2015 payment. This marks the ninth consecutive year in which the dividend was increased. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average, while maintaining the Company’s stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Board’s continued review of the Company’s dividend rate in the context of the performance of the Company’s two operating segments and their future growth prospects.


32 \| Southwest Gas Corporation

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)


December 31,	2014			2013
ASSETS
Utility plant:
Gas plant	$	5,556,599		$	5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413

Net utility plant (Note 2)		3,658,383			3,486,108

Other property and investments (Note 1)		326,743			260,871

Restricted cash (Note 1)		821			—

Current assets:
Cash and cash equivalents		39,566			41,077
Accounts receivable, net of allowances (Note 3)		281,824			219,469
Accrued utility revenue		73,900			72,700
Income taxes receivable, net		21,853			3,790
Deferred income taxes, net (Note 11)		2,109			31,130
Deferred purchased gas costs (Note 4)		87,556			18,217
Prepaids and other current assets (Notes 1, 4, and 12)		99,975			108,289

Total current assets		606,783			494,672

Noncurrent assets:
Goodwill (Notes 1 and 15)		143,160			17,810
Deferred charges and other assets (Notes 2, 4, and 12)		478,625			305,713

Total noncurrent assets		621,785			323,523

Total assets	$	5,214,515		$	4,565,174


34 \| Southwest Gas Corporation

CONSOLIDATED BALANCE SHEETS – Continued


December 31,	2014			2013
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized – 60,000,000 shares; issued and outstanding – 46,523,184 and 46,356,125 shares) (Note 10)	$	48,153		$	47,986
Additional paid-in capital		851,381			840,521
Accumulated other comprehensive income (loss), net (Note 5)		(50,175	)		(41,698	)
Retained earnings		639,164			567,714

Total Southwest Gas Corporation equity		1,488,523			1,414,523
Noncontrolling interest		(2,257	)		(2,128	)

Total equity		1,486,266			1,412,395
Redeemable noncontrolling interest (Note 16)		20,042			—
Long-term debt, less current maturities (Note 6)		1,637,592			1,381,327

Total capitalization		3,143,900			2,793,722

Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)		19,192			11,105
Short-term debt (Note 7)		5,000			—
Accounts payable		167,988			183,511
Customer deposits		71,546			73,367
Accrued general taxes		44,339			39,681
Accrued interest		16,468			17,920
Other current liabilities (Notes 2, 4, and 12)		145,584			108,580

Total current liabilities		470,117			434,164

Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 11)		723,688			674,411
Taxes payable		—			284
Accumulated removal costs (Note 4)		304,000			279,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 9, and 12)		572,810			383,593

Total deferred income taxes and other credits		1,600,498			1,337,288

Total capitalization and liabilities	$	5,214,515		$	4,565,174

The accompanying notes are an integral part of these statements.


35 \| Southwest Gas Corporation

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)


Year Ended December 31,	2014			2013			2012
Operating revenues:
Gas operating revenues	$	1,382,087		$	1,300,154		$	1,321,728
Construction revenues		739,620			650,628			606,050

Total operating revenues		2,121,707			1,950,782			1,927,778

Operating expenses:
Net cost of gas sold		505,356			436,001			479,602
Operations and maintenance		383,732			384,914			369,979
Depreciation and amortization		253,027			236,817			223,422
Taxes other than income taxes		47,252			45,551			41,728
Construction expenses		647,857			573,284			541,523

Total operating expenses		1,837,224			1,676,567			1,656,254

Operating income		284,483			274,215			271,524

Other income and (expenses):
Net interest deductions (Notes 6 and 7)		(72,069	)		(63,700	)		(68,020	)
Other income (deductions)		7,107			12,300			4,411

Total other income and (expenses)		(64,962	)		(51,400	)		(63,609	)

Income before income taxes		219,521			222,815			207,915
Income tax expense (Note 11)		78,373			77,942			75,276

Net income		141,148			144,873			132,639
Net income (loss) attributable to noncontrolling interests		22			(447	)		(692	)

Net income attributable to Southwest Gas Corporation	$	141,126		$	145,320		$	133,331

Basic earnings per share (Notes 1 and 14)	$	3.04		$	3.14		$	2.89

Diluted earnings per share (Notes 1 and 14)	$	3.01		$	3.11		$	2.86

Average number of common shares outstanding		46,494			46,318			46,115
Average shares outstanding (assuming dilution)		46,944			46,758			46,555

The accompanying notes are an integral part of these statements.


36 \| Southwest Gas Corporation

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)


Year Ended December 31,	2014			2013			2012
Net Income	$	141,148		$	144,873		$	132,639

Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 9):
Net actuarial gain (loss)		(107,661	)		62,214			(46,409	)
Amortization of prior service cost		220			220			—
Amortization of transition obligation		—			—			538
Amortization of net actuarial loss		14,667			21,190			15,870
Prior service cost		(4,130	)		—			(1,502	)
Regulatory adjustment		86,991			(76,651	)		26,518

Net defined benefit pension plans		(9,913	)		6,973			(4,985	)

Forward-starting interest rate swaps:
Unrealized/realized gain (loss) (Notes 5 and 12)		—			—			1,834
Amounts reclassified into net income (Notes 5 and 12)		2,073			2,074			1,737

Net forward-starting interest rate swaps		2,073			2,074			3,571

Foreign currency translation adjustments		(659	)		—			—

Total other comprehensive income (loss), net of tax		(8,499	)		9,047			(1,414	)

Comprehensive income		132,649			153,920			131,225
Comprehensive income (loss) attributable to noncontrolling interests		—			(447	)		(692	)

Comprehensive income attributable to Southwest Gas Corporation	$	132,649		$	154,367		$	131,917

The accompanying notes are an integral part of these statements.


		Southwest Gas Corporation \| 37

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)


Year Ended December 31,	2014			2013			2012
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	141,148		$	144,873		$	132,639
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		253,027			236,817			223,422
Deferred income taxes		64,309			68,639			66,280
Changes in current assets and liabilities:
Accounts receivable, net of allowances		(3,683	)		(22,556	)		12,333
Accrued utility revenue		(1,200	)		(700	)		(1,700	)
Deferred purchased gas costs		(69,339	)		(111,143	)		22,823
Accounts payable		(41,499	)		27,668			(25,998	)
Accrued taxes		(13,573	)		925			113
Other current assets and liabilities		23,379			5,084			(18,948	)
Gains on sale		(6,171	)		(4,112	)		(8,040	)
Changes in undistributed stock compensation		7,973			6,958			5,137
AFUDC		(1,995	)		(2,274	)		(1,943	)
Changes in other assets and deferred charges		(21,732	)		(21,719	)		(15,367	)
Changes in other liabilities and deferred credits		15,779			17,749			(4,427	)

Net cash provided by operating activities	$	346,423		$	346,209		$	386,324


38 \| Southwest Gas Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued


Year Ended December 31,	2014			2013			2012
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions		(396,898	)		(364,276	)		(395,712	)
Acquisition of businesses, net of cash acquired		(190,497	)		—			—
Restricted cash		1,233			—			12,785
Changes in customer advances		20,363			7,773			(3,025	)
Miscellaneous inflows		11,611			8,465			13,963
Miscellaneous outflows		(1,400	)		—			(2,004	)

Net cash used in investing activities		(555,588	)		(348,038	)		(373,993	)

CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net		405			1,635			1,581
Dividends paid		(66,275	)		(59,535	)		(53,040	)
Interest rate swap settlement		—			—			(21,754	)
Issuance of long-term debt, net		269,228			311,290			489,518
Retirement of long-term debt		(139,155	)		(137,013	)		(427,043	)
Change in credit facility and commercial paper		140,000			(101,000	)		2,000
Change in short-term debt		5,000			1,999			—
Principal payments on capital lease obligations		(434	)		—			—
Other		(1,257	)		—			—

Net cash provided by (used in) financing activities		207,512			17,376			(8,738	)

Effects of currency translation on cash and cash equivalents		142			—			—

Change in cash and cash equivalents		(1,511	)		15,547			3,593
Cash and cash equivalents at beginning of period		41,077			25,530			21,937

Cash and cash equivalents at end of period	$	39,566		$	41,077		$	25,530

Supplemental information:
Interest paid, net of amounts capitalized	$	65,552		$	58,730		$	87,439

Income taxes paid (received)	$	24,247		$	6,850		$	2,843

The accompanying notes are an integral part of these statements.


39 \| Southwest Gas Corporation

SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

AND REDEEMABLE NONCONTROLLING INTEREST

(In thousands, except per share amounts)


	Southwest Gas Corporation Equity
	Common Stock				Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
	Shares		Amount		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
DECEMBER 31, 2011		45,956	$	47,586	$	821,640	$	(49,331	)	$	406,125		$	(989	)	$	1,225,031		$	—
Common stock issuances		192		192		7,137											7,329
Net income (loss)											133,331			(692	)		132,639
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)								(4,985	)								(4,985	)
FSIRS realized and unrealized gain, net of tax (Notes 5 and 12)								1,834									1,834
Amounts reclassified to net income, net of tax (Notes 5 and 12)								1,737									1,737
Dividends declared
Common: $1.18 per share											(55,087	)					(55,087	)

DECEMBER 31, 2012		46,148	$	47,778	$	828,777	$	(50,745	)	$	484,369		$	(1,681	)	$	1,308,498		$	—
Common stock issuances		208		208		11,744											11,952
Net income (loss)											145,320			(447	)		144,873
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)								6,973									6,973
Amounts reclassified to net income, net of tax (Notes 5 and 12)								2,074									2,074
Dividends declared
Common: $1.32 per share											(61,975	)					(61,975	)


40 \| Southwest Gas Corporation


	Southwest Gas Corporation Equity
	Common Stock					Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
	Shares			Amount		Additional Paid-in Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non- controlling Interest			Total			Redeemable Noncontrolling Interest (Temporary Equity)
DECEMBER 31, 2013		46,356		$	47,986	$	840,521	$	(41,698	)	$	567,714		$	(2,128	)	$	1,412,395		$	—
Common stock issuances		167			167		10,860											11,027
Redeemable noncontrolling interest attributable to acquisition																					18,952
Net income (loss)												141,126			(129	)		140,997			151
Fair value accretion (Note 16)												(961	)					(961	)		961
Foreign currency exchange translation adj.									(637	)								(637	)		(22	)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 9)									(9,913	)								(9,913	)
Amounts reclassified to net income, net of tax (Notes 5 and 12)									2,073									2,073
Dividends declared Common: $1.46 per share												(68,715	)					(68,715	)

DECEMBER 31, 2014		46,523	*	$	48,153	$	851,381	$	(50,175	)	$	639,164		$	(2,257	)	$	1,486,266		$	20,042

At December 31, 2014, 2.7 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 36,000 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.


		Southwest Gas Corporation \| 41

Notes to Consolidated Financial Statements

Note 1 – Summary of Significant Accounting Policies

Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Centuri Construction Group Inc. (“Centuri” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and industrial construction solutions. Centuri operations are generally conducted under the business names of NPL Construction Co., Link-Line, W.S. Nicholls, and Brigadier.

Basis of Presentation. The Company follows generally accepted accounting principles in the United States (“U.S. GAAP”) in accounting for all of its businesses. Unless specified otherwise, all amounts are in U.S. dollars. Accounting for the natural gas utility operations conforms with U.S. GAAP as applied to regulated companies and as prescribed by federal agencies and 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 those accounted for using the equity method as discussed further below). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and Centuri in accordance with accounting treatment for rate-regulated entities.

In October 2014, the Company, through its subsidiaries, led principally by NPL Construction Co., completed the acquisition of three privately held, affiliated construction businesses for approximately US$221 million. Additional consideration will be paid or accrued through the true-up period. The acquisition extends the construction services operations into Canada and provides additional opportunities for market expansion. Funding for the acquisition was primarily provided by a new $300 million secured revolving credit and term loan facility described in Note 6 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”) that provides construction and maintenance services for the Canadian utility industry, with operations primarily in Ontario, Canada; (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls, which together provide industrial construction solutions, fabrication, and civil services to the oil and gas, pulp and paper, and automotive industries, as well as government and private sector customers in British Columbia and Ontario, Canada (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania as a specialty midstream pipeline contractor (“Brigadier”).


42 \| Southwest Gas Corporation

In October 2014, upon completion of the acquisition, the Company restructured its ownership of NPL Construction Co. and Carson Water Company (an inactive wholly owned subsidiary) creating a holding company, a direct subsidiary of Carson Water Company. In January 2015, the holding company was renamed Centuri. In addition, two direct subsidiaries exist under Centuri: Vistus Construction Group Inc. (“Vistus”, U.S. operations) and Lynxus Construction Group Inc. (“Lynxus”, Canadian operations). Three subsidiaries exist under Vistus: NPL Construction Co., Southwest Administrators, and Brigadier Pipelines Inc. Link-Line and W.S. Nicholls are subsidiaries of Lynxus.

Lynxus, including its subsidiaries of Link-Line, W.S. Nicholls, WSN Construction and WSN Industries will be consolidated under the voting interest method of accounting. Brigadier will be consolidated under the voting interest method.

Centuri, through its subsidiaries, holds a 65% interest in a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. Centuri consolidates the entity (IntelliChoice Energy, LLC) as a majority-owned subsidiary. Centuri, through its subsidiaries, holds a 50% interest in W.S. Nicholls Western Construction LTD. (“Western”), a Canadian construction services company that is a variable interest entity. Centuri determined that it is not the primary beneficiary of the entity due to a shared-power structure; therefore, Centuri does not consolidate the entity and has recorded its investment, and results related thereto, using the equity method. The Company’s investment in Western is not significant in relation to its total assets included in the Consolidated Balance Sheets. At December 31, 2014, Centuri’s investment in Western is $14.7 million and its maximum exposure to loss as a result of its involvement with the entity is estimated at $20.8 million, including obligations under a construction bonding arrangement under which Centuri has guaranteed the performance on certain projects of Western. The estimated maximum exposure to loss represents the maximum loss that would be absorbed by Centuri in the event that all of the assets of Western are deemed worthless.

Centuri, through its subsidiaries, also has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture. Any future changes to the values of these entities will be recorded by Centuri using the equity method. The equity method investment in Western is included in Other Property and Investments in the 2014 Consolidated Balance Sheet.

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.

Other Property and Investments. Other property and investments includes (millions of dollars):


	2014			2013
Centuri property, equipment, and intangibles	$	405		$	320
Centuri accumulated provision for depreciation and amortization		(187	)		(163	)
Net cash surrender value of COLI policies		99			93
Other property		10			11

Total	$	327		$	261


		Southwest Gas Corporation \| 43

Restricted Cash. A construction bond that was required to be in place during the completion of one of Centuri’s construction projects is classified in the Consolidated Balance Sheets as restricted cash. The project is expected to be completed within one year. The restricted cash was acquired in conjunction with the acquisition of construction services businesses. See Note 15 – Acquisition of Construction Services Businesses for more information.

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.

Prepaids and other current assets. Prepaids and other current assets includes gas pipe inventory and operating supplies of $23 million in 2014 and $21 million in 2013.

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. As of December 31, 2014, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.

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. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents at December 31, 2014 also includes two money market fund investments totaling approximately $250,000 which fall within Level 2 (significant other observable inputs) of the fair value hierarchy, due to the asset valuation methods used by money market funds.

During 2013 and 2014, approximately $9.3 million and $8.1 million, respectively, of customer advances, upon contract expiration, were applied as contributions toward utility construction activity and represent a non-cash investing activity. Additionally, in conjunction with the acquisition, the Company acquired several capital leases. During 2014 and after the acquisition date, an additional capital lease obligation was entered into and represents a non-cash financing inflow activity of $204,000. The associated capital lease asset represents a non-cash investing outflow activity of $204,000. In association with the acquisition, cash flows from investing activities includes an $18.9 million non-cash investing outflow due to equity to the noncontrolling interest in a subsidiary to acquire businesses. In addition, a non-cash investing outflow activity of $10.8 million related to an increase in an acquisition consideration payable is included.

Inventories. Inventories are carried at weighted average cost and include natural gas stored underground, liquefied natural gas storage and materials and supplies.


44 \| Southwest Gas Corporation

Goodwill. The construction services segment includes Goodwill of $133 million in 2014 ($125 million related to the recent acquisition, which is net of approximately $5 million due to foreign currency exchange translation adjustments between the acquisition date and the end of the year). The December 31, 2014 and 2013 Goodwill amounts shown in the Consolidated Balance Sheets include approximately $8 million of Goodwill recognized when Southwest first acquired NPL Construction Co. and is associated with the construction services segment. Goodwill of $10 million in both 2014 and 2013 is associated with the natural gas operations segment. Goodwill is assessed for impairment annually, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill. No impairment was recorded in 2014.

Intangible Assets. Intangible assets are amortized using the straight-line method to reflect the pattern of economic benefits consumed over the estimated periods benefited. The recoverability of intangible assets is evaluated when events or circumstances indicate that a revision of estimated useful lives is warranted or that an intangible asset may be impaired. Intangible assets have finite lives and are described in Notes 2 and 15.

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


	December 31, 2014		December 31, 2013
Accumulated removal costs	$	304,000	$	279,000

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

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

Construction Revenues. The majority of Centuri contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in a few 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 on fixed-price contracts is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of 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. In connection with significant changes in estimated costs to complete a


		Southwest Gas Corporation \| 45

large fixed-price contract, construction services results for 2012 reflected a pretax loss of $15 million ($0.20 per share, after tax). The estimated cost changes that resulted in the loss recognized included reductions in projected productivity and higher costs of restoration work. During 2013, profitability on this contract was minimal and as of December 31, 2013, this fixed-price contract was substantially complete. Some unit-price contracts contain caps that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.

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, acquisition and acquisition-related costs, and office-related fixed costs of Centuri.

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

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

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

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


	2014		2013		2012
(In thousands)
AFUDC:
Debt portion	$	1,228	$	1,260	$	1,129
Equity portion		1,995		2,274		1,943

AFUDC capitalized as part of utility plant	$	3,223	$	3,534	$	3,072


46 \| Southwest Gas Corporation

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):


	2014			2013			2012
Change in COLI policies	$	5,300		$	12,400		$	6,600
Interest income		2,602			461			924
Pipe replacement costs		—			(132	)		(2,680	)
Foreign currency transaction gain (loss)		(178	)		—			—
Miscellaneous income and (expense)		(617	)		(429	)		(433	)

Total other income (deductions)	$	7,107		$	12,300		$	4,411

Included in the table above is the change in cash surrender values of company-owned life insurance (“COLI”) policies (including net death benefits recognized). Changes in cash surrender values are directly influenced by the investment portfolio underlying the insurance 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, changes in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work. The replacement program work subject to non-recoverability was substantially completed in 2012.

Foreign Currency Translation. Foreign currency-denominated assets and liabilities of consolidated subsidiaries are translated into U.S. dollars at exchange rates existing at the respective balance sheet dates. Translation adjustments resulting from fluctuations in exchange rates are recorded as a separate component of accumulated other comprehensive income within stockholders’ equity. Results of operations of foreign subsidiaries are translated using the monthly weighted-average exchange rates during the respective periods. Gains and losses resulting from foreign currency transactions, the amounts of which are not material, are included in other income (expense) within net income. Gains and losses resulting from intercompany foreign currency transactions that are of a long-term investment nature are reported in other comprehensive income, if applicable.

Earnings Per Share. In connection with the ownership structure of Centuri and its subsidiary entities, a redeemable noncontrolling interest exists in Lynxus. The Company concluded that this noncontrolling interest meets the definition of a participating security in connection with Accounting Standards Codification (“ASC”) Topic 260, as a result of dividend participation rights of the noncontrolling interest that are different than the underlying proportional ownership interest. Related provisions of ASC 260 would require consideration of the participation right in computing earnings per share. However, as earnings are already attributed to the noncontrolling interest equivalent to the participation right, taking an additional adjustment in computing basic earnings per share would duplicate the economic impact associated with the participating security. Furthermore, as net income attributable to common shareholders of Southwest Gas Corporation has already been adjusted for the attribution of income to the noncontrolling interest, the Company concluded that a diluted earnings per share calculation, assuming exchange of the ownership shares of the noncontrolling interest in Lynxus, for ownership shares in Centuri, would not produce a different result than that which results from computing basic earnings per share. The noncontrolling interest is also redeemable for fair value at specified dates in the future. No adjustment will be made to the


		Southwest Gas Corporation \| 47

Company’s income attributable to common shareholders, in computing earnings per share, to reflect changes in the redemption price, as redemption at fair value is not considered an economic distribution different from other common stockholders. See also Note 15 – Acquisition of Construction Services Businesses and Note 16 – Construction Services Noncontrolling Interests.

Basic earnings per share (“EPS”) are calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during the period. Diluted EPS includes 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 denominator used in the Basic and Diluted EPS calculations is shown in the following table.


	2014		2013		2012
(In thousands)
Average basic shares		46,494		46,318		46,115
Effect of dilutive securities:
Stock options		17		26		42
Performance shares		215		231		254
Restricted stock units		218		183		144

Average diluted shares		46,944		46,758		46,555

Recently Issued Accounting Standards Updates. In May 2014, the Financial Accounting Standards Board (“FASB”) issued the update “Revenue from Contracts with Customers (Topic 606).” The update replaces much of the current guidance regarding revenue recognition including most industry-specific guidance. The core principle of the update is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity will be required to identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. In addition to the new revenue recognition requirements, entities will be required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Entities may choose between two retrospective transition methods when applying the update. The Company plans to adopt this update, as required, on January 1, 2017 for interim and annual reporting periods. Early adoption is not permitted. The Company is evaluating what impact this standard might have on its consolidated financial statements and disclosures. Additionally, the power and utilities industry as a whole assembled a task force for purposes of considering unique circumstances that relate to our industry and for communicating those industry considerations to the American Institute of Certified Public Accountants. Those undertakings are ongoing.

In August 2014, the FASB issued the update “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which requires management to asses a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Under the update, disclosures are required when conditions give rise to substantial doubt about a company’s ability to continue as a going concern within one year from the financial statement issuance date. The update is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. This update is not expected to have a material impact on the Company’s disclosures.


48 \| Southwest Gas Corporation

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

Reclassifications. Certain reclassifications were made to the prior year’s financial information included in the Consolidated Balance Sheets (goodwill is identified separately from Deferred charges and other assets) in order to present the prior-year information on a basis comparable with the current year’s presentation, with no impact to total assets overall.

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2014 and 2013 was as follows (thousands of dollars):


December 31,	2014			2013
Gas plant:
Storage	$	22,531		$	21,282
Transmission		312,300			313,306
Distribution		4,655,640			4,410,598
General		356,072			324,490
Software and software-related intangibles		196,035			168,815
Other		14,021			13,978

		5,556,599			5,252,469
Less: accumulated depreciation		(1,973,098	)		(1,868,504	)
Acquisition adjustments, net		550			730
Construction work in progress		74,332			101,413

Net utility plant	$	3,658,383		$	3,486,108

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


	2014		2013		2012
Depreciation and amortization expense	$	194,360	$	185,283	$	182,612

Included in the figures above is amortization of intangibles of $11.7 million in 2014, $10.3 million in 2013, and $9.3 million in 2012.

Operating Leases and Rentals. In July 2014, the Company purchased for $16.5 million a portion of its corporate headquarters office complex in Las Vegas that it had previously leased. With the completion of the purchase, the lease terminated.


		Southwest Gas Corporation \| 49

The Company leases certain office and construction equipment. The majority of these leases are short-term and accounted for as operating leases. For the gas segment, these leases are also treated as operating leases for regulatory purposes. Centuri has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest’s rental payments and Centuri’s lease payments that are included in operating expenses (in thousands):


	2014		2013		2012
Southwest Gas	$	5,330	$	8,308	$	7,762
Centuri		30,012		27,118		24,054

Consolidated rental payments/lease expense	$	35,342	$	35,426	$	31,816

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, 2014 (thousands of dollars):


Year Ending December 31,
2015	$	5,957
2016		4,236
2017		2,532
2018		1,582
2019		912
Thereafter		831

Total minimum lease payments	$	16,050

Capital Leases. Centuri leases certain construction equipment. These leases are considered capital leases. The amount of capital leases of equipment as of December 31, 2014 and 2013 is as follows (thousands of dollars):


December 31,	2014			2013
Capital leases of equipment	$	5,763		$	—
Less: accumulated amortization		(287	)		—

Net capital leases	$	5,476		$	—

The following is a schedule of future minimum lease payments for non-cancelable capital leases (with initial or remaining terms in excess of one year) as of December 31, 2014 (thousands of dollars):


Year Ending December 31,
2015	$	1,690
2016		1,632
2017		813
2018		591
2019		—
Thereafter		—

		4,726
Less: amount representing interest		(497	)

Total minimum lease payments	$	4,229


50 \| Southwest Gas Corporation

Note 3 – Receivables and Related Allowances

Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. The table below contains information about the gas utility customer accounts receivable balance (net of allowance) at December 31, 2014, and the percentage of customers in each of the three states.


	December 31, 2014
Gas utility customer accounts receivable balance (in thousands)	$	136,148



	December 31, 2014
Percent of customers by state
Arizona		53	%
Nevada		37	%
California		10	%

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


	Allowance for Uncollectibles
Balance, December 31, 2011	$	3,182
Additions charged to expense		2,471
Accounts written off, less recoveries		(3,149	)

Balance, December 31, 2012		2,504
Additions charged to expense		3,583
Accounts written off, less recoveries		(4,362	)

Balance, December 31, 2013		1,725
Additions charged to expense		4,146
Accounts written off, less recoveries		(3,616	)

Balance, December 31, 2014	$	2,255

At December 31, 2014, the construction services segment (Centuri) had $142 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs have been insignificant and are not reflected in the table above.


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Note 4 – Regulatory Assets and Liabilities

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

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


December 31,	2014			2013
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)	$	390,293		$	249,985
Unrealized net loss on non-trading derivatives (Swaps) (2)		5,425			160
Deferred purchased gas costs (3)		87,556			18,217
Accrued purchased gas costs (4)		2,600			31,500
Unamortized premium on reacquired debt (5)		20,478			19,614
Other (6)		72,132			48,945

		578,484			368,421
Regulatory liabilities:
Accumulated removal costs		(304,000	)		(279,000	)
Unrealized net gain on non-trading derivatives (Swaps) (2)		—			(981	)
Deferred gain on southern Nevada division operations facility (7)		(115	)		(253	)
Unamortized gain on reacquired debt (8)		(10,862	)		(11,398	)
Other (9)		(34,233	)		(26,482	)

Net regulatory assets	$	229,274		$	50,307

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

(2)

The following table details the regulatory assets/(liabilities) offsetting the derivatives (Swaps) at fair value in the balance sheets (thousands of dollars). The actual amounts, when realized at settlement, become a component of purchased gas costs under the Company’s purchased gas adjustment (“PGA”) mechanisms. (See Note 12).


Instrument	Balance Sheet Location	2014		2013
Swaps	Deferred charges and other assets	$	363	$	4
Swaps	Prepaids and other current assets		5,062		156
Swaps	Other current liabilities		—		(801	)
Swaps	Other deferred credits		—		(180	)

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

(4)	Included in Prepaids and other current assets on the Consolidated Balance Sheets. Balance recovered or refunded on an ongoing basis.


52 \| Southwest Gas Corporation

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

(6)

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

(7)	Balance was originally being amortized over a four-year period beginning in the fourth quarter of 2009. As a result of the most recent Nevada general rate case, the amortization period was extended through October 2015.

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

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


		Southwest Gas Corporation \| 53

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

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

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


	2014									2013									2012
	Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount			Before- Tax Amount			Tax (Expense) or Benefit (1)			Net-of- Tax Amount
(Thousands of dollars)
Defined benefit pension plans:
Net actuarial gain/(loss)	$	(173,646	)	$	65,985		$	(107,661	)	$	100,345		$	(38,131	)	$	62,214		$	(74,853	)	$	28,444		$	(46,409	)
Amortization of prior service cost		355			(135	)		220			355			(135	)		220			—			—			—
Amortization of transition obligation		—			—			—			—			—			—			867			(329	)		538
Amortization of net actuarial (gain)/loss		23,656			(8,989	)		14,667			34,177			(12,987	)		21,190			25,597			(9,727	)		15,870
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			(2,423	)		921			(1,502	)
Regulatory adjustment		140,308			(53,317	)		86,991			(123,630	)		46,979			(76,651	)		42,771			(16,253	)		26,518

Pension plans other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		11,247			(4,274	)		6,973			(8,041	)		3,056			(4,985	)
FSIRS (designated hedging activities):
Unrealized/realized gain (loss)		—			—			—			—			—			—			2,959			(1,125	)		1,834
Amounts reclassified into net income		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			2,801			(1,064	)		1,737

FSIRS other comprehensive income (loss)		3,345			(1,272	)		2,073			3,345			(1,271	)		2,074			5,760			(2,189	)		3,571
Foreign currency translation adjustments:
Translation adjustments		(659	)		—			(659	)		—			—			—			—			—			—

Foreign currency other comprehensive income (loss)		(659	)		—			(659	)		—			—			—			—			—			—

Total other comprehensive income (loss)	$	(13,302	)	$	4,803		$	(8,499	)	$	14,592		$	(5,545	)	$	9,047		$	(2,281	)	$	867		$	(1,414	)

(1)

Tax amounts are calculated using a 38% rate. The Company has elected to indefinitely reinvest the earnings of Centuri’s Canadian subsidiaries in Canada, thus preventing deferred taxes on such earnings. As a result of this assertion, the Company is not recognizing any tax effect or presenting a tax expense or benefit for the currency translation adjustment amount reported in Other Comprehensive Income, as repatriation of earnings is not anticipated.


54 \| Southwest Gas Corporation

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


Retirement plan net actuarial loss	$	33,000
SERP net actuarial loss		1,300
PBOP net actuarial loss		300
PBOP prior service cost		1,300

Approximately $2.1 million of previously realized losses (net of tax) related to the forward-starting interest rate swaps (“FSIRS”), included in AOCI at December 31, 2014, will be reclassified into interest expense within the next twelve months as the related interest payments on long-term debt occur.

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

AOCI – Rollforward

(Thousands of dollars)


	Defined Benefit Plans (Note 9)									FSIRS (Note 12)									Foreign Currency Items
	Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit			After- Tax			Before- Tax			Tax (Expense) Benefit		After- Tax			AOCI
Beginning Balance AOCI December 31, 2013	$	(41,223	)	$	15,665		$	(25,558	)	$	(26,033	)	$	9,893		$	(16,140	)	$	—		$	—	$	—		$	(41,698	)

Net actuarial gain/(loss)		(173,646	)		65,985			(107,661	)		—			—			—			—			—		—			(107,661	)
Translation adjustments		—			—			—			—			—			—			(659	)		—		(659	)		(659	)

Other comprehensive income before reclassi fications		(173,646	)		65,985			(107,661	)		—			—			—			(659	)		—		(659	)		(108,320	)
FSIRS amounts reclassified from AOCI (1)		—			—			—			3,345			(1,272	)		2,073			—			—		—			2,073
Amortization of prior service cost (2)		355			(135	)		220			—			—			—			—			—		—			220
Amortization of net actuarial loss (2)		23,656			(8,989	)		14,667			—			—			—			—			—		—			14,667
Prior service cost		(6,661	)		2,531			(4,130	)		—			—			—			—			—		—			(4,130	)
Regulatory adjustment (3)		140,308			(53,317	)		86,991			—			—			—			—			—		—			86,991

Net current period other comprehensive income (loss)		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(659	)		—		(659	)		(8,499	)
Less: Translation adjustment attributable to redeemable noncontrolling interest		—			—			—			—			—			—			(22	)		—		(22	)		(22	)

Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation		(15,988	)		6,075			(9,913	)		3,345			(1,272	)		2,073			(637	)		—		(637	)		(8,477	)

Ending Balance AOCI December 31, 2014	$	(57,211	)	$	21,740		$	(35,471	)	$	(22,688	)	$	8,621		$	(14,067	)	$	(637	)	$	—	$	(637	)	$	(50,175	)


		Southwest Gas Corporation \| 55

(1)	The FSIRS reclassification amounts are included in the Net interest deductions line item on the Consolidated Statements of Income.

(2)	These AOCI components are included in the computation of net periodic benefit cost (see Note 9 – Pension and Other Postretirement Benefits for additional details).

(3)	The regulatory adjustment represents the portion of the activity above that is expected to be recovered through rates in the future (the related regulatory asset is included in the Deferred charges and other assets line item on the Consolidated Balance Sheets).

The following table represents amounts (before income tax impacts) included in Accumulated other comprehensive income (in the table above), that have not yet been recognized in net periodic benefit cost as of December 31, 2014 and 2013:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)


	2014			2013
Net actuarial (loss) gain	$	(439,131	)	$	(289,141	)
Prior service cost		(8,373	)		(2,067	)
Less: amount recognized in regulatory assets		390,293			249,985

Recognized in AOCI	$	(57,211	)	$	(41,223	)

See Note 9 – Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 12 – Derivatives and Fair Value Measurements for more information on the FSIRS.

Note 6 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2014 and December 31, 2013 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, due to the Company’s ability to access similar debt arrangements at measurement dates with comparable terms, including variable rates. The fair values of debentures, senior notes, and fixed-rate IDRBs were determined utilizing a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves, credit ratings and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. The market values of debentures and fixed-rate IDRBs are categorized as Level 2 (observable market inputs based on market prices of similar securities). The Centuri secured revolving credit and term loan facility and Centuri other debt obligations (not actively traded) are categorized as Level 3, based on significant unobservable inputs to their fair values. Since Centuri’s debt is not publicly traded, fair values for the secured revolving credit and term loan facility and other debt obligations were based on a conventional discounted cash flow methodology and utilizes current market pricing yield curves, across Centuri’s debt maturity spectrum, of other industrial bonds with an assumed credit rating comparable to the Company’s.


56 \| Southwest Gas Corporation


December 31,	2014					2013
	Carrying Amount			Market Value		Carrying Amount			Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020	$	125,000		$	133,403	$	125,000		$	130,953
Notes, 6.1%, due 2041		125,000			157,290		125,000			141,873
Notes, 3.875%, due 2022		250,000			262,030		250,000			252,485
Notes, 4.875%, due 2043		250,000			280,903		250,000			257,280
8% Series, due 2026		75,000			102,296		75,000			96,263
Medium-term notes, 7.59% series, due 2017		25,000			27,573		25,000			28,741
Medium-term notes, 7.78% series, due 2022		25,000			31,144		25,000			30,586
Medium-term notes, 7.92% series, due 2027		25,000			33,695		25,000			31,497
Medium-term notes, 6.76% series, due 2027		7,500			9,156		7,500			8,468
Unamortized discount		(5,223	)				(5,560	)

		902,277					901,940

Revolving credit facility and commercial paper		150,000			150,000		10,000			10,000

Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028		50,000			50,000		50,000			50,000
2003 Series A, due 2038		50,000			50,000		50,000			50,000
2008 Series A, due 2038		50,000			50,000		50,000			50,000
2009 Series A, due 2039		50,000			50,000		50,000			50,000
Fixed-rate bonds:
5.25% 2003 Series D, due 2038		20,000			20,277		20,000			20,150
5.25% 2004 Series A, due 2034		—			—		65,000			64,522
5.00% 2004 Series B, due 2033		31,200			31,223		31,200			30,284
4.85% 2005 Series A, due 2035		100,000			100,071		100,000			95,192
4.75% 2006 Series A, due 2036		24,855			25,399		24,855			22,974
Unamortized discount		(1,943	)				(2,776	)

		374,112					438,279

Centuri secured revolving credit and term loan facility		199,267			200,341		—			—
Centuri other debt obligations		31,128			31,127		42,213			42,119

		1,656,784					1,392,432
Less: current maturities		(19,192	)				(11,105	)

Long-term debt, less current maturities	$	1,637,592				$	1,381,327

In March 2014, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2017, but was extended to March 2019. Southwest will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. In addition to extending the credit facility, among other amendments, the applicable margins and unused commitment fees were reduced and the Pricing Level definitions were modified. Interest rates for the credit facility are calculated at either the


		Southwest Gas Corporation \| 57

London Interbank Offered Rate (“LIBOR”) or an “alternate base rate,” plus in each case an applicable margin that is determined based on the Company’s senior unsecured debt rating. At December 31, 2014, the applicable margin is 1% for loans bearing interest with reference to LIBOR and 0% for loans bearing interest with reference to the alternative base rate. At December 31, 2014, $150 million was outstanding on the long-term portion of the credit facility, including $50 million in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 1.21% at December 31, 2014. Borrowings under the credit facility ranged from none during the first and second quarters of 2014 to a high of $165 million during November and December 2014. With regard to the short-term portion of the credit facility, there was $5 million outstanding at December 31, 2014 and no borrowings outstanding at December 31, 2013. (See Note 7 – Short-Term Debt).

Also in March 2014, the Company amended the note purchase agreement associated with its 6.1% $125 million notes (“Notes”). The amendment modifies the Permitted Lien category, thereby permitting liens securing indebtedness not to exceed 10% of total capitalization as of the end of any quarter. This provision in the agreement prohibits liens on any property securing other indebtedness under bank facilities unless the Notes are secured in a similar manner. The provision was amended to clarify that it only applies to bank facilities of Southwest Gas Corporation.

The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the program are calculated at the then current commercial paper rate. At December 31, 2014, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.65% at December 31, 2014.

In October 2014, construction services subsidiaries of the Company entered into a $300 million secured revolving credit and term loan facility. The facility is scheduled to expire in October 2019 and replaces the previous $75 million credit facility, which was scheduled to expire in June 2015. The facility is secured by substantially all of Centuri’s assets except ones explicitly excluded under the terms of the agreement including owned real estate and certain certificated vehicles. Centuri assets securing the facility at December 31, 2014 totaled $477 million.

Interest rates for Centuri’s $300 million secured facility are calculated at the LIBOR, the Canadian Dealer Offered Rate (“CDOR”), or an alternate base rate or Canadian base rate, plus in each case an applicable margin that is determined based on Centuri’s consolidated leverage ratio. The applicable margin ranges from 1.00% to 2.25% for loans bearing interest with reference to LIBOR or CDOR and from 0.00% to 1.25% for loans bearing interest with reference to the alternate base rate or Canadian base rate. Centuri is also required to pay a commitment fee on the unfunded portion of the commitments based on the consolidated leverage ratio. The commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the credit facility ranged from a low of $199 million during December 2014 to a high of $232 million during October 2014. All amounts outstanding are considered long-term borrowings. The outstanding amount on the facility at December 31, 2014 includes term loans in the amount of $142 million. The effective interest rate on the facility was 3.31% at December 31, 2014.

In November 2014, Southwest’s $65 million 2004 5.25% Series A fixed-rate IDRBs (originally due in 2034) were redeemed at par plus accrued interest.


58 \| Southwest Gas Corporation

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


	December 31, 2014			December 31, 2013
2003 Series A		0.85	%		1.43	%
2008 Series A		0.90	%		1.41	%
2009 Series A		0.89	%		1.01	%
Tax-exempt Series A		0.84	%		1.07	%

In Nevada, interest fluctuations due to changing interest rates on the 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.

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


2015	$	19,192
2016		20,991
2017		43,899
2018		16,985
2019		304,328

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, 2014, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $1.9 billion in additional debt and meet the leverage ratio requirement. The Company has at least $900 million of cushion in equity relating to the minimum net worth requirement.

Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2014, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $88 million in additional debt and meet the leverage ratio requirement. Centuri has at least $35 million of cushion in equity relating to the minimum fixed charge ratio coverage requirement.

Note 7 – Short-Term Debt

As discussed in Note 6, Southwest has a $300 million credit facility that is scheduled to expire in March 2019, of which $150 million has been designated by management for working capital purposes. The Company had $5 million in short-term borrowings outstanding at December 31, 2014 and no short-term borrowings outstanding at December 31, 2013. The effective interest rate on the short-term portion of the credit facility was 1.13% at December 31, 2014.

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.


		Southwest Gas Corporation \| 59

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers would be responsible for amounts up to the policy limits. For the policy year August 2014 to July 2015, these liability insurance policies require Southwest to be responsible for the first $1 million dollars (self-insured retention) of each incident plus the first $4 million in aggregate claims above its self-insured retention in the policy year. Through an assessment process, the Company may determine that certain costs are likely to be incurred in the future related to specific legal matters. In these circumstances and in accordance with accounting policies, the Company will make an accrual.

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 deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches one-half of amounts deferred by employees, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. Centuri has a separate plan, the cost and liability of which are not significant. The cost of the Southwest plan is listed below (in thousands):


	2014		2013		2012
Employee Investment Plan cost	$	4,816	$	4,850	$	4,707

Southwest has a deferred compensation plan for all officers and a separate deferred compensation plan for members of the Board of Directors. The plans provide the opportunity to defer up to 100% of annual cash compensation. Southwest matches one-half of amounts deferred by officers, up to a maximum matching contribution of 3.5% of an officer’s annual base salary. Upon retirement, payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150% of Moody’s Seasoned Corporate Bond Rate Index.

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

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

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


60 \| Southwest Gas Corporation

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

A target portfolio of investments in the qualified retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Asset return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. At December 31, 2014, the percentage ranges of the target portfolio are:


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

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

U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on 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 lower interest rate environment for high-quality fixed income investments, the Company reduced the discount rate at December 31, 2014 from 2013. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also lowered (consistent with management’s expectations overall). The asset return assumption (which impacts the following year’s expense) was not changed. The rates are presented in the table below:


	December 31, 2014			December 31, 2013
Discount rate		4.25	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		3.25	%
Asset return assumption		7.75	%		7.75	%


		Southwest Gas Corporation \| 61

A landmark change to a new actuarial mortality table by the Society of Actuaries, which takes into account longer life spans for plan participants and forms a new basis for retirement plan obligations in the U.S., will significantly increase the expense level for 2015. It also negatively impacts the funded status of the plan at the end of 2014. Pension expense for 2015 is estimated to increase by $10 million compared to 2014 because of the extended mortality assumption and lower discount rate. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

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


	2014									2013
	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)	$	886,714		$	36,143		$	58,020		$	902,812		$	37,373		$	59,704
Service cost		21,360			292			1,101			23,056			373			1,220
Interest cost		43,440			1,745			2,829			37,607			1,535			2,482
Plan amendments		—			—			6,661			—			—			—
Actuarial loss (gain)		144,606			5,459			4,567			(44,768	)		(661	)		(4,073	)
Benefits paid		(35,880	)		(2,463	)		(976	)		(31,993	)		(2,477	)		(1,313	)

Benefit obligation at end of year (PBO/PBO/APBO)		1,060,240			41,176			72,202			886,714			36,143			58,020

Change in plan assets
Market value of plan assets at beginning of year		719,944			—			42,314			609,750			—			35,250
Actual return on plan assets		34,732			—			2,859			96,187			—			7,319
Employer contributions		36,000			2,463			—			46,000			2,477			169
Benefits paid		(35,880	)		(2,463	)		(281	)		(31,993	)		(2,477	)		(424	)

Market value of plan assets at end of year		754,796			—			44,892			719,944			—			42,314

Funded status at year end	$	(305,444	)	$	(41,176	)	$	(27,310	)	$	(166,770	)	$	(36,143	)	$	(15,706	)

Weighted-average assumptions (benefit obligation)
Discount rate		4.25	%		4.25	%		4.25	%		5.00	%		5.00	%		5.00	%
Weighted-average rate of compensation increase		2.75	%		2.75	%		N/A			3.25	%		3.25	%		N/A

Estimated funding for the plans above during calendar year 2015 is approximately $39 million of which $36 million pertains to the retirement plan. Management monitors plan assets and liabilities and could, at its discretion, increase plan funding levels above the minimum in order to achieve a desired funded status and avoid or minimize potential benefit restrictions.


62 \| Southwest Gas Corporation

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


	December 31, 2014		December 31, 2013
Retirement plan	$	886,215	$	794,919
SERP		39,125		33,894

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


	2015	2016	2017	2018		2019		2020-2024
Pension	$ 39.1	$41.3	$43.1		$45.3		$47.5		$272.7
PBOP	3.3	3.6	3.8		4.0		4.1		20.4
SERP	2.6	2.6	2.6		2.6		2.6		13.0

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

For PBOP measurement purposes, the per capita cost of the covered health care benefits medical rate trend assumption is 6% declining to 5%. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays all covered health care costs for employees who retired prior to 1989. The medical trend rate assumption noted above applies to the benefit obligations of pre-1989 retirees only.

Components of net periodic benefit cost


	Qualified Retirement Plan									SERP									PBOP
	2014			2013			2012			2014			2013			2012			2014			2013			2012
(Thousands of dollars)
Service cost	$	21,360		$	23,056		$	20,319		$	292		$	373		$	274		$	1,101		$	1,220		$	977
Interest cost		43,440			37,607			38,266			1,745			1,535			1,629			2,829			2,482			2,547
Expected return on plan assets		(53,342	)		(49,840	)		(45,780	)		—			—			—			(3,264	)		(2,824	)		(2,404	)
Amortization of prior service cost		—			—			—			—			—			—			355			355			—
Amortization of transition obligation		—			—			—			—			—			—			—			—			867
Amortization of net actuarial loss		22,873			32,261			23,883			783			971			683			—			945			1,031

Net periodic benefit cost	$	34,331		$	43,084		$	36,688		$	2,820		$	2,879		$	2,586		$	1,021		$	2,178		$	3,018

Weighted-average assumptions (net benefit cost)
Discount rate		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%		5.00	%		4.25	%		5.00	%
Expected return on plan assets		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%		7.75	%		8.00	%		8.00	%
Weighted-average rate of compensation increase		3.25	%		2.75	%		3.00	%		3.25	%		2.75	%		3.00	%		N/A			N/A			N/A


		Southwest Gas Corporation \| 63

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


	2014												2013												2012
	Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP			Total			Qualified Retirement Plan			SERP			PBOP
(Thousands of dollars)
Net actuarial loss (gain) (a)	$	173,646		$	163,215		$	5,460		$	4,971		$	(100,345	)	$	(91,115	)	$	(662	)	$	(8,568	)	$	74,853		$	70,016		$	4,111		$	726
Amortization of prior service cost (b)		(355	)		—			—			(355	)		(355	)		—			—			(355	)		—			—			—			—
Amortization of transition obligation (b)		—			—			—			—			—			—			—			—			(867	)		—			—			(867	)
Amortization of net actuarial loss (b)		(23,656	)		(22,872	)		(784	)		—			(34,177	)		(32,261	)		(971	)		(945	)		(25,597	)		(23,883	)		(683	)		(1,031	)
Prior service cost		6,661			—			—			6,661			—			—			—			—			2,423			—			—			2,423
Regulatory adjustment		(140,308	)		(129,031	)		—			(11,277	)		123,630			113,762			—			9,868			(42,771	)		(41,520	)		—			(1,251	)

Recognized in other comprehensive
(income) loss		15,988			11,312			4,676			—			(11,247	)		(9,614	)		(1,633	)		—			8,041			4,613			3,428			—
Net periodic benefit costs recognized in net income		38,172			34,331			2,820			1,021			48,141			43,084			2,879			2,178			42,292			36,688			2,586			3,018

Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss	$	54,160		$	45,643		$	7,496		$	1,021		$	36,894		$	33,470		$	1,246		$	2,178		$	50,333		$	41,301		$	6,014			$3,018

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

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

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

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

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

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


64 \| Southwest Gas Corporation

The following table sets forth, by level within the three-level fair value hierarchy, the fair values of the assets of the qualified pension plan and the PBOP as of December 31, 2014 and December 31, 2013. The SERP has no assets. There were no transfers between Levels 1 and 2 during 2014.


	December 31, 2014						December 31, 2013
	Qualified Retirement Plan		PBOP		Total		Qualified Retirement Plan		PBOP		Total
Assets at fair value (thousands of dollars):

Level 1 – Quoted prices in active markets for identical financial assets
Common stock
Agriculture	$	6,661	$	198	$	6,859	$	8,224	$	244	$	8,468
Capital equipment		2,222		66		2,288		3,891		115		4,006
Chemicals/materials		5,233		155		5,388		8,228		244		8,472
Consumer goods		41,731		1,238		42,969		54,329		1,611		55,940
Energy and mining		18,502		549		19,051		36,126		1,071		37,197
Finance/insurance		20,685		613		21,298		37,643		1,116		38,759
Healthcare		37,846		1,122		38,968		40,426		1,199		41,625
Information technology		25,881		767		26,648		24,636		731		25,367
Services		28,846		855		29,701		31,212		926		32,138
Telecommunications/internet/media		18,498		549		19,047		24,270		720		24,990
Other		10,958		325		11,283		16,455		488		16,943
Real estate investment trusts		5,713		169		5,882		5,779		171		5,950
Mutual funds		86,159		24,567		110,726		76,764		22,495		99,259
Government fixed income securities		44,694		1,325		46,019		34,495		1,023		35,518
Preferred securities		568		17		585		—		—		—

Total Level 1 Assets (1)	$	354,197	$	32,515	$	386,712	$	402,478	$	32,154	$	434,632

Level 2 – Significant other observable inputs
Commercial paper	$	—	$	—	$	—	$	1,411	$	42	$	1,453
Government fixed income and mortgage backed securities		48,312		1,433		49,745		49,298		1,462		50,760
Corporate fixed income securities
Asset-backed and mortgage-backed		27,071		803		27,874		20,697		614		21,311
Banking		23,289		691		23,980		19,004		564		19,568
Insurance		6,182		183		6,365		6,481		192		6,673
Utilities		4,232		126		4,358		5,278		156		5,434
Other		23,120		686		23,806		19,649		582		20,231
Pooled funds and mutual funds		11,968		984		12,952		8,111		1,150		9,261
State and local obligations		1,499		44		1,543		1,370		41		1,411

Total Level 2 assets (2)	$	145,673	$	4,950	$	150,623	$	131,299	$	4,803	$	136,102

Level 3 – Significant unobservable inputs
Commingled equity funds	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070

Total Level 3 assets (3)	$	259,235	$	7,687	$	266,922	$	189,452	$	5,618	$	195,070

Total Plan assets at fair value	$	759,105	$	45,152	$	804,257	$	723,229	$	42,575	$	765,804
Insurance company general account contracts (4)		4,003		—		4,003		4,296		—		4,296

Total Plan assets (5)	$	763,108	$	45,152	$	808,260	$	727,525	$	42,575	$	770,100


		Southwest Gas Corporation \| 65

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

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

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

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

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

The commingled equity funds include private equity funds that invest in domestic and international securities (predominately Level 1 assets) regularly traded on securities exchanges. These funds are shown in the above table at net asset value. Investment strategies employed by the funds include:

•

Domestic large capitalization value equities

•

International developed countries value and growth equities

•

Emerging markets equities

•

International small capitalization equities

The terms and conditions under which shares in the commingled equity funds may be redeemed vary among the funds; the notice required ranges from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds requires the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminishes the greater the transaction. Other such funds may impose fees to recover direct costs incurred by the fund at redemption, but are indeterminable prior to redemption.

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

(5)

The assets in the above table exceed the market value of plan assets shown in the funded status table by $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) and $7,842,000 (qualified retirement plan – $7,581,000, PBOP – $261,000) for 2014 and 2013, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.


66 \| Southwest Gas Corporation

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)


	Commingled Equity Funds
(Thousands of dollars):
Balance, December 31, 2012	$	127,467
Actual return on plan assets:
Relating to assets still held at the reporting date		21,903
Relating to assets sold during the period		—
Purchases		45,700
Sales		—
Settlements		—
Transfers in and/or out of Level 3		—

Balance, December 31, 2013		195,070
Actual return on plan assets:
Relating to assets still held at the reporting date		(6,932	)
Relating to assets sold during the period		2,069
Purchases		82,615
Sales		(5,900	)
Settlements		—
Transfers in and/or out of Level 3		—

Balance, December 31, 2014	$	266,922

Note 10 – Stock-Based Compensation

At December 31, 2014, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan which includes a cash award, and a restricted stock/unit plan. The table below shows total stock-based plan compensation expense, including the cash award, which was recognized in the consolidated statements of income (in thousands):


	2014		2013		2012
Stock-based compensation plan expense, net of related tax benefits	$	8,130	$	8,012	$	7,396
Stock-based compensation plan related tax benefits		4,983		4,910		4,533

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.


		Southwest Gas Corporation \| 67

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


	2014					2013					2012
	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		52		$	27.57		125		$	28.13		177		$	27.28
Exercised during the year		(16	)		24.31		(72	)		28.44		(52	)		25.25
Forfeited or expired during the year		—			—		(1	)		33.07		—			—

Outstanding and exercisable at year end		36		$	28.97		52		$	27.57		125		$	28.13

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


	2014		2013		2012
Outstanding and exercisable	$	1,194	$	1,473	$	1,788
Exercised		451		1,402		928


	December 31, 2014		December 31, 2013		December 31, 2012
Market value of Southwest Gas stock	$	61.81	$	55.91	$	42.41

The weighted-average remaining contractual life for outstanding options was one year for 2014. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2014 (thousands of options):


	Options Outstanding and Exercisable
Range of Exercise Price	Number outstanding		Weighted-average remaining contractual life		Weighted-average exercise price
$25.00 to $26.10		17		0.5 Years	$	25.71
$29.08 to $33.07		19		1.5 Years	$	31.83

The Company received $379,000 in cash from the exercise of options during 2014 and a corresponding tax benefit of $167,000 which was recorded in additional paid-in capital.

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

The Company awards restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/units vest 40% at the end of year one and 30% at the end of years two and three and are issued annually as common stock in accordance with the percentage vested. The


68 \| Southwest Gas Corporation

restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants of restricted stock/units to directors occurs immediately upon grant. The issuance of common stock for directors occurs when their service on the Board ends.

The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2014 (thousands of shares):


	Performance Shares			Weighted- average grant date fair value		Restricted Stock/ Units			Weighted- average grant date fair value
Nonvested/unissued at beginning of year		323		$	39.16		245		$	38.00
Granted		77			53.73		83			53.73
Dividends		7					7
Forfeited or expired		—			—		—			—
Vested and issued*		(136	)		36.23		(78	)		40.87

Nonvested/unissued at December 31, 2014		271		$	43.71		257		$	41.22

*	Includes shares for retiree payouts and those converted for taxes.

The average grant date fair value of performance shares and restricted stock/units granted in 2013 and 2012 was $44.83 and $41.34, respectively.

As of December 31, 2014, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $2.9 million.

Note 11 – Income Taxes

The following is a summary of income before taxes and noncontrolling interest for domestic and foreign operations (thousands of dollars):


Year ended December 31,	2014			2013		2012
U.S.	$	221,471		$	222,815	$	207,915
Foreign		(1,950	)		—		—

Total income before income taxes	$	219,521		$	222,815	$	207,915


		Southwest Gas Corporation \| 69

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


Year Ended December 31,	2014			2013		2012
Current:
Federal	$	1,739		$	3,549	$	2,296
State		5,073			5,107		5,744
Foreign		2,193			—		—

		9,005			8,656		8,040

Deferred:
Federal		71,439			67,414		65,551
State		614			1,872		1,685
Foreign		(2,685	)		—		—

		69,368			69,286		67,236

Total income tax expense	$	78,373		$	77,942	$	75,276

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


Year Ended December 31,	2014			2013			2012
Deferred federal and state:
Property-related items	$	52,814		$	62,737		$	64,249
Purchased gas cost adjustments		15,049			16,189			1,755
Employee benefits		109			(2,769	)		564
All other deferred		2,257			(6,010	)		1,529

Total deferred federal and state		70,229			70,147			68,097
Deferred ITC, net		(861	)		(861	)		(861	)

Total deferred income tax expense	$	69,368		$	69,286		$	67,236

A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2012, 2013, and 2014 (and the sources of these differences and the effect of each) are summarized as follows:


Year Ended December 31,	2014			2013			2012
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Net state taxes		1.9			2.4			2.6
Property-related items		0.1			0.1			0.2
Tax credits		(0.5	)		(0.4	)		(0.4	)
Company owned life insurance		(1.0	)		(2.1	)		(1.3	)
All other differences		0.2			—			0.1

Consolidated effective income tax rate		35.7	%		35.0	%		36.2	%


70 \| Southwest Gas Corporation

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


December 31,	2014			2013
Deferred tax assets:
Deferred income taxes for future amortization of ITC	$	2,146		$	2,679
Employee benefits		31,557			25,591
Alternative minimum tax credit		20,172			19,739
Net operating losses and credits		9,719			15,113
Interest rate swap		8,622			9,893
Other		25,872			22,334
Valuation allowance		(253	)		(200	)

		97,835			95,149

Deferred tax liabilities:
Property-related items, including accelerated depreciation		736,810			694,024
Regulatory balancing accounts		33,736			18,688
Property-related items previously flowed through		28			836
Unamortized ITC		3,410			4,271
Debt-related costs		5,066			4,713
Intangibles		12,792			—
Other		27,572			15,898

		819,414			738,430

Net deferred tax liabilities		721,579			643,281

Current		(2,109	)		(31,130	)
Noncurrent		723,688			674,411

Net deferred tax liabilities	$	721,579		$	643,281

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, various states, and in Canada. The Company is currently under examination in Canada for years 2011 and 2012. With few exceptions, the Company is no longer subject to United States federal, state and local, or Canadian income tax examinations for years before 2010.

At December 31, 2014, the Company has a U.S. federal net operating loss carryforward of $28 million which expires in 2031. The Company also has federal general business credits of $711,000, which begin to expire in 2031. The Company also has U.S. federal net capital loss carryforwards of $494,000, which begin to expire in 2016. At December 31, 2014, the Company has an income tax net operating loss carryforward related to Canadian operations of $1.1 million which expires in 2034.

As of December 31, 2014, the Company sustained losses in its foreign jurisdiction and therefore has no undistributed foreign earnings. However, the Company intends to permanently reinvest any future foreign earnings in Canada.


		Southwest Gas Corporation \| 71

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


	2014		2013
Unrecognized tax benefits at beginning of year	$	—	$	—
Gross increases-tax positions in prior period		305		—
Gross decreases-tax positions in prior period		—		—
Gross increases-current period tax positions		—		—
Gross decreases-current period tax positions		—		—
Settlements		—		—
Lapse in statute of limitations		—		—

Unrecognized tax benefits at end of year	$	305	$	—

In assessing whether uncertain tax positions should be recognized in its financial statements, Southwest first determines whether it is more-likely-than-not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, Southwest presumes that the position will be examined by the appropriate taxing authority that would have full knowledge of all relevant information. For tax positions that meet the more-likely-than-not recognition threshold, Southwest measures the amount of benefit recognized in the financial statements at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. Southwest recognizes unrecognized tax benefits in the first financial reporting period in which information becomes available indicating that such benefits will more-likely-than-not be realized. For each reporting period, management applies a consistent methodology to measure unrecognized tax benefits, and all unrecognized tax benefits are reviewed periodically and adjusted as circumstances warrant. Southwest’s measurement of its unrecognized tax benefits is based on management’s assessment of all relevant information, including prior audit experience, the status of audits, conclusions of tax audits, lapsing of applicable statutes of limitations, identification of new issues, and any administrative guidance or developments

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate was $0 at December 31, 2014. No significant increases or decreases in unrecognized tax benefit are expected within the next 12 months.

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


	2014		2013		2012
Tax-related interest income	$	—	$	—	$	24

Final and Proposed Income Tax Regulations. In September 2013, the United States Department of the Treasury and the Internal Revenue Service (“IRS”) issued final and proposed regulations for the tax treatment of tangible property. The final regulations include standards for determining whether and when a taxpayer must capitalize costs incurred in acquiring, maintaining, or improving tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, and were eligible for adoption in earlier years under certain


72 \| Southwest Gas Corporation

circumstances. Proposed regulations were also released that revise the rules for dispositions of tangible property and general asset accounts. The Company expects the IRS to issue natural gas industry guidance which will facilitate its analysis regarding the regulations’ impact on natural gas distribution networks. Based upon preliminary analysis of the final and proposed regulations, and in anticipation of specific guidance for the natural gas industry, the Company expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.

Note 12 – Derivatives and Fair Value Measurements

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

In late 2013, the Company suspended further swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The decision did not impact previously executed purchase arrangements. Agreements, under the Nevada VMP program, made prior to the suspension will terminate following the March 2015 delivery month. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

The fixed-price contracts and Swaps are utilized by Southwest under its ongoing volatility mitigation programs to effectively fix the price on a portion (for the 2014/2015 heating season, up to 25%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2015 through March 2016. Under such contracts, Southwest pays the counterparty a fixed rate and receives from the counterparty a floating rate per MMBtu (“dekatherm”) of natural gas. Only the net differential is actually paid or received. The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):


	December 31, 2014		December 31, 2013
Contract notional amounts		5,105		13,571

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


		Southwest Gas Corporation \| 73

The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2014, 2013, and 2012 and their location in the Consolidated Statements of Income (thousands of dollars):

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

(Thousands of dollars)


Instrument	Location of Gain or (Loss) Recognized in Income on Derivative	2014			2013			2012
Swaps	Net cost of gas sold	$	(2,363	)	$	976		$	(4,854	)
Swaps	Net cost of gas sold		2,363	*		(976	)*		4,854	*

Total		$	—		$	—		$	—

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

In January 2010, Southwest entered into two forward-starting interest rate swaps (“FSIRS”), both of which were designated cash flow hedges, to partially hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace maturing debt. The first FSIRS terminated in December 2010. The second FSIRS terminated in March 2012. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss (ineffective portion) was recognized in income for either FSIRS during any period, including the period presented in the following table.

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


	Year Ended December 31, 2014		Year Ended December 31, 2013		Year Ended December 31, 2012
(Thousands of dollars)
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative	$	—	$	—	$	2,959


74 \| Southwest Gas Corporation

The following table sets forth the fair values of the Company’s Swaps and their location in the Consolidated Balance Sheets (thousands of dollars):

Fair values of derivatives not designated as hedging instruments:


December 31, 2014 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Other current liabilities	$	—	$	(5,062	)	$	(5,062	)
Swaps	Other deferred credits		—		(363	)		(363	)

Total		$	—	$	(5,425	)	$	(5,425	)


December 31, 2013 Instrument	Balance Sheet Location	Asset Derivatives		Liability Derivatives			Net Total
Swaps	Deferred charges and other assets	$	257	$	(77	)	$	180
Swaps	Prepaids and other current assets		1,054		(253	)		801
Swaps	Other current liabilities		126		(282	)		(156	)
Swaps	Other deferred credits		7		(11	)		(4	)

Total		$	1,444	$	(623	)	$	821

The estimated fair values of the natural gas 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 Company had no outstanding collateral associated with the Swaps during either period shown in the above table.

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

The following table shows the amounts Southwest paid to and received from counterparties for settlements of matured Swaps.


	Year ended December 31, 2014		Year ended December 31, 2013		Year ended December 31, 2012
(Thousands of dollars)
Paid to counterparties	$	829	$	3,148	$	14,843

Received from counterparties	$	4,713	$	915	$	634


		Southwest Gas Corporation \| 75

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


December 31, 2014 Instrument	Balance Sheet Location	Net Total
Swaps	Prepaids and other current assets	$	5,062
Swaps	Deferred charges and other assets		363

December 31, 2013 Instrument	Balance Sheet Location	Net Total
Swaps	Other deferred credits	$	(180	)
Swaps	Other current liabilities		(801	)
Swaps	Prepaids and other current assets		156
Swaps	Deferred charges and other assets		4

Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at December 31, 2014 and 2013 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 (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.

The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Company’s financial assets and liabilities that were accounted for at fair value (see Note 9 – Pension and Other Post Retirement Benefits for definitions of the levels of the fair value hierarchy):

Level 2 - Significant other observable inputs


	December 31, 2014			December 31, 2013
(Thousands of dollars)
Assets at fair value:
Prepaids and other current assets - Swaps	$	—		$	801
Deferred charges and other assets - Swaps		—			180
Liabilities at fair value:
Other current liabilities - Swaps		(5,062	)		(156	)
Other deferred credits - Swaps		(363	)		(4	)

Net Assets (Liabilities)	$	(5,425	)	$	821

No financial assets or liabilities associated with the Swaps, which were accounted for at fair value, fell within Level 1 or Level 3 of the fair value hierarchy.

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, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and providing industrial construction solutions.


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


	December 31, 2014		December 31, 2013
Accounts receivable for Centuri services	$	9,169	$	10,787

The following table presents the amount of revenues and long-lived assets by geographic area (thousands of dollars):


	December 31, 2014		December 31, 2013
Revenues (a)
United States	$	2,069,513	$	1,950,782
Canada		52,194		—

Total	$	2,121,707	$	1,950,782

Long-lived assets
United States	$	6,021,476		5,674,449
Canada		14,475		—

Total	$	6,035,951	$	5,674,449

(a)	Revenues are attributed to countries based on the location of customers.

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, 2014 is as follows (thousands of dollars):


2014	Gas Operations		Construction Services		Adjustments (a)			Total
Revenues from unaffiliated customers	$	1,382,087	$	647,432				$	2,029,519
Intersegment sales		—		92,188					92,188

Total	$	1,382,087	$	739,620				$	2,121,707

Interest revenue	$	2,596	$	6				$	2,602

Interest expense	$	68,299	$	3,770				$	72,069

Depreciation and amortization	$	204,144	$	48,883				$	253,027

Income tax expense	$	63,597	$	14,776				$	78,373

Segment net income	$	116,872	$	24,254				$	141,126

Segment assets	$	4,657,709	$	567,405	$	(10,599	)	$	5,214,515

Capital expenditures	$	350,025	$	46,873				$	396,898


		Southwest Gas Corporation \| 77


2013	Gas Operations		Construction Services		Adjustments (b)			Total
Revenues from unaffiliated customers	$	1,300,154	$	562,475				$	1,862,629
Intersegment sales		—		88,153					88,153

Total	$	1,300,154	$	650,628				$	1,950,782

Interest revenue	$	456	$	5				$	461

Interest expense	$	62,555	$	1,145				$	63,700

Depreciation and amortization	$	193,848	$	42,969				$	236,817

Income tax expense	$	65,377	$	12,565				$	77,942

Segment net income	$	124,169	$	21,151				$	145,320

Segment assets	$	4,272,029	$	293,811	$	(666	)	$	4,565,174

Capital expenditures	$	314,578	$	49,698				$	364,276


2012	Gas Operations		Construction Services		Adjustments			Total
Revenues from unaffiliated customers	$	1,321,728	$	522,676				$	1,844,404
Intersegment sales		—		83,374					83,374

Total	$	1,321,728	$	606,050				$	1,927,778

Interest revenue	$	915	$	9				$	924

Interest expense	$	66,957	$	1,063				$	68,020

Depreciation and amortization	$	186,035	$	37,387				$	223,422

Income tax expense	$	64,973	$	10,303				$	75,276

Segment net income	$	116,619	$	16,712				$	133,331

Segment assets	$	4,204,948	$	283,109				$	4,488,057

Capital expenditures	$	308,951	$	86,761				$	395,712

(a)

Construction services segment assets include two liabilities that were netted against gas operations segment assets during consolidation in 2014. They are: Income taxes payable of $3.3 million, netted against income taxes receivable, net and deferred income taxes of $1.4 million, netted against deferred income taxes, net. Construction services segment assets exclude a long-term deferred tax benefit of $1.4 million, which was netted against gas operations segment deferred income taxes and investment tax credits, net during consolidation. Gas operations segment assets include a deferred income tax liability of $4.5 million, which was netted against a construction services segment asset for deferred income taxes, net during consolidation.

(b)	Construction services segment assets include income taxes payable of $666,000 in 2013, which was 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)
2014
Operating revenues	$	608,396	$	453,153		$	432,475		$	627,683
Operating income		127,065		26,755			18,290			112,373
Net income		70,697		9,627			1,927			58,897
Net income attributable to Southwest Gas Corporation		70,783		9,627			1,970			58,746
Basic earnings per common share*		1.52		0.21			0.04			1.26
Diluted earnings per common share*		1.51		0.21			0.04			1.25

2013
Operating revenues	$	613,505	$	411,574		$	387,346		$	538,357
Operating income		138,394		28,908			6,141			100,772
Net income (loss)		80,674		10,067			(3,057	)		57,189
Net income (loss) attributable to Southwest Gas Corporation		80,773		10,108			(2,864	)		57,303
Basic earnings (loss) per common share*		1.75		0.22			(0.06	)		1.24
Diluted earnings (loss) per common share*		1.73		0.22			(0.06	)		1.22

2012
Operating revenues	$	657,645	$	409,768		$	371,799		$	488,566
Operating income		134,623		15,380			6,310			115,211
Net income (loss)		78,835		(3,888	)		(4,414	)		62,106
Net income (loss) attributable to Southwest Gas Corporation		78,919		(3,676	)		(4,305	)		62,393
Basic earnings (loss) per common share*		1.71		(0.08	)		(0.09	)		1.35
Diluted earnings (loss) per common share*		1.70		(0.08	)		(0.09	)		1.34

*	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 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. Additionally, see Note 15 – Acquisition of Construction Services Businesses below regarding an acquisition in the last quarter of 2014 and see Note-16 – Construction Services Noncontrolling Interests regarding allocation of earnings.

Note 15 – Acquisition of Construction Services Businesses

As indicated in Note 1 – Summary of Significant Accounting Policies, under Consolidation, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses for $221 million. Previous owners of the acquired companies retained an approximate 10% interest in the Canadian subsidiaries of Centuri.


		Southwest Gas Corporation \| 79

Assets acquired and liabilities assumed in the transaction were recorded, generally, at their acquisition date fair values. Transaction costs associated with the acquisition were expensed as incurred. The Company’s allocation of the purchase price was based on an evaluation of the appropriate fair values and represented management’s best estimate based on available data (including market data, data regarding customers of the acquired businesses, terms of acquisition-related agreements, analysis of historical and projected results, and other types of data). The analysis included the impacts of differences between Accounting Standards for Private Enterprises in Canada and U. S. GAAP applicable to public companies, as well as consideration of types of intangibles that were acquired, including non-competition agreements, customer relationships, trade names, and work backlog. The final purchase accounting has not yet been completed. Further refinement is expected to occur, including changes to income taxes and intangibles. However, no material changes are expected. The preliminary estimated fair values of assets acquired and liabilities assumed as of October 1, 2014, are as follows (in millions of dollars):


Cash, cash equivalents, and restricted cash	$	3
Contracts receivable and other receivables		62
Property, plant and equipment		17
Other assets		17
Intangible assets		52
Goodwill		130

Total assets acquired		281
Current liabilities		39
Deferred income tax—long-term		17
Other long-term liabilities		4

Net assets acquired	$	221

Acquired contracts receivable and other receivables are expected to be collected.

The preliminary allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill, which is generally not deductible for tax purposes, consists of the value associated with the assembled workforce and consolidation of operations. The business of Brigadier was acquired via asset purchase. Therefore, the $4.9 million of tax-basis goodwill assigned to Brigadier is expected to be deductible for tax purposes. All other goodwill associated with the acquisition is not deductible for tax purposes. At December 31, 2014, the balance of goodwill associated with the acquisition was $125 million after consideration of changes in foreign currency adjustments. At December 31, 2014, other intangible assets totaled $48.2 million (after foreign currency adjustments of $1.9 million and approximately $1.5 million accumulated amortization). Intangible assets (as of December 2014) consist of $500,000 in non-competition agreements (net of approximately $40,000 of accumulated amortization, with a 5-year weighted-average useful life), $36.5 million in customer relationships (net of approximately $550,000 accumulated amortization, with useful lives ranging from 12 to 21 years), $10 million in trade names (net of approximately $250,000 accumulated amortization, with useful lives ranging from 4 to 20 years), and $1.2 million in work backlog (net of approximately $700,000 accumulated


80 \| Southwest Gas Corporation

amortization, with an 8-month useful life). The intangible assets other than goodwill are included in Other property and investments in the Consolidated Balance Sheets. The estimated future amortization of the intangible assets acquired in the acquisition for the next five years is as follows (in thousands):


2015	$	4,615
2016		3,371
2017		3,371
2018		3,123
2019		2,370

In connection with the acquisition, previous owners retained certain ownership rights, specifically, an approximate 10% stock ownership interest in the associated Canadian businesses. However, while the actual ownership interest was approximately 10% of Lynxus (Canadian operations), the terms of the underlying equity agreements include dividend participation rights equal to 3.4% of dividends declared at the level of Centuri. Additionally, these same agreements include, among other terms, the ability of the prior owners to exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021. Furthermore, the equity agreements include an exchange feature such that the noncontrolling ownership interest retained by the parties, in the Canadian subsidiaries, may be convertible into shares equivalent to a 3.4% interest in Centuri (redeemable noncontrolling interest). In consideration of these circumstances and the underlying agreements, it was deemed appropriate to allocate earnings to the redeemable noncontrolling interest at an amount equivalent to approximately 3.4% of total Centuri earnings (rather than based on the actual current proportional ownership). Through this earnings allocation process, approximately 96.6% of Centuri earnings are attributable to the Company. This earnings allocation takes place before the redeemable noncontrolling interest balance, included on the balance sheet, is adjusted based on its redemption value. Adjustments to redemption value through December 31, 2014 impacted retained earnings but not current net income. See also Earnings Per Share included within Note 1, and discussion below regarding adjustment to fair value, as well as Note 16 – Construction Services Noncontrolling Interests for more information.

The unaudited pro forma consolidated financial information for fiscal 2014 and fiscal 2013 (assuming the acquisition of Link-Line, W.S. Nicholls, and Brigadier occurred as of the beginning fiscal 2013) is as follows (in thousands of dollars, except per share amounts):


	Year Ended December 31,
	2014		2013
Total operating revenues	$	2,295,318	$	2,203,272
Net income attributable to Southwest Gas Corporation	$	149,588	$	143,424
Basic earnings per share	$	3.22	$	3.10
Diluted earnings per share	$	3.19	$	3.07

Acquisition costs of $5 million that were incurred during 2014, and included in construction expenses in the Consolidated Statements of Income, were excluded from the 2014 unaudited pro forma consolidated financial information shown above and included in the 2013 amounts. No material nonrecurring pro forma adjustments directly attributable to the business combination were included in the unaudited pro forma consolidated financial information.


		Southwest Gas Corporation \| 81

The pro forma financial information includes assumptions and adjustments made to incorporate various items including, but not limited to, additional interest expense and depreciation and amortization expense, and intercompany eliminations and tax effects, as appropriate. The pro forma financial information has been prepared for comparative purposes only, and is not intended to be indicative of what the Company’s results would have been had the acquisition occurred at the beginning of the periods presented or of the results which may occur in the future, for a number of reasons. These reasons include, but are not limited to, differences between the assumptions used to prepare the pro forma information, potential cost savings from operating efficiencies, and the impact of incremental costs incurred in integrating the businesses.

Actual results from Link-Line, W.S. Nicholls, and Brigadier operations included in the Consolidated Statements of Income since the date of acquisition are as follows (in thousands of dollars):


	Year ended December 31, 2014
Construction revenues	$	54,264
Net income attributable to Link-Line, W.S. Nicholls, and Brigadier	$	1,859

Note 16 – Construction Services Noncontrolling Interests

As discussed in Note 15 – Acquisition of Construction Services Businesses, at the close of the acquisition, previous owners of the acquired companies retained an approximate 10% equity interest in the Canadian businesses that were acquired. The agreement, associated with the approximate 10% indirect equity interest of the sellers, provides special dividend rights which entitle the sellers, as holders, to dividends equal to 3.4% of dividends paid at the level of Centuri and subject to certain conditions, such interests may become exchangeable for a 3.4% equity interest in Centuri. Additionally, the previous owners may exit their investment retained by requiring Centuri to purchase a portion of their interest (in Lynxus) commencing October 2016 and in incremental amounts each anniversary date thereafter. The shares subject to the election cumulate (if earlier elections are not made) such that 100% of their interest retained is subject to the election after September 2021.


82 \| Southwest Gas Corporation

The Company has determined that this noncontrolling interest is a redeemable noncontrolling interest and, in accordance with SEC guidance, is classified as mezzanine equity (temporary equity) in the Consolidated Balance Sheets. The redeemable noncontrolling interest is reported at $20 million, the estimated redemption value as of December 31, 2014. Based on the fair value model employed, the estimated redemption value of the redeemable noncontrolling interest increased by approximately $961,000 during the fourth quarter of 2014. Changes in the value of the redeemable noncontrolling interest will be recognized as they occur and the carrying value will be adjusted accordingly at each quarterly reporting date. Any adjustment to the redemption value impacts retained earnings, but does not impact net income.


	Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2013	$	—
Redeemable noncontrolling interest related to acquisition		18,952
Net Income (loss) attributable to redeemable noncontrolling interest		151
Foreign currency exchange translation adjustment		(22	)
Adjustment to redemption value		961

Balance, December 31, 2014	$	20,042

The redemption value of the redeemable noncontrolling interest was determined using a Monte Carlo simulation method. First, a market approach was utilized to determine a construction services enterprise value as of the acquisition date. Potential guideline publicly-traded companies were identified by using a selection criteria, including actively traded equities, their financial solvency, and other factors. Once the guideline companies were determined, enterprise value was calculated using a weighted approach of projected earnings before interest expense and taxes (“EBIT”) and earnings before interest expense, taxes, and depreciation and amortization expense (“EBITDA”). After an estimated fair value was determined, a Monte Carlo simulation was used to assign a value to the noncontrolling interest of the sellers. Other assumptions used in this analysis included dividends, probability of events, and a discount due to lack of control (the sellers do not influence operations).

Centuri also holds a 65% interest in a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. Centuri consolidates the entity (IntelliChoice Energy, LLC) as a majority-owned subsidiary. The interest is immaterial to the consolidated financial statements.


		Southwest Gas Corporation \| 83

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. See Item 9A Controls and Procedures of the 2014 SEC Form 10-K for a discussion regarding the scope of management’s assessment due to the recent acquisition of Link-Line, W.S. Nicholls, and Brigadier, entities which are excluded from management’s report on internal control over financial reporting. The acquired businesses represent 5% of consolidated total assets and 3% of consolidated revenues for the year ended December 31, 2014 and are not significant to the Company’s consolidated financial statements. 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 in 2013. 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, 2014. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 26, 2015


84 \| Southwest Gas Corporation

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of cash flows and of equity and redeemable noncontrolling interest present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

As described in Management’s Report on Internal Control Over Financial Reporting appearing in Item 9A of the Southwest Gas Corporation’s 2014 Annual Report on Form 10-K, management has excluded Link-Line Contractors


		Southwest Gas Corporation \| 85

Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. from its assessment of internal control over financial reporting as of December 31, 2014 because it was acquired in a purchase business combination by NPL Construction Co. on October 1, 2014. We have also excluded Link-Line Contractors Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. from our audit of internal control over financial reporting. Link-Line Contractors Ltd., W.S. Nicholls Construction, Inc., and Brigadier Pipelines Inc. are wholly-owned subsidiaries whose total assets and total revenues represent 5% and 3%, respectively, of the related consolidated financial statements amounts as of and for the year ended December 31, 2014.

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PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 26, 2015


86 \| Southwest Gas Corporation

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