Exhibit 13.01

Consolidated Selected Financial Statistics

 

Year Ended December 31,		2015				2014				2013				2012				2011
(Thousands of dollars, except pershare amounts)
Operating revenues		$	2,463,625			$	2,121,707			$	1,950,782			$	1,927,778			$	1,887,188
Operating expenses			2,175,293				1,837,224				1,676,567				1,656,254				1,637,108
Operating income		$	288,332			$	284,483			$	274,215			$	271,524			$	250,080
Net income		$	138,317			$	141,126			$	145,320			$	133,331			$	112,287
Total assets at year end		$	5,358,685			$	5,208,297			$	4,565,174			$	4,488,057			$	4,276,007
Capitalization at year end
Total equity		$	1,592,325			$	1,486,266			$	1,412,395			$	1,308,498			$	1,225,031
Redeemable noncontrolling interest			16,108				20,042				—				—				—
Long-term debt, excluding current maturities			1,551,204				1,631,374				1,381,327				1,268,373				930,858
		$	3,159,637			$	3,137,682			$	2,793,722			$	2,576,871			$	2,155,889
Current maturities of long-term debt		$	19,475			$	19,192			$	11,105			$	50,137			$	322,618
Common stock data
Common equity percentage of capitalization			50.4	%			47.4	%			50.6	%			50.8	%			56.8	%
Return on average common equity			8.9	%			9.7	%			10.6	%			10.4	%			9.3	%
Basic earnings per share		$	2.94			$	3.04			$	3.14			$	2.89			$	2.45
Diluted earnings per share		$	2.92			$	3.01			$	3.11			$	2.86			$	2.43
Dividends declared per share		$	1.62			$	1.46			$	1.32			$	1.18			$	1.06
Payout ratio			55	%			48	%			42	%			41	%			43	%
Book value per share at year end		$	33.65			$	32.03			$	30.51			$	28.39			$	26.68
Market value per share at year end		$	55.16			$	61.81			$	55.91			$	42.41			$	42.49
Market value per share to per share			164	%			193	%			183	%			149	%			159	%
Common shares outstanding at year end (000)			47,378				46,523				46,356				46,148				45,956
Number of common shareholders at year end			14,153				14,749				15,359				16,028				16,834
Ratio of earnings to fixed charges			3.43				3.58				3.90				3.61				3.21

 

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Natural Gas Operations

 

Year Ended December 31,		2015				2014				2013				2012				2011
(Thousands of dollars)
Operating revenue		$	1,454,639			$	1,382,087			$	1,300,154			$	1,321,728			$	1,403,366
Net cost of gas sold			563,809				505,356				436,001				479,602				613,489
Operating margin			890,830				876,731				864,153				842,126				789,877
Expenses
Operations and maintenance			393,199				383,732				384,914				369,979				358,498
Depreciation and amortization			213,455				204,144				193,848				186,035				175,253
Taxes other than income taxes			49,393				47,252				45,551				41,728				40,949
Operating income		$	234,783			$	241,603			$	239,840			$	244,384			$	215,177
Contribution to consolidated net income		$	111,625			$	116,872			$	124,169			$	116,619			$	91,420
Total assets at year end		$	4,822,845			$	4,652,307			$	4,272,029			$	4,204,948			$	4,048,613
Net gas plant at year end		$	3,891,085			$	3,658,383			$	3,486,108			$	3,343,794			$	3,218,944
Construction expenditures and property additions		$	438,289			$	350,025			$	314,578			$	308,951			$	305,542
Cash flow, net
From operating activities		$	497,500			$	288,534			$	265,290			$	344,441			$	216,745
From (used in) investing activities			(416,727	)			(328,645	)			(304,189	)			(296,886	)			(289,234	)
From (used in) financing activities			(74,159	)			23,413				44,947				(43,453	)			(2,327	)
Net change in cash		$	6,614			$	(16,698	)		$	6,048			$	4,102			$	(74,816	)
Total throughput (thousands of therms)
Residential			655,421				617,377				741,327				655,046				718,765
Small commercial			285,118				276,582				298,045				270,665				303,923
Large commercial			92,284				94,391				102,761				116,582				112,256
Industrial/Other			30,973				32,374				50,210				47,830				50,208
Transportation			1,035,707				906,691				1,037,916				998,095				941,544
Total throughput			2,099,503				1,927,415				2,230,259				2,088,218				2,126,696
Weighted average cost of gas purchased ($/therm)		$	0.44			$	0.55			$	0.42			$	0.42			$	0.58
Customers at year end			1,956,000				1,930,000				1,904,000				1,876,000				1,859,000
Employees at year end			2,219				2,196				2,220				2,245				2,298
Customer to employee ratio			881				879				858				836				809
Degree days – actual			1,512				1,416				1,918				1,740				2,002
Degree days – ten-year average			1,792				1,816				1,876				1,866				1,888

 

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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, 2015, Southwest had 1,956,000 residential, commercial, industrial, and other natural gas customers, of which 1,045,000 customers were located in Arizona, 720,000 in Nevada, and 191,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2015, 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 the 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.

Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) 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 develops industrial construction solutions. In October 2014, the Company acquired three privately held construction businesses, primarily based in Canada. The financial information contained herein only includes the results of the acquired entities since October 2014. 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 recent 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

 

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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 bid contracts (especially those of a longer duration), 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 83% 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,		2015				2014				2013
(In thousands, except per share amounts)
Contribution to net income
Natural gas operations		$	111,625			$	116,872			$	124,169
Construction services			26,692				24,254				21,151
Consolidated		$	138,317			$	141,126			$	145,320
Average number of common shares outstanding			46,992				46,494				46,318
Basic earnings per share fine
Consolidated		$	2.94			$	3.04			$	3.14
Natural Gas Operations
Operating margin		$	890,830			$	876,731			$	864,153

2015 Overview

Consolidated results for 2015 decreased compared to 2014 due to results from the natural gas operations segment, partially offset by improved results from the construction services segment. Basic earnings per share were $2.94 in 2015 compared to basic earnings per share of $3.04 in 2014.

Natural gas operations highlights include the following:

•

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

•

Operating expenses increased $21 million, or 3%, between years

•

Net financing costs decreased $4 million between 2015 and 2014

•

COLI loss of $500,000 in 2015 compared to income of $5.3 million in 2014

•

Paiute Pipeline Company general rate case settlement approved by FERC

•

Redeemed $31.2 million of 5.00% IDRBs and $20 million of 5.25% IDRBs

•

Credit facility expiration date extended one year to March 2020

•

Issued $35.5 million in common stock under a $100 million Equity Shelf Program

•

Filed for a holding company structure with state regulatory commissions – approval received in California

 

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Construction services highlights include the following:

•

Revenues in 2015 increased $269 million, or 36%, compared to 2014, reaching $1 billion for the first time

•

Construction expenses increased $251 million or 39%, compared to 2014

•

Contribution to net income increased $2 million compared to 2014

•

Completed integration of Link-Line group of companies

Customer Growth.    Southwest completed 23,000 first-time meter sets, but realized 26,000 net new customers during 2015, an increase of 1.35%. The incremental additions reflect a return to service of customer meters on previously vacant homes. Southwest projects customer growth of about 1.5% for 2016.

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 $237 million at December 31, 2015. 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, 2015 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 movements in the broader stock and bond markets. In 2015, as indicated in Note 1 of the Notes to Consolidated Financial Statements, the cash surrender values of COLI policies declined $500,000 (compared to positive returns of $5.3 million in 2014). Over the long-term, management expects average income of $3 million to $5 million annually on the COLI policies, excluding any net death benefits recognized.

Liquidity. Southwest believes its liquidity position is sufficient. Southwest has a $300 million credit facility maturing in March 2020. 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 2015 was $180 million. In May 2015, the Company redeemed at par the $31.2 million 5.00% 2004 Series B Industrial Development Revenue Bonds (“IDRBs”) originally due in 2033. In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated these redemptions primarily from cash on hand and borrowings under its $300 million credit facility. At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility ($50 million of which was under the commercial paper program), and $18 million was outstanding on the short-term portion of the credit facility. Southwest has no debt maturities prior to 2017.

Centuri has a $300 million secured revolving credit and term loan facility maturing in October 2019. The facility is provided through a consortium of six banking institutions and consists of a term loan with an initial limit of approximately $150 million (which was reached in 2014) and a revolving line of credit of $150 million. The maximum amount outstanding on the credit facility during 2015 was $276 million including $113 million outstanding on the term loan facility. At December 31, 2015, there was approximately $77.4 million, net of letters of credit, available under the line of credit.

 

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Results of Natural Gas Operations

 

Year Ended December 31,		2015				2014				2013
(Thousands of dollars)
Gas operating revenues		$	1,454,639			$	1,382,087			$	1,300,154
Net cost of gas sold			563,809				505,356				436,001
Operating margin			890,830				876,731				864,153
Operations and maintenance expense			393,199				383,732				384,914
Depreciation and amortization			213,455				204,144				193,848
Taxes other than income taxes			49,393				47,252				45,551
Operating income			234,783				241,603				239,840
Other income (deductions)			2,292				7,165				12,261
Net interest deductions			64,095				68,299				62,555
Income before income taxes			172,980				180,469				189,546
Income tax expense			61,355				63,597				65,377
Contribution to consolidated net income		$	111,625			$	116,872			$	124,169

2015 vs. 2014

The contribution to consolidated net income from natural gas operations decreased $5.2 million between 2015 and 2014. The decline was primarily due to an increase in operating expenses and a decrease in other income, partially offset by improved operating margin and a decline in net interest deductions.

Operating margin increased $14 million between years. New customers contributed $8 million in operating margin during 2015. Combined rate relief in the California jurisdiction and Paiute Pipeline Company (see Rates and Regulatory Proceedings) provided $5 million in operating margin. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues increased by $1 million.

Operations and maintenance expense increased $9.5 million, or 2%, between years due primarily to general cost increases and higher employee-related expenses including pension expense. These increases were partially offset by certain expenses that were higher in the prior year, including a $5 million legal accrual in 2014 and $1.1 million in rent expense (associated with the previously leased corporate headquarters complex).

Depreciation and amortization expense increased $9.3 million, or 5%. Average gas plant in service for the current year increased $276 million, or 5%, 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. Increases in depreciation from these plant additions were partially offset by lower depreciation rates in California. Amortizations associated with the recovery of regulatory assets increased approximately $2.4 million overall (primarily due to Arizona integrity management and California energy efficiency programs).

Taxes other than income taxes increased $2.1 million, or 5%, between years primarily due to higher property taxes associated with net plant additions.

 

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Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, decreased $4.9 million between 2015 and 2014. The current year reflects a loss of $500,000 associated with COLI policy cash surrender value decreases, while the prior year included $5.3 million of COLI-related income.

Net interest deductions decreased $4.2 million between years. The decrease primarily resulted from the redemptions of $65 million 5.25% Series A IDRBs in November 2014, $31.2 million 5.00% 2004 Series B IDRBs in May 2015, and $20 million 5.25% 2003 Series D IDRBs in September 2015, partially offset by increased interest expense on PGA balances.

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. New customers contributed $8 million of the increase during 2014. 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 $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 2014 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 $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 years due to higher property taxes in Arizona and Nevada.

Other income decreased $5.1 million between 2014 and 2013. Cash surrender values of COLI policies (including net death benefits recognized) increased $5.3 million in 2014, while COLI-related income was $12.4 million in the prior year. Interest income increased $2.1 million between years, as under-collected PGA balances and the associated interest thereon rose significantly in 2014.

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 2013 associated with PGA balances, which were in an over-collected status for the majority of 2013.

 

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Results of Construction Services

 

Year Ended December 31,		2015				2014				2013
(Thousands of dollars)
Construction revenues		$	1,008,986			$	739,620			$	650,628
Operating expenses:
Construction expenses			898,781				647,857				573,284
Depreciation and amortization			56,656				48,883				42,969
Operating income			53,549				42,880				34,375
Other income (deductions)			587				(58	)			39
Net interest deductions			7,784				3,770				1,145
Income before income taxes			46,352				39,052				33,269
Income tax expense			18,547				14,776				12,565
Net income			27,805				24,276				20,704
Net income (loss) attributable to noncontrolling interests			1,113				22				(447	)
Contribution to consolidated net income attributable to Centuri		$	26,692			$	24,254			$	21,151

2015 vs. 2014

In October 2014, construction services operations were expanded by the acquisition of the Link-Line group of companies. Line items in the table above reflect the results of the acquired companies only since the acquisition date. Contribution to consolidated net income from construction services for 2015 increased $2.4 million compared to 2014.

Revenues increased $269.4 million, or 36%, when compared to 2014, due to additional pipe replacement work and the inclusion of a full year of revenues of the acquired companies (an increase of $124 million). NPL revenues in the United States increased over $140 million primarily due to securing contracts to perform accelerated pipeline replacement work for its large utility customers. Favorable weather conditions in several operating areas during the fourth quarter of 2015 also provided an extended construction season. Governmental-mandated pipeline safety-related programs have resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues include contracts with Southwest totaling $104 million in 2015 and $92 million in 2014. Centuri accounts for services provided to Southwest at contractual (market) prices.

Construction expenses increased $250.9 million, or 39%, due primarily to additional pipe replacement work in 2015 and the inclusion of a full year of the acquired companies’ construction costs (an increase of $115 million). The increase in expense includes a $3.4 million loss on a Canadian project, discussed below. General and administrative expense (included in construction expenses) increased approximately $9 million overall, including $8 million from the acquired companies, which included changes that were implemented to match the increased size of the business and its complexity. Offsetting these increases were approximately $5 million of acquisition-related expenses in 2014 that were not incurred in 2015. Gains on sale of equipment (reflected as an offset to construction expenses) were $3.4 million and $6.2 million in 2015 and 2014, respectively.

During 2015, a loss of $3.4 million was recorded on an industrial construction project in Canada (revenue of $22.3 million and construction costs of $25.7 million). Work commenced on this project in March 2015 and was completed in the third quarter. During construction, delays in delivery of critical equipment to the job site resulted in

 

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production inefficiencies and an increase in total estimated project costs. At the end of the first quarter, total project costs were estimated to exceed contract revenues by $5.6 million, and by the end of the third quarter the estimated overrun was $7.7 million. Change orders were being negotiated during the construction period to offset the additional costs. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

Depreciation and amortization expense increased $7.8 million between 2015 and 2014 due primarily to the incremental amortization of finite-lived intangible assets recognized from the acquisition ($3 million) and incremental depreciation from the acquired companies ($4 million).

Net interest deductions were $7.8 million in 2015 compared to $3.8 million in 2014. 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 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 2015 and 2014, revenues from replacement work were 68% and 67%, respectively, of total revenues. Governmental pipeline safety-related programs and U.S. bonus depreciation tax incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.

2014 vs. 2013

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

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 of 2014. Construction revenues include Centuri contracts with Southwest totaling approximately $92 million in 2014 and $88 million in 2013.

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 acquired companies, acquisition costs ($5 million), and changes that were implemented to match the increased size of the business and its complexity. Offsetting these increases was approximately $4 million that was recorded 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 2013 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 acquisition.

 

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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 all periods (2013—2015) for which results of Natural Gas Operations are disclosed above.

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 Rehearing Decision addressed issues raised by Southwest regarding capital structure. Ultimately, the Company was authorized an overall rate of return of 6.56%, and a 10% return on 42.7% common equity in southern Nevada; and 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 initially proposed by Southwest.

General Revenues Adjustment.    As part of the Annual Rate Adjustment (“ARA”) filing in June 2015, Southwest requested recovery of amounts associated with its revenue decoupling mechanism (General Revenues Adjustment, or “GRA”). The ARA, including amounts to recover the regulatory asset associated with this mechanism, was approved in December 2015, with rates effective January 2016. The rate adjustment is expected to recover approximately $19 million of the associated regulatory asset during 2016. There is no impact to net income overall from these recoveries, but there is a favorable impact to cash flows as the regulatory asset balance is recovered.

Infrastructure Replacement Mechanisms.    In January 2014, the PUCN approved final rules for a mechanism to defer and recover certain costs associated with accelerated replacement of non-revenue producing infrastructure. 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. Southwest made a filing in May 2014, referred to as a Gas Infrastructure Replacement (“GIR”) Advance Application, identifying early vintage plastic pipe (“EVPP”) and vintage steel pipe (“VSP”) projects for replacement beginning in 2015. In October 2014, the PUCN approved EVPP replacement expenditures of $14.4 million for 2015. In June 2015, Southwest filed its GIR Advance Application with the PUCN proposing $43.5 million of accelerated pipe replacements for 2016 (subject to the GIR mechanism). Once completed, the annualized revenue requirement associated with the accelerated replacement is estimated at $4.6 million. In October 2015, the PUCN approved the GIR Advance Application, granting Southwest the authority to replace the $43.5 million of infrastructure under the GIR mechanism. Also in October 2015, management filed a rate application to reset the GIR surcharge, based upon project costs deferred through August 2015. In December, the PUCN approved new rates, effective in January 2016, which are expected to result in approximately $4 million in annualized revenues.

 

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Conservation and Energy Efficiency. As part of the ARA filing, Southwest requested recovery of energy efficiency and conservation development and implementation costs, including promotions and incentives for various programs, as originally approved for deferral by the PUCN effective November 2009. While recovery of these costs was approved as part of the most recent general rate case made effective May 2012, amounts incurred subsequent to the effective date continued to be deferred. Approved rates became effective January 2016 and will result in annualized margin increases of $2 million in northern Nevada and $8.7 million in southern Nevada, and also includes amounts representing expected program expenditures for 2016. There is, however, no anticipated impact to net income overall from these recoveries as the amounts collected through customer rates will also be reflected as higher amortization expense.

Expansion and Economic Development Legislation. In February 2015, legislation (“SB 151”) was introduced in Nevada directing the PUCN to adopt regulations authorizing natural gas utilities to expand their infrastructure consistent with a program of economic development. This includes providing natural gas service to unserved and underserved areas in Nevada, as well as attracting and retaining utility customers and accommodating the expansion of existing business customers. SB 151 was signed into law in May 2015. The draft regulations were reviewed by the Legislative Council Bureau and final regulations were approved by the PUCN in January 2016. Southwest is currently assessing and prioritizing potential areas to extend service to based on the legislation and regulations. The process will require the identification of projects, advance approval requests, and development of rates for investment in excess of allowable investment.

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 2015, Southwest made its annual PTY attrition filing, requesting annual revenue increases of $1.8 million in southern California, $499,000 in northern California and $249,000 for South Lake Tahoe. This filing was approved in December 2015 and rates were made effective in January 2016. At the same time, rates were updated to recover, the regulatory asset associated with the revenue decoupling mechanism, or margin tracker. The rate adjustment is expected to recover approximately $18 million of the associated regulatory asset balance during 2016. There is no impact to net income overall from margin tracker recoveries; however, there is a favorable impact to cash flows as the regulatory asset balance is recovered. In addition to the PTY attrition and margin tracking mechanism approvals, the CPUC also approved an adjustment to recover costs associated with Southwest’s

 

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Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plan (“Implementation Plan”), effective January 2016. The Implementation Plan involved replacing 7.1 miles of transmission pipeline in its system, in addition to installing a remote control shut-off valve. This adjustment is expected to result in an annualized margin increase of $1.7 million during 2016.

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 applicable requirements associated with the California GHG emissions reporting 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 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 and for 2016, in the third quarter of 2015. Of those allocated allowances, Southwest must consign a certain percentage to the CARB for auction. The Company can use any allocated allowances that remain after consignment, along with allowances it can purchase through CARB auctions or reserve sales, or through over the counter (“OTC”) purchases with other market participants, to meet its compliance obligations. The CPUC has issued a decision that provides for the regulatory treatment of the program costs and there is no expected impact on earnings.

Arizona Jurisdiction

General Rate Case Status.    The most recent general rate case decision from the Arizona Corporation Commission (“ACC”) in Southwest’s Arizona rate jurisdiction was made effective in January 2012 and authorized 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, relative to an authorized original cost rate base of $1.07 billion. That ACC decision also approved a full revenue decoupling mechanism with a monthly weather adjuster. At that time, Southwest agreed not to file a general rate case prior to April 30, 2016. Given the period covered by the moratorium, Southwest is currently preparing its rate case filing and intends to request approval to continue its decoupled rate design, expand its currently approved infrastructure recovery program, and update its cost of service, including an increase in rate base of approximately 22-24% to reflect various investments Southwest has made since its last rate case to enhance its distribution system. Southwest also intends to include a depreciation study in compliance with the most recent general rate case decision to update depreciation rates. Southwest anticipates filings its general rate case in the second quarter of 2016, shortly after the “stay-out” period has expired.

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). In December 2014, Southwest received an order from the ACC granting pre-approval of Southwest’s application to construct the LNG facility 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. 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. The Company purchased the site for the facility in October 2015 and is preparing the construction

 

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requirements bid package for potential contractors. The contract to construct the facility is currently expected to be in place in the second half of 2016 and construction is expected to take approximately two to three years to complete. The Company anticipates including a proposal for the ratemaking treatment of facility costs as part of its next Arizona rate case filing.

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 were set off from the customer’s home, which is not a traditional configuration. Customers with this configuration were previously 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 (incurred to replace and relocate service lines and meters) 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 January 2014, the Company received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs, which was subsequently revised effective June 2014. Resources continue to be focused on contacting customers within replacement project areas to participate in the Phase II meter relocation. In February 2015, the Company filed to increase the surcharge revenue from $1.5 million to $2.5 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total capital expenditures of $16 million, $6.3 million of which was incurred during 2014. In May 2015, the ACC issued a decision approving the surcharge application, effective in June 2015.

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. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case. 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 were filed in March 2015. In addition to agreeing to rate design changes to encourage longer-term contracts with its shippers, the settlement resulted in an annual revenue increase of $2.4 million, plus a $1.3 million depreciation reduction. The settlement implies 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.

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. A certificate application for the project was filed in June 2014. In May 2015, the FERC issued an order authorizing a Certificate of Public Convenience and Necessity to Paiute to construct and operate the Elko County Expansion Project, and subsequently provided a formal Notice to Proceed. Construction began in the second quarter of 2015 and the project was placed in service in January 2016 as authorized by the FERC. Rates to begin recovering the cost of the

 

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project were implemented in January 2016 and are expected to result in $6 million in revenue annually. The total cost of this project is estimated at approximately $35 million, including remaining costs associated with site restoration along the construction corridor.

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, 2015, under-collections in California resulted in an asset of $3.6 million, and over-collections in Arizona and northern and southern Nevada collectively resulted in a liability of $45.6 million on the Company’s balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during 2015. The lower cost of natural gas, combined with surcharges in place during 2015, fully recovered PGA receivables existing at December 31, 2014. 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 Consolidated Statements of Income 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):

 

		2015				2014
Arizona		$	(3.5	)		$	48.4
Northern Nevada			(2.3	)			10.2
Southern Nevada			(39.8	)			20.4
California			3.6				8.6
		$	(42.0	)		$	87.6

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. This surcharge was reduced in June and July 2015 and was eliminated in August 2015 as the receivable balance was fully collected, while gas cost rates paid to suppliers remained low for the remainder of the year.

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 November 2015, Southwest filed to adjust its quarterly Deferred Energy Account Adjustment rate, which is based upon a twelve-month rolling average, in addition to requesting adjusted Base Tariff Energy rates, both of which were also approved effective January 2016. These new rates are intended to reduce the outstanding liability over a twelve-month period.

 

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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 (up to 25% in the Arizona and California jurisdictions) of its annual normal weather supply needs. For the 2015/2016 heating season, contracts contained in the fixed-price portion of the supply portfolio ranged from slightly under $3 to approximately $4.40 per dekatherm. Southwest makes natural gas purchases not covered by fixed-price contracts under variable-price contracts with firm quantities, and on the spot market. The contract price for these contracts is determined at the beginning of each month to reflect that month’s published first-of-month index price. The contract price of commitments to purchase gas at daily market prices is based on a published daily price index. In either case, the index price is not published or known until the purchase period begins. In late 2013, the Company suspended fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Company evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.

Holding Company Reorganization

In 2015, the Board of Directors (“Board”) of the Company authorized management to evaluate and pursue a holding company reorganization to provide further separation between regulated and unregulated businesses, and to provide additional financing flexibility. Regulatory applications for preapproval of the reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. In January 2016, approval was received by the CPUC, but approvals by the ACC and the PUCN are still pending. The reorganization is subject to approval by the aforementioned state regulatory commissions, consents from various third parties, and final Board approval. Subject to such conditions, the reorganization could become effective in the second half of 2016. In this event, each outstanding share of Southwest Gas common stock would automatically convert into a share of stock in the holding company, on a one-for-one basis.

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. In addition, in March 2015, the Company filed an automatic shelf registration statement for the offer and sale of up to $100 million of its common stock for general corporate purposes and for the noted investment activities, refer to Note 6 – Common Stock and the discussion below. 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. In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (“PATH Act”) was enacted extending the 50% bonus depreciation tax deduction provided for by earlier legislation for qualified property acquired or constructed and placed in-service during 2015 (and additional years as noted below) as well as other tax deductions, credits, and incentives through 2016. See Bonus Depreciation for more information.

Cash Flows

Operating Cash Flows.    Cash flows provided by consolidated operating activities increased $200.7 million between 2015 and 2014. The improvement in operating cash flows was primarily attributable to temporary increases from working capital components overall (notably the collection of deferred purchased gas costs).

 

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Investing Cash Flows.    Cash used in consolidated investing activities decreased $85.8 million in 2015 as compared to 2014. The decline was primarily due to the acquisition of the construction services businesses in 2014. Construction expenditures, including scheduled and accelerated pipe replacement, and to a lesser extent, equipment purchases by Centuri due to the increased replacement construction work of its customers were higher in 2015. In association with the acquisition of construction services businesses, a $9 million working capital adjustment related to a contractual true-up period was paid in the first quarter of 2015.

Financing Cash Flows.    The change in financing cash flows was primarily due to net borrowings in 2014 to finance the construction services acquisition compared to net debt repayments and redemptions in 2015. Repayment of long-term debt in 2015 included $51.2 million of IDRBs, while the prior year included the repayment of $65 million of IDRBs. The long-term debt issuance amounts and the remaining retirements of long-term debt primarily relate to borrowings and repayments under the secured revolving credit facility portion of Centuri’s secured revolving credit and term loan facility. The majority of Centuri’s borrowings in the prior year were associated with the acquisition of construction services businesses. Southwest also issued approximately $35 million in stock under its Equity Shelf Program. See also Note 6 – Common Stock, and the discussion below. Dividends paid increased in 2015 as compared to 2014 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding. While Centuri paid dividends during 2015, the only impact to consolidated cash flows overall was due to the amount paid to the holders of the redeemable noncontrolling interest.

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.

2015 Construction Expenditures

During the three-year period ended December 31, 2015, total gas plant increased from $5 billion to $5.9 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 64,000 meters during the three-year period.

During 2015, construction expenditures for the natural gas operations segment were $438 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 $498 million and provided approximately 97% 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.

2015 Financing Activity

In May 2015, the Company redeemed at par its $31.2 million 2004 5.00% Series B IDRBs originally due in 2033. In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated the redemptions primarily from cash on hand and borrowings under its $300 million credit facility.

In March 2015, the Company filed with the SEC a shelf registration statement which included a prospectus detailing the Company’s plans to sell up to $100 million of the Company’s common stock over a period of time. In March 2015, the Company entered into a Sales Agency Agreement with BNY Mellon Capital Markets, LLC relating to this

 

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issuance and sale of shares of the Company’s common stock (“Equity Shelf Program”). Sales of the shares will continue to be made at market prices prevailing at the time of sale. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

During 2015, 645,225 shares were issued in at-the-market offerings at an average price of $55.05 per share with gross proceeds of $35.5 million, agent commissions of $355,000, and net proceeds of $35.2 million. See Note 6 – Common Stock for more information.

During 2015, the Company issued approximately 209,000 additional shares of common stock collectively through the Restricted Stock/Unit Plan, the Management Incentive Plan, and the Stock Incentive Plan. The Company raised approximately $741,000 from the issuance of shares of common stock through the Stock Incentive Plan.

Three-Year Construction Expenditures, Debt Maturities, and Financing

Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2018 will be between $1.4 billion and $1.6 billion. Of this amount, approximately $460 million is expected to be incurred in 2016. Southwest plans to request regulatory support to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). This will include requests in California and Arizona to expand existing or initiate new programs. If successful, significant replacement activities are expected to continue well beyond the next few years. See also Rates and Regulatory Proceedings for discussion of Nevada infrastructure, California IRRAM, Arizona COYL, and an LNG facility. During the three-year period, cash flows from operating activities of Southwest are expected to provide approximately 60% to 70% 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.

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 2015, the PGA balance went from an under-collected balance of $87.6 million to an over-collected balance of $42 million at December 31, 2015. See PGA Filings for more information.

 

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In March 2015, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2019 and was extended to March 2020. 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 2015 occurred during the fourth quarter and was $180 million ($150 million outstanding on the long-term portion of the credit facility (including $50 million on the commercial paper program), in addition to $30 million outstanding on the short-term portion). At December 31, 2015, $150 million was outstanding on the long-term portion of the credit facility (including $50 million under the commercial paper program), and $18 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 $160 million, $56 million, and $97 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 as noted above. 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, 2015, $50 million was outstanding on the commercial paper program, which is the maximum amount outstanding at any time during the year.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. The term loan facility portion had an initial limit of approximately $150 million, which was reached in 2014 and is in the process of being repaid. No further borrowing is permitted under this portion of the facility. The secured revolving credit facility portion also has a limit of $150 million; amounts borrowed and repaid under this portion of the facility are available to be re-borrowed. The maximum amount outstanding on the Centuri secured revolving credit facility during 2015 was $104.3 million, which occurred in the second quarter. At December 31, 2015, $60.6 million was outstanding on the Centuri secured revolving credit facility. At December 31, 2015, there was approximately $77.4 million, net of letters of credit, available under the line of credit.

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). The Company’s current unsecured long-term debt ratings are all considered investment grade.

The Company’s unsecured long-term debt rating from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as reaffirmed in January 2016. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal. The ratings from ‘AA’ to ‘CCC’ may be modified by the addition of a plus “+” or minus “-” sign to show relative standing within the major rating categories.

 

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The Company’s senior unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is A3 with a stable outlook as reaffirmed in January 2016. 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.

The Company’s senior unsecured ratings including IDRBs from Fitch Ratings (“Fitch”) is A (with a stable outlook) as reaffirmed in July 2015. 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. The modifiers “+” or “-” may be appended to a rating to denote relative status within major rating categories. Such suffixes are not added to the ‘AAA’ obligation rating category, or to corporate finance obligation ratings in the categories below ‘CCC’.

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, 2015, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $2.2 billion in additional debt and meet the leverage ratio requirement. The Company has at least $1 billion 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, 2015, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $75 million in additional debt and meet the leverage ratio requirement. Centuri has at least $15 million of cushion 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 utility 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.

 

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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.

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 Statements 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, 2015 (millions of dollars):

 

		Payments due by period
Contractual Obligations		Total				2016				2017-2018				2019-2020				Thereafter
Operating leases (Note 2)		$	22			$	7			$	8			$	4			$	3
Gas purchase obligations			151				89				55				7				—
Pipeline capacity/storage			1,145				124				211				131				679
Derivatives (Note 13)			5				4				1				—				—
Other commitments			22				12				10				—				—
Long-term debt, including current maturities (Note 7)			1,571				19				57				418				1,077
Interest on long-term debt			899				60				117				111				611
Capital leases (Note 2)			3				2				1				—				—
Other			6				—				1				1				4
Total		$	3,824			$	317			$	461			$	672			$	2,374

In the table above, 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 151 million dekatherms. The fixed-price contracts range in price from slightly under $3 to $4 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.

Debt obligations, in the table above, consists 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, 2015 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 2016 is $39 million and is not included in the table above.

 

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Bonus Depreciation

In December 2015, the PATH Act was enacted extending the 50% bonus depreciation tax deduction for qualified property acquired or constructed and placed in-service during 2015 (and additional years as noted below) as well as other tax deductions, credits, and incentives. The bonus depreciation tax deduction will be phased out over five years. The PATH Act provides for a 50% bonus depreciation tax deduction in 2015 through 2017, 40% in 2018, 30% in 2019, and no deduction after 2019. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provision of the PATH Act deferred the payment of approximately $55 million of federal income taxes for 2015.

Recently Issued Accounting Standards Updates

The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition, going concern, recognition and measurement of financial instruments, the presentation of deferred taxes in the balance sheet, net asset value (“NAV”) used as a practical expedient, and the presentation of debt issuance costs in the balance sheet. 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. While management may make many estimates and judgments, many would not be materially altered, or provide a material impact to the financial statements taken as a whole, if different estimates, or means of estimation were employed. 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

 

Southwest Gas Corporation		28

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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.

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 $39.5 million and future pension expense by $4 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.5 million and expense by $1.6 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $2 million (but has no impact on the pension obligation).

 

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At December 31, 2015, the Company raised the discount rate to 4.50% from a rate of 4.25% at December 31, 2014. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation increased to 3.25% at December 31, 2015 from 2.75% in the prior year. The Company lowered the asset return assumption to 7.25% to be used for 2016 expense from the 7.75% rate used in the previous year. A change to a new actuarial mortality table occurred in 2014, which took into account longer life spans for plan participants; however, just one year later, a decline in the mortality improvement scale was reflected by the same Society of Actuaries, highlighting the nature of estimation. Pension expense for 2016 is estimated to decrease by $6.7 million compared to 2015 because of the new mortality assumption and higher 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, 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. The fair value assigned to the intangible assets acquired and liabilities assumed in 2014, and the determination of goodwill associated with the acquisition, are described in Note 17—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, 2015 are included as exhibits to the 2015 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,”

 

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“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 cost of the Paiute expansion in Elko County, Nevada, forecasted operating cash flows and results of operations, net earnings impacts from gas infrastructure replacement surcharges, funding sources of cash requirements, amounts generally expected to be reflected in 2016 or future period revenues from regulatory rate proceedings, PTY rate adjustments, ARA rates and other surcharges, PGA, and other rate adjustments, sufficiency of working capital and current credit facilities, bank lending practices, the Company’s views regarding its liquidity position, ability to raise funds and receive external financing capacity and the intent and ability to issue the remaining capacity under the Equity Shelf Program, future dividend increases, earnings trends, future Centuri operating revenues, operating income, amortization and interest expense, pension and post-retirement benefits, certain benefits of tax acts, the effect of any rate changes or regulatory proceedings, infrastructure replacement mechanisms and the COYL program, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, recoverability of regulatory assets, the impact of certain legal proceedings, the expectation that goodwill assigned to Brigadier will be deductible for tax purposes, the process required with regard to SB 151 legislation and resulting Nevada regulations, the success in securing remaining approvals of the proposed holding company structure or timing of the related reorganization, 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, variability in volume of gas or transportation service sold to customers, 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, our continued ability to meet consignment and purchase requirements under Cap and Trade regulations, 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, and ability to successfully procure new work, acquisitions and management’s plans related thereto, competition, our ability to raise capital in external financings, our ability to continue to remain within the ratios and other limits subject to our debt covenants, and ongoing evaluations in regard to goodwill and other intangible assets. 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, 2015.

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

 

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forward-looking statements even if experience or future changes show that the indicated results or events will not be realized. We caution you to not rely unduly on any forward-looking statement(s).

Common Stock Price and Dividend Information

 

		2015								2014								Dividends Declared
		High				Low				High				Low				2015				2014
First quarter		$	63.68			$	52.94			$	55.33			$	51.70			$	0.405			$	0.365
Second quarter			59.75				51.69				55.69				50.96				0.405				0.365
Third quarter			58.40				51.26				53.34				47.21				0.405				0.365
Fourth quarter			62.56				50.78				64.20				48.23				0.405				0.365
																		$	1.620			$	1.460

The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 16, 2016, there were 14,095 holders of record of common stock, and the market price of the common stock was $59.56.

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 for its respective businesses. The quarterly common stock dividend declared was 33 cents per share throughout 2013, 36.5 cents per share throughout 2014, and 40.5 cents per share throughout 2015. As a result of its ongoing review of dividend policy, in February 2016, the Board increased the quarterly dividend from 40.5 cents to 45 cents per share, effective with the June 2016 payment. This marks the tenth consecutive year in which the dividend was increased. The Board’s policy is to target a dividend payout ratio that allows the Company to maintain its strong credit ratings and effectively fund its rate base growth and is consistent with the local distribution company peer group average. The timing and amount of any increases will be based on the Board’s continual 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.

 

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except par value)

 

December 31,		2015				2014
ASSETS
Utility plant:
Gas plant		$	5,854,917			$	5,556,599
Less: accumulated depreciation			(2,084,007	)			(1,973,098	)
Acquisition adjustments, net			370				550
Construction work in progress			119,805				74,332
Net utility plant (Note 2)			3,891,085				3,658,383
Other property and investments (Note 1)			313,531				326,743
Restricted cash			—				821
Current assets:
Cash and cash equivalents			35,997				39,566
Accounts receivable, net of allowances (Note 3)			314,512				281,824
Accrued utility revenue			74,700				73,900
Income taxes receivable, net			34,175				21,853
Deferred income taxes, net (Note 12)			—				2,109
Deferred purchased gas costs (Note 4)			3,591				87,556
Prepaids and other current assets (Notes 1, 4, and 13)			95,199				99,803
Total current assets			558,174				606,611
Noncurrent assets:
Goodwill (Note 1)			126,145				143,160
Deferred income taxes (Note 12)			428				—
Deferred charges and other assets (Notes 2, 4, and 13)			469,322				472,579
Total noncurrent assets			595,895				615,739
Total assets		$	5,358,685			$	5,208,297

 

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CONSOLIDATED BALANCE SHEETS – Continued

 

December 31,		2015				2014
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—47,377,575 and 46,523,184 shares) (Note 11)		$	49,007			$	48,153
Additional paid-in capital			896,448				851,381
Accumulated other comprehensive income (loss), net (Note 5)			(50,268	)			(50,175	)
Retained earnings			699,221				639,164
Total Southwest Gas Corporation equity			1,594,408				1,488,523
Noncontrolling interest			(2,083	)			(2,257	)
Total equity			1,592,325				1,486,266
Redeemable noncontrolling interest (Note 16)			16,108				20,042
Long-term debt, less current maturities (Note 7)			1,551,204				1,631,374
Total capitalization			3,159,637				3,137,682
Commitments and contingencies (Note 9)
Current liabilities:
Current maturities of long-term debt (Note 7)			19,475				19,192
Short-term debt (Note 8)			18,000				5,000
Accounts payable			164,857				167,988
Customer deposits			72,631				71,546
Income taxes payable, net			940				—
Accrued general taxes			47,337				44,339
Accrued interest			16,173				16,468
Deferred purchased gas costs (Note 4)			45,601				—
Other current liabilities (Notes 2, 4, and 13)			150,031				145,584
Total current liabilities			535,045				470,117
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits, net (Note 12)			769,445				723,688
Accumulated removal costs (Note 4)			303,000				304,000
Other deferred credits and other long-term liabilities (Notes 2, 4, 10, and 13)			591,558				572,810
Total deferred income taxes and other credits			1,664,003				1,600,498
Total capitalization and liabilities		$	5,358,685			$	5,208,297

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share amounts)

 

Year Ended December 31,		2015				2014				2013
Operating revenues:
Gas operating revenues		$	1,454,639			$	1,382,087			$	1,300,154
Construction revenues			1,008,986				739,620				650,628
Total operating revenues			2,463,625				2,121,707				1,950,782
Operating expenses:
Net cost of gas sold			563,809				505,356				436,001
Operations and maintenance			393,199				383,732				384,914
Depreciation and amortization			270,111				253,027				236,817
Taxes other than income taxes			49,393				47,252				45,551
Construction expenses			898,781				647,857				573,284
Total operating expenses			2,175,293				1,837,224				1,676,567
Operating income			288,332				284,483				274,215
Other income and (expenses):
Net interest deductions (Notes 7 and 8)			(71,879	)			(72,069	)			(63,700	)
Other income (deductions)			2,879				7,107				12,300
Total other income and (expenses)			(69,000	)			(64,962	)			(51,400	)
Income before income taxes			219,332				219,521				222,815
Income tax expense (Note 12)			79,902				78,373				77,942
Net income			139,430				141,148				144,873
Net income (loss) attributable to noncontrolling interests			1,113				22				(447	)
Net income attributable to Southwest Gas Corporation		$	138,317			$	141,126			$	145,320
Basic earnings per share (Notes 1 and 15)		$	2.94			$	3.04			$	3.14
Diluted earnings per share (Notes 1 and 15)		$	2.92			$	3.01			$	3.11
Average number of common shares outstanding			46,992				46,494				46,318
Average shares outstanding (assuming dilution)			47,383				46,944				46,758

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of dollars)

 

Year Ended December 31,		2015				2014				2013
Net Income		$	139,430			$	141,148			$	144,873
Other comprehensive income (loss), net of tax
Defined benefit pension plans (Notes 5 and 10):
Net actuarial gain (loss)			(18,922	)			(107,661	)			62,214
Amortization of prior service cost			828				220				220
Amortization of net actuarial loss			21,316				14,667				21,190
Prior service cost			—				(4,130	)			—
Regulatory adjustment			(3,500	)			86,991				(76,651	)
Net defined benefit pension plans			(278	)			(9,913	)			6,973
Forward-starting interest rate swaps:
Amounts reclassified into net income (Notes 5 and 13)			2,073				2,073				2,074
Net forward-starting interest rate swaps			2,073				2,073				2,074
Foreign currency translation adjustments			(1,954	)			(659	)			—
Total other comprehensive income (loss), net of tax			(159	)			(8,499	)			9,047
Comprehensive income			139,271				132,649				153,920
Comprehensive income (loss) attributable to noncontrolling interests			1,047				—				(447	)
Comprehensive income attributable to Southwest Gas Corporation		$	138,224			$	132,649			$	154,367

The accompanying notes are an integral part of these statements.

 

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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of dollars)

 

Year Ended December 31,		2015				2014				2013
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income		$	139,430			$	141,148			$	144,873
Adjustments to reconcile net income to netcash provided by operating activities:
Depreciation and amortization			270,111				253,027				236,817
Deferred income taxes			48,785				64,309				68,639
Changes in current assets and liabilities:
Accounts receivable, net of allowances			(39,850	)			(3,683	)			(22,556	)
Accrued utility revenue			(800	)			(1,200	)			(700	)
Deferred purchased gas costs			129,566				(69,339	)			(111,143	)
Accounts payable			(3,491	)			(41,499	)			27,668
Accrued taxes			(8,405	)			(13,573	)			925
Other current assets and liabilities			18,300				23,379				5,084
Gains on sale			(3,102	)			(6,171	)			(4,112	)
Changes in undistributed stock compensation			2,914				7,973				6,958
AFUDC			(3,008	)			(1,995	)			(2,274	)
Changes in other assets and deferred charges			(14,166	)			(21,732	)			(21,719	)
Changes in other liabilities and deferred credits			10,863				15,779				17,749
Net cash provided by operating activities			547,147				346,423				346,209

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued

 

Year Ended December 31,		2015				2014				2013
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions			(488,000	)			(396,898	)			(364,276	)
Acquisition of businesses, net of cash acquired			(9,261	)			(190,497	)			—
Restricted cash			785				1,233				—
Changes in customer advances			18,300				20,363				7,773
Miscellaneous inflows			8,354				11,611				8,465
Miscellaneous outflows			—				(1,400	)			—
Net cash used in investing activities			(469,822	)			(555,588	)			(348,038	)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net			35,396				405				1,635
Dividends paid			(74,248	)			(66,275	)			(59,535	)
Centuri distribution to redeemable noncontrolling interest			(99	)			—				—
Issuance of long-term debt, net			135,816				269,228				311,290
Retirement of long-term debt			(187,973	)			(139,155	)			(137,013	)
Change in credit facility and commercial paper			—				140,000				(101,000	)
Change in short-term debt			13,000				5,000				1,999
Principal payments on capital lease obligations			(1,420	)			(434	)			—
Other			41				(1,257	)			—
Net cash provided by (used in) financing activities			(79,487	)			207,512				17,376
Effects of currency translation on cash and cash equivalents			(1,407	)			142				—
Change in cash and cash equivalents			(3,569	)			(1,511	)			15,547
Cash and cash equivalents at beginning of period			39,566				41,077				25,530
Cash and cash equivalents at end of period		$	35,997			$	39,566			$	41,077
Supplemental information:
Interest paid, net of amounts capitalized		$	66,623			$	65,552			$	58,730
Income taxes paid		$	43,225			$	24,247			$	6,850

The accompanying notes are an integral part of these statements.

 

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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
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 10)															6,973												6,973
Amounts reclassified to net income, net of tax (Notes 5 and 13)															2,074												2,074
Dividends declared
Common: $1.32 per share																			(61,975	)							(61,975	)
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
Redemption value adjustments (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 10)															(9,913	)											(9,913	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)															2,073												2,073
Dividends declared
Common: $1.46 per share																			(68,715	)							(68,715	)

 

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CONSOLIDATED STATEMENTS OF EQUITY – Continued

 

		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
DECEMBER 31, 2014			46,523			$	48,153			$	851,381			$	(50,175	)		$	639,164			$	(2,257	)		$	1,486,266			$	20,042
Common stock issuances			854				854				39,290																40,144
Net income (loss)																			138,317				174				138,491				939
Redemption value adjustments (Note 16)											5,777								(1,069	)							4,708				(4,708	)
Foreign currency exchange translation adj.															(1,888	)											(1,888	)			(66	)
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10)															(278	)											(278	)
Amounts reclassified to net income, net of tax (Notes 5 and 13)															2,073												2,073
Centuri distribution to redeemable noncontrolling interest																															(99	)
Dividends declared Common: $1.62 per share																			(77,191	)							(77,191	)
DECEMBER 31, 2015			47,377	*		$	49,007			$	896,448			$	(50,268	)		$	699,221			$	(2,083	)		$	1,592,325			$	16,108

*

At December 31, 2015, 3.6 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 17,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10).

The accompanying notes are an integral part of these statements.

 

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Notes to Consolidated Financial Statements

Note 1 – Summary of Significant Accounting Policies

Nature of Operations.    Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas 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 96.6% 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 occur in 20 major markets in the U.S. and within the provinces of British Columbia and Ontario in Canada, and are generally conducted under the business names of NPL Construction Co. (“NPL”), Link-Line Contractors Ltd. (“Link-Line”), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). The Company acquired Link-Line, W.S. Nicholls, and Brigadier in October 2014. See Note 17 – Acquisition of Construction Services Businesses for more information.

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 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.

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).

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 totaled $14.7 million and $10.8 million at December 31, 2014 and 2015, respectively. Both periods include the impacts of foreign currency exchange translation adjustments. No dividends were paid during 2015. The equity method investment in Western is included in Other Property and Investments in the Consolidated Balance Sheets. Centuri’s maximum exposure to loss as a result of its involvement with Western is estimated at

 

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$14.7 million. 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 recorded earnings of $310,000 from this investment in 2015 which is included in Other Income (deductions) in the Consolidated Statements of Income.

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.

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):

 

		2015				2014
Centuri property, equipment, and intangibles		$	423			$	405
Centuri accumulated provision for depreciation and amortization			(221	)			(187	)
Net cash surrender value of COLI policies			99				99
Other property			13				10
Total		$	314			$	327

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 materials and operating supplies of $24 million in 2015 and $23 million in 2014 (carried at weighted average cost), and also includes natural gas stored underground and liquefied natural gas, in addition to prepaid assets.

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, 2015, 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,

 

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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, 2015 and 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.

Significant non-cash investing activities for the natural gas operations segment included the following: Upon contract expiration, customer advances of approximately $3.1 million, $8.1 million, and $9.3 million during 2015, 2014, and 2013, respectively, were applied as contributions toward utility construction activity and represent non-cash investing activity. In 2014, investing activities included an $18.9 million non-cash investing outflow due to the equity of the noncontrolling interest associated with businesses acquired. In addition, a non-cash investing outflow activity of $10.8 million in 2014 related to acquisition consideration payable.

Goodwill.    Goodwill is assessed for impairment annually in October, as required by U.S. GAAP, or otherwise, if circumstances indicate impairment to the carrying value of goodwill may have occurred. The goodwill impairment analysis may start with an assessment of qualitative factors (Step 0) to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the qualitative factors, management determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or if management does not perform a qualitative assessment, a Step 1 impairment test will be performed. Management considered the qualitative factors and the evidence obtained and determined that it is not more likely than not that the fair value of any reporting unit is less than its carrying amount in 2014 or 2015. Thus, no impairment was recorded in 2014 or 2015. The acquisition date adjustment shown in the table below was recorded in the first quarter of 2015. No acquisition date adjustments occurred subsequently. The business of Brigadier was acquired via asset purchase. Therefore, goodwill assigned to Brigadier is expected to be deductible for tax purposes, resulting in an after-tax value of $4.9 million. All other goodwill associated with the acquisition is not deemed deductible for tax purposes.

 

		Natural Gas Operations				Construction Services				Consolidated
(In thousands of dollars)
December 31, 2014		$	10,095			$	133,065			$	143,160
Acquisition date adjustment			—				1,380				1,380
Foreign currency translation adjustment			—				(18,395	)			(18,395	)
December 31, 2015		$	10,095			$	116,050			$	126,145

Intangible Assets.    Intangible assets (other than goodwill) 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 are primarily associated with the 2014 acquisition of construction services businesses and have finite lives.

 

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Centuri has $36.8 million and $48.2 million of intangible assets (varies due to foreign currency translation) at December 31, 2015 and 2014, respectively, as detailed in the following table (thousands of dollars):

 

December 31, 2015		Gross Carrying Amount				Accumulated Amortization				Net Carrying Amount
Customer relationships		$	31,226			$	(2,070	)		$	29,156
Trade names and trademarks			8,621				(1,331	)			7,290
Customer contracts backlog			1,606				(1,606	)			—
Noncompete agreement			437				(110	)			327
Total		$	41,890			$	(5,117	)		$	36,773
December 31, 2014		Gross Carrying Amount				Accumulated Amortization				Net Carrying Amount
Customer relationships		$	37,059			$	(524	)		$	36,535
Trade names and trademarks			10,208				(241	)			9,967
Customer contracts backlog			1,912				(724	)			1,188
Noncompete agreement			519				(34	)			485
Total		$	49,698			$	(1,523	)		$	48,175

The intangible assets (other than goodwill and software-related intangibles) are included in Other property and investments in the Consolidated Balance Sheets. The estimated future amortization of the intangible assets for the next five years is as follows (in thousands):

 

2016		$	2,809
2017			2,809
2018			2,605
2019			1,971
2020			1,906

See Note 2 – Utility Plant and Leases for additional information regarding natural gas operations intangible assets.

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 (“SEC”) position on presentation of these amounts, management reclassifies estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the Consolidated Balance Sheets. Amounts fluctuate between periods depending on the level of replacement work performed, the estimated cost of removal in rates and the actual cost of removal experienced.

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.

 

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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. 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. During 2015, construction expenses were impacted by a loss reserve on an industrial construction project in Canada recognized earlier in the year, in the amount of $7.7 million. Delays in delivery of critical equipment to the job site resulted in production inefficiencies and an increase in total project costs. Work commenced on this project in March 2015 and was completed in the third quarter. In situations where losses on a project are possible, accounting rules and adopted policies require that future costs to complete the project be estimated and a loss recognized currently, but potential incremental revenue to cover such costs is recognized only if and when change orders are formally approved. In October, Centuri and the general contractor agreed to mediation to attempt to resolve open change orders. In December 2015, a final settlement of approximately $4 million was reached and the overall loss on this project was reduced to $3.4 million.

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

 

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amortized over the weighted-average lives of the new issues and become a component of interest expense. See also discussion regarding Accumulated Removal Costs above.

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.

 

		2015				2014				2013
(In thousands)
AFUDC:
Debt portion		$	1,666			$	1,228			$	1,260
Equity portion			3,008				1,995				2,274
AFUDC capitalized as part of utility plant		$	4,674			$	3,223			$	3,534

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):

 

		2015				2014				2013
Change in COLI policies		$	(500	)		$	5,300			$	12,400
Interest income			2,173				2,602				461
Equity AFUDC			3,008				1,995				2,274
Foreign currency transaction gain (loss)			(824	)			(178	)			—
Equity in earnings of unconsolidated investment - Western			310				107				—
Miscellaneous income and (expense)			(1,288	)			(2,719	)			(2,835	)
Total other income (deductions)		$	2,879			$	7,107			$	12,300

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

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 are included in other income (expense). 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.

 

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Earnings Per Share.    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.

 

		2015				2014				2013
(In thousands)
Average basic shares			46,992				46,494				46,318
Effect of dilutive securities:
Stock options			8				17				26
Performance shares			171				215				231
Restricted stock units			212				218				183
Average diluted shares			47,383				46,944				46,758

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. In accordance with the update, 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. In April 2015, the FASB voted to propose, and in July 2015 it approved, a one-year deferral of the effective date (annual periods beginning after December 15, 2017), but to permit entities to adopt one year earlier if they choose (i.e., the original effective date). The FASB decided, based on its outreach to various stakeholders and the forthcoming exposure drafts, which amend the update, that a deferral is necessary to provide adequate time to effectively implement the update. The Company plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2018. The Company is evaluating what impact this update might have on its consolidated financial statements and disclosures.

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 assess 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 and changes thereto are not expected to have a material impact on the Company’s disclosures.

In April 2015, the FASB issued the update “Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs.” To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. While balance sheet presentation is impacted by the update, the recognition and measurement of debt issuance costs are not.

 

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Retrospective application of the update is required. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2015. Early adoption of the amendments in this update is permitted for financial statements that have not been previously issued. The Company adopted this update as of December 31, 2015, as permitted. See Note 7 – Long-Term Debt for additional information.

In May 2015, the FASB issued the update “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent).” This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the net asset value per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments that calculate net asset value per share (or its equivalent), but for which the practical expedient is not applied, will continue to be included in the fair value hierarchy. The update removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. A reporting entity should continue to disclose information on investments for which fair value is measured at net asset value as a practical expedient to help users understand the nature and risks of the investments and whether the investments, if sold, are probable of being sold at amounts different from net asset value. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods thereafter. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 10 – Pension and Other Postretirement Benefits for additional information.

In November 2015, the FASB issued the update “Income Taxes (Topic 740)” in order to simplify the presentation of deferred income taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The previous guidance required an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. This update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted and the Company adopted this update as of December 31, 2015. See Note 12 – Income Taxes for additional information.

In January 2016, the FASB issued the update “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” in order to improve the recognition and measurement of financial instruments. The update makes targeted improvements to existing U.S. GAAP by: 1) requiring equity investments to be measured at fair value with changes in fair value recognized in net income; 2) requiring the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes; 3) requiring separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements; 4) eliminating the requirement to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost on the balance sheet; and 5) requiring a reporting organization to present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when the organization has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. All entities can early adopt the provision to record fair value changes for financial liabilities under the fair value option resulting from instrument-specific credit risk in other comprehensive income. The Company is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.

 

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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.

Note 2 – Utility Plant and Leases

Net utility plant as of December 31, 2015 and 2014 was as follows (thousands of dollars):

 

December 31,		2015				2014
Gas plant:
Storage		$	22,944			$	22,531
Transmission			312,996				312,300
Distribution			4,935,730				4,655,640
General			365,865				356,072
Software and software-related intangibles			203,323				196,035
Other			14,059				14,021
			5,854,917				5,556,599
Less: accumulated depreciation			(2,084,007	)			(1,973,098	)
Acquisition adjustments, net			370				550
Construction work in progress			119,805				74,332
Net utility plant		$	3,891,085			$	3,658,383

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, based on the processes of regulatory proceedings and related regulatory commission approvals and/or mandates. In 2015, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2014 and 2013 also approximated 3.6% on average.

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

 

		2015				2014				2013
Depreciation and amortization expense		$	201,233			$	194,360			$	185,283

Included in the figures above is amortization of intangibles of $12.7 million in 2015, $11.7 million in 2014, and $10.3 million in 2013.

Operating Leases and Rentals.    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):

 

		2015				2014				2013
Southwest Gas		$	4,186			$	5,330			$	8,308
Centuri			45,849				30,012				27,118
Consolidated rental payments/lease expense		$	50,035			$	35,342			$	35,426

 

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The following is a schedule of future minimum lease payments for significant non-cancelable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2015 (thousands of dollars):

 

Year Ending December 31,
2016		$	6,836
2017			4,732
2018			2,993
2019			2,110
2020			1,473
Thereafter			3,583
Total minimum lease payments		$	21,727

Capital Leases.    Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2015 and 2014 are as follows (thousands of dollars):

 

December 31,		2015				2014
Capital leases of equipment		$	4,584			$	5,763
Less: accumulated amortization			(1,043	)			(287	)
Net capital leases		$	3,541			$	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, 2015 (thousands of dollars):

 

Year Ending December 31,
2016		$	1,469
2017			869
2018			494
2019			21
2020			—
Thereafter			—
			2,853
Less: amount representing interest			(223	)
Total minimum lease payments		$	2,630

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, 2015 and 2014, and the percentage of customers in each of the three states.

 

		December 31, 2015				December 31, 2014
Gas utility customer accounts receivable balance (in thousands)		$	151,775			$	136,148

 

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		December 31, 2015
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, 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
Additions charged to expense			4,113
Accounts written off, less recoveries			(4,098	)
Balance, December 31, 2015		$	2,270

At December 31, 2015, the construction services segment (Centuri) had $162 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs have been insignificant and are not reflected in the table above.

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.

 

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

 

December 31,		2015				2014
Regulatory assets:
Accrued pension and other postretirement benefit costs (1)		$	384,647			$	390,293
Unrealized net loss on non-trading derivatives (Swaps) (2)			5,486				5,425
Deferred purchased gas costs (3)			3,591				87,556
Accrued purchased gas costs (4)			—				2,600
Unamortized premium on reacquired debt (5)			21,511				20,478
Other (6)			73,022				72,132
			488,257				578,484
Regulatory liabilities:
Deferred purchased gas costs (3)			(45,601	)			—
Accumulated removal costs			(303,000	)			(304,000	)
Accrued purchased gas costs (4)			(10,400	)			—
Deferred gain on southern Nevada division operations facility (7)			—				(115	)
Unamortized gain on reacquired debt (8)			(10,325	)			(10,862	)
Other (9)			(36,631	)			(34,233	)
Net regulatory assets		$	82,300			$	229,274

 

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

(2)

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

 

Instrument		Balance Sheet Location		2015				2014
Swaps		Deferred charges and other assets		$	1,219			$	363
Swaps		Prepaids and other current assets			4 ,267				5,062

 

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

(4)	Asset included in Prepaids and other current assets and liability included in Other current liabilities on the Consolidated Balance Sheets. Balance recovered or refunded on an ongoing basis.

(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)	The amortization period ended October 2015.

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

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

 

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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, as well as the Redeemable Noncontrolling Interest.

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

 

(Thousands of dollars)						2015												2014												2013
		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
Defined benefit pension plans:
Net actuarial gain/(loss)		$	(30,519	)		$	11,597			$	(18,922	)		$	(173,646	)		$	65,985			$	(107,661	)		$	100,345			$	(38,131	)		$	62,214
Amortization of prior service cost			1,335				(507	)			828				355				(135	)			220				355				(135	)			220
Amortization of net actuarial (gain)/loss			34,381				(13,065	)			21,316				23,656				(8,989	)			14,667				34,177				(12,987	)			21,190
Prior service cost			—				—				—				(6,661	)			2,531				(4,130	)			—				—				—
Regulatory adjustment			(5,646	)			2,146				(3,500	)			140,308				(53,317	)			86,991				(123,630	)			46,979				(76,651	)
Pension plans other comprehensive income (loss)			(449	)			171				(278	)			(15,988	)			6,075				(9,913	)			11,247				(4,274	)			6,973
Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities):
Amounts reclassified into net income			3,344				(1,271	)			2,073				3,345				(1,272	)			2,073				3,345				(1,271	)			2,074
FSIRS other comprehensive income (loss)			3,344				(1,271	)			2,073				3,345				(1,272	)			2,073				3,345				(1,271	)			2,074
Foreign currency translation adjustments:
Translation adjustments			(1,954	)			—				(1,954	)			(659	)			—				(659	)			—				—				—
Foreign currency other comprehensive income (loss)			(1,954	)			—				(1,954	)			(659	)			—				(659	)			—				—				—
Total other comprehensive income (loss)		$	941			$	(1,100	)		$	(159	)		$	(13,302	)		$	4,803			$	(8,499	)		$	14,592			$	(5,545	)		$	9,047

 

(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.

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		$	25,000
SERP net actuarial loss			1,400
PBOP net actuarial loss			400
PBOP prior service cost			1,300

 

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Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, included in AOCI at December 31, 2015, 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 10)												FSIRS (Note 13)												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, 2014		$	(57,211)			$	21,740			$	(35,471	)		$	(22,688	)		$	8,621			$	(14,067	)		$	(637	)		$	—			$	(637	)		$	(50,175	)
Net actuarial gain/(loss)			(30,519	)			11,597				(18,922	)			—				—				—				—				—				—				(18,922	)
Translation adjustments			—				—				—				—				—				—				(1,954	)			—				(1,954	)			(1,954	)
Other comprehensive income before reclassifications			(30,519	)			11,597				(18,922	)			—				—				—				(1,954	)			—				(1,954	)			(20,876	)
FSIRS amounts reclassified from AOCI (1)			—				—				—				3,344				(1,271	)			2,073				—				—				—				2,073
Amortization of prior service cost (2)			1,335				(507	)			828				—				—				—				—				—				—				828
Amortization of net actuarial loss (2)			34,381				(13,065	)			21,316				—				—				—				—				—				—				21,316
Regulatory adjustment (3)			(5,646	)			2,146				(3,500	)			—				—				—				—				—				—				(3,500	)
Net current period other comprehensive income (loss)			(449	)			171				(278	)			3,344				(1,271	)			2,073				(1,954	)			—				(1,954	)			(159	)
Less: Translation adjustment attributable to redeemable noncontrolling interest			—				—				—				—				—				—				(66	)			—				(66	)			(66	)
Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation			(449	)			171				(278	)			3,344				(1,271	)			2,073				(1,888	)			—				(1,888	)			(93	)
Ending Balance AOCI December 31, 2015		$	(57,660	)		$	21,911			$	(35,749	)		$	(19,344	)		$	7,350			$	(11,994	)		$	(2,525	)		$	—			$	(2,525	)		$	(50,268	)

 

(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 10 – 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).

 

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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, 2015 and 2014:

Amounts Recognized in AOCI (Before Tax)

(Thousands of dollars)

 

		2015				2014
Net actuarial (loss) gain		$	(435,269	)		$	(439,131	)
Prior service cost			(7,038	)			(8,373	)
Less: amount recognized in regulatory assets			384,647				390,293
Recognized in AOCI		$	(57,660	)		$	(57,211	)

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

Note 6 – Common Stock

On March 10, 2015, the Company filed with the Securities Exchange Commission (“SEC”) an automatic shelf registration statement on Form S-3 (File No. 333-202633), which became effective upon filing, for the offer and sale of up to $100,000,000 of the Company’s common stock from time to time in at-the-market offerings under the prospectus included therein and in accordance with the Sales Agency Agreement, dated March 10, 2015, between the Company and BNY Mellon Capital Markets, LLC (the “Equity Shelf Program”). During 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds to the Company of $35,167,584, net of $355,228 in agent commissions. No sales occurred in the fourth quarter of 2015. As of December 31, 2015, the Company had up to $64,477,188 of common stock available for sale under the program. Net proceeds from the sale of shares of common stock under the Equity Shelf Program are intended for general corporate purposes, including the acquisition of property for the construction, completion, extension or improvement of pipeline systems and facilities located in and around the communities Southwest serves.

In addition, during 2015, the Company issued approximately 209,000 shares of common stock through the Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan.

Note 7 – Long-Term Debt

Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2015 and December 31, 2014 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

 

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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 utilized 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.

 

December 31,		2015								2014
		Carrying Amount				Market Value				Carrying Amount				Market Value
(Thousands of dollars)
Debentures:
Notes, 4.45%, due 2020		$	125,000			$	130,273			$	125,000			$	133,403
Notes, 6.1%, due 2041			125,000				141,581				125,000				157,290
Notes, 3.875%, due 2022			250,000				253,600				250,000				262,030
Notes, 4.875%, due 2043			250,000				251,483				250,000				280,903
8% Series, due 2026			75,000				97,035				75,000				102,296
Medium-term notes, 7.59% series, due 2017			25,000				26,253				25,000				27,573
Medium-term notes, 7.78% series, due 2022			25,000				29,855				25,000				31,144
Medium-term notes, 7.92% series, due 2027			25,000				31,890				25,000				33,695
Medium-term notes, 6.76% series, due 2027			7,500				8,684				7,500				9,156
Unamortized discount and debt issuance costs			(6,137	)							(6,604	)
			901,363								900,896
Revolving credit facility and commercial paper			150,000				150,000				150,000				150,000
Industrial development revenue bonds:
Variable-rate bonds:
Tax-exempt Series A, due 2028			50,000				50,000				50,000				50,000
2003 Series A, due 2038			50,000				50,000				50,000				50,000
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
5.00% 2004 Series B, due 2033			—				—				31,200				31,223
4.85% 2005 Series A, due 2035			100,000				100,452				100,000				100,071
4.75% 2006 Series A, due 2036			24,855				25,130				24,855				25,399
Unamortized discount and debt issuance costs			(3,946	)							(5,964	)
			320,909								370,091
Centuri term loan facility			112,571				112,665				142,071				143,021
Unamortized debt issuance costs			(692	)							(816	)
			111,879								141,255
Centuri secured revolving credit facility			60,627				60,724				57,196				57,320
Centuri other debt obligations			25,901				26,059				31,128				31,127
			1,570,679								1,650,566
Less: current maturities			(19,475	)							(19,192	)
Long-term debt, less current maturities		$	1,551,204							$	1,631,374

 

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In March 2015, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2019, but was extended to March 2020. The Company will continue to use $150 million of the facility as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the credit facility are calculated at either the 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, 2015, 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, 2015, $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 1.45% at December 31, 2015. Borrowings under the credit facility ranged from none during the second quarter of 2015 to a high of $180 million during the fourth quarter of 2015. With regard to the short-term portion of the credit facility, there was $18 million outstanding at December 31, 2015 and $5 million outstanding at December 31, 2014. (See Note 8 – Short-Term Debt).

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, 2015, and as noted above, $50 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 1.01% at December 31, 2015.

In May 2015, the Company redeemed at par the $31.2 million 5.00% 2004 Series B IDRBs originally due in 2033. The Company facilitated the redemption primarily from cash on hand and borrowings under its $300 million credit facility.

In September 2015, the Company redeemed at par the $20 million 5.25% 2003 Series D IDRBs originally due in 2038. The Company facilitated the redemption primarily from cash on hand and borrowings under its $300 million credit facility.

Centuri has a $300 million secured revolving credit and term loan facility that is scheduled to expire in October 2019. This facility includes a revolving credit facility and a term loan facility. The term loan facility had an initial limit of approximately $150 million, which was reached in 2014 and is in the process of being repaid. No further borrowing is permitted under the term loan facility. In January 2016, administrative amendments were made to the revolving credit and term loan facility with no impact to borrowing capacity, due dates, or interest provisions. The revolving credit facility has a limit of $150 million; amounts borrowed and repaid under the revolving credit facility are available to be re-borrowed. The revolving credit and term loan 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, 2015 totaled $437 million.

Interest rates for Centuri’s $300 million secured revolving credit and term loan 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

 

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commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the revolving credit facility ranged from a low of $60.6 million during December 2015 to a high of $105.2 million during May 2015. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.46% at December 31, 2015.

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

 

		December 31, 2015				December 31, 2014
2003 Series A			0.87	%			0.85	%
2008 Series A			0.87	%			0.90	%
2009 Series A			0.75	%			0.89	%
Tax-exempt Series A			0.81	%			0.84	%

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):

 

2016		$	19,475
2017			42,245
2018			14,906
2019			142,452
2020			275,238

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, 2015, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue approximately $2.2 billion in additional debt and meet the leverage ratio requirement. The Company has at least $1 billion 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, 2015, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $75 million in additional debt and meet the leverage ratio requirement. Centuri has at least $15 million of cushion relating to the minimum fixed charge ratio coverage requirement.

Early Adoption of Accounting Standards Update (“ASU”) No. 2015-03. As of December 31, 2015, the Company adopted FASB ASU No. 2015-03 “Interest-Imputation of Interest (subtopic 835-30)”. To simplify presentation of debt issuance costs, the amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The adoption of this update is considered a change in an accounting principle. Upon adoption, the 2014 amounts in the Consolidated Balance Sheets were restated for Long-term debt (from $1,637,592,000 to $1,631,374,000), Deferred charges and other assets (from $478,625,000 to $472,579,000), and Prepaids and other current assets (from $99,975,000 to $99,803,000). The 2014 amounts in the debt listing table for unamortized discount and debt issuance costs for debentures and IDRBs previously included only amounts

 

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associated with unamortized discount, ($5,223,000) for debentures and ($1,943,000) for IDRBs. The difference between the associated figures in the debt listing table and these figures are amounts associated with unamortized debt issue costs reclassified in accordance with the update.

In a related update, the SEC provided guidance that for line-of-credit (“LOC”) arrangements, companies could elect to present debt issuance costs within assets, regardless of whether there is an outstanding balance on such borrowings. Making such an election may make presentations less confusing as net negative balances would otherwise result in cases when there are no outstanding LOC borrowings but associated issuance costs are still being amortized. Therefore, for LOC arrangements, such as Southwest’s revolving credit facility and Centuri’s secured revolving credit portion of its facility, the Company has elected, as permitted, to continue to recognize unamortized debt issuance costs within its asset categories and no such amounts have been reclassified. The unamortized debt issuance costs associated with the term loan portion of Centuri’s $300 million facility, ($816,000), have been reclassified as a deduction from the related 2014 debt balance. The debt listing table has been updated to reflect these changes based on the elections made.

Note 8 – Short-Term Debt

As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2020, of which $150 million has been designated by management for working capital purposes. The Company had $18 million in short-term borrowings outstanding at December 31, 2015 and $5 million in short-term borrowings outstanding at December 31, 2014. The effective interest rate on the short-term portion of the credit facility was 1.37% at December 31, 2015.

Note 9 – Commitments and Contingencies

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

The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company 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 2015 to July 2016, these liability insurance policies require Southwest to be responsible for the first $1 million (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, as necessary.

Note 10 – Pension and Other Postretirement Benefits

Southwest has an Employees’ Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches 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):

 

		2015				2014				2013
Employee Investment Plan cost		$	5,072			$	4,816			$	4,850

 

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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 executive 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 Consolidated 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.

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.

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, 2015, 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

 

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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. 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 higher interest rate environment for high-quality fixed income investments, the Company increased the discount rate at December 31, 2015 from 2014. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also raised (consistent with management’s expectations overall). The asset return assumption (which impacts the following year’s expense) was lowered. The rates are presented in the table below:

 

		December 31, 2015				December 31, 2014
Discount rate			4.50	%			4.25	%
Weighted-average rate of compensation increase			3.25	%			2.75	%
Asset return assumption			7.25	%			7.75	%

Pension expense for 2016 is estimated to decrease by $6.7 million compared to 2015 notably due to the higher discount rate and lower mortality projection. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.

 

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

 

		2015												2014
		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)		$	1,060,240			$	41,176			$	72,202			$	886,714			$	36,143			$	58,020
Service cost			25,123				320				1,641				21,360				292				1,101
Interest cost			44,229				1,695				2,999				43,440				1,745				2,829
Plan amendments			—				—				—				—				—				6,661
Actuarial loss (gain)			(44,553	)			2,322				(3,251	)			144,606				5,459				4,567
Benefits paid			(40,222	)			(2,793	)			(959	)			(35,880	)			(2,463	)			(976	)
Benefit obligation at end of year (PBO/PBO/APBO)			1,044,817				42,720				72,632				1,060,240				41,176				72,202
Change in plan assets
Market value of plan assets at beginning of year			754,796				—				44,892				719,944				—				42,314
Actual return on plan assets			(13,694	)			—				(1,034	)			34,732				—				2,859
Employer contributions			36,000				2,793				—				36,000				2,463				—
Benefits paid			(40,222	)			(2,793	)			(274	)			(35,880	)			(2,463	)			(281	)
Market value of plan assets at end of year			736,880				—				43,584				754,796				—				44,892
Funded status at year end		$	(307,937	)		$	(42,720	)		$	(29,048	)		$	(305,444	)		$	(41,176	)		$	(27,310	)
Weighted-average assumptions (benefit obligation)
Discount rate			4.50	%			4.50	%			4.50	%			4.25	%			4.25	%			4.25	%
Weighted-average rate of compensation increase			3.25	%			3.25	%			N/A				2.75	%			2.75	%			N/A

Estimated funding for the plans above during calendar year 2016 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.

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

 

		December 31, 2015				December 31, 2014
Retirement plan		$	922,992			$	886,215
SERP			39,270				39,125

 

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

 

		2016		2017		2018		2019				2020				2021-2025
Pension		$44.0		$45.5		$47.2			$48.9				$50.5				$283.5
PBOP		3.9		4.1		4.3			4.5				4.5				21.3
SERP		2.8		2.8		2.8			2.9				2.9				14.1

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 7.5% declining to 4.5%. 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
		2015				2014				2013				2015				2014				2013				2015				2014				2013
(Thousands of dollars)
Service cost		$	25,123			$	21,360			$	23,056			$	320			$	292			$	373			$	1,641			$	1,101			$	1,220
Interest cost			44,229				43,440				37,607				1,695				1,745				1,535				2,999				2,829				2,482
Expected return on plan assets			(57,808	)			(53,342	)			(49,840	)			—				—				—				(3,464	)			(3,264	)			(2,824	)
Amortization of prior service cost			—				—				—				—				—				—				1,335				355				355
Amortization of net actuarial loss			32,743				22,873				32,261				1,293				783				971				345				—				945
Net periodic benefit cost		$	44,287			$	34,331			$	43,084			$	3,308			$	2,820			$	2,879			$	2,856			$	1,021			$	2,178
Weighted-average assumptions (net benefit cost)
Discount rate			4.25	%			5.00	%			4.25	%			4.25	%			5.00	%			4.25	%			4.25	%			5.00	%			4.25	%
Expected return on plan assets			7.75	%			7.75	%			8.00	%			7.75	%			7.75	%			8.00	%			7.75	%			7.75	%			8.00	%
Weighted-average rate of compensation increase			2.75	%			3.25	%			2.75	%			2.75	%			3.25	%			2.75	%			N/A				N/A				N/A

 

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

 

		2015																2014																2013
		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)		$	30,519			$	26,949			$	2,322			$	1,248			$	173,646			$	163,215			$	5,460			$	4,971			$	(100,345	)		$	(91,115	)		$	(662	)		$	(8,568	)
Amortization of prior service cost (b)			(1,335	)			—				—				(1,335	)			(355	)			—				—				(355	)			(355	)			—				—				(355	)
Amortization of net actuarial loss (b)			(34,381	)			(32,743	)			(1,293	)			(345	)			(23,656	)			(22,872	)			(784	)			—				(34,177	)			(32,261	)			(971	)			(945	)
Prior service cost			—				—				—				—				6,661				—				—				6,661				—				—				—				—
Regulatory adjustment			5,646				5,214				—				432				(140,308	)			(129,031	)			—				(11,277	)			123,630				113,762				—				9,868
Recognized in other comprehensive
(income) loss			449				(580	)			1,029				—				15,988				11,312				4,676				—				(11,247	)			(9,614	)			(1,633	)			—
Net periodic benefit costs recognized in net income			50,451				44,287				3,308				2,856				38,172				34,331				2,820				1,021				48,141				43,084				2,879				2,178
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss		$	50,900			$	43,707			$	4,337			$	2,856			$	54,160			$	45,643			$	7,496			$	1,021			$	36,894			$	33,470			$	1,246			$	2,178

The table above discloses the net gain or loss and prior service cost 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.

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, 2015 and December 31, 2014. The SERP has no assets. The FASB issued guidance in 2015, which the Company has adopted early as permitted, removing the requirement to categorize assets in the fair value hierarchy that are measured using the net asset value (“NAV”) practical

 

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expedient. See note (3) to the table below. Based on this guidance, no Level 3 assets existed (nor are reflected in the table below) at December 31, 2015 and December 31, 2014.

 

		December 31, 2015												December 31, 2014
		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		$	7,021			$	209			$	7,230			$	6,661			$	198			$	6,859
Capital equipment			533				16				549				2,222				66				2,288
Chemicals/materials			3,304				98				3,402				5,233				155				5,388
Consumer goods			41,035				1,221				42,256				41,731				1,238				42,969
Energy and mining			11,066				329				11,395				18,502				549				19,051
Finance/insurance			29,957				892				30,849				20,685				613				21,298
Healthcare			37,930				1,129				39,059				37,846				1,122				38,968
Information technology			29,229				870				30,099				25,881				767				26,648
Services			12,341				367				12,708				28,846				855				29,701
Telecommunications/internet/media			25,883				770				26,653				18,498				549				19,047
Other			9,043				269				9,312				10,958				325				11,283
Real estate investment trusts			5,010				149				5,159				5,713				169				5,882
Mutual funds			87,483				23,985				111,468				86,159				24,567				110,726
Government fixed income securities			33,482				996				34,478				44,694				1,325				46,019
Preferred securities			—				—				—				568				17				585
Futures contracts			(7	)			—				(7	)			—				—				—
Total Level 1 Assets (1)		$	333,310			$	31,300			$	364,610			$	354,197			$	32,515			$	386,712
Level 2 – Significant other observable inputs
Government fixed income and mortgage backed securities		$	49,571			$	1,475			$	51,046			$	48,312			$	1,433			$	49,745
Corporate fixed income securities
Asset-backed and mortgage-backed			23,542				701				24,243				27,071				803				27,874
Banking			20,857				621				21,478				23,289				691				23,980
Insurance			4,896				146				5,042				6,182				183				6,365
Utilities			3,826				114				3,940				4,232				126				4,358
Other			30,995				922				31,917				23,120				686				23,806
Pooled funds and mutual funds			14,808				796				15,604				11,968				984				12,952
Real estate investment trusts			1,949				58				2,007				—				—				—
State and local obligations			950				28				978				1,499				44				1,543
Preferred securities			554				17				571				—				—				—
Convertible securities			196				6				202				—				—				—
Total Level 2 assets (2)		$	152,144			$	4,884			$	157,028			$	145,673			$	4,950			$	150,623
Total Plan assets at fair value		$	485,454			$	36,184			$	521,638			$	499,870			$	37,465			$	537,335
Commingled equity funds (3)			250,511				7,455				257,966				259,235				7,687				266,922
Insurance company general account contracts (4)			3,719				—				3,719				4,003				—				4,003
Total Plan assets (5)		$	739,684			$	43,639			$	783,323			$	763,108			$	45,152			$	808,260

 

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(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)

The commingled equity funds include private equity funds that invest in domestic and international securities regularly traded on securities exchanges. These funds are shown in the above table at net asset value, which is the value of securities in the fund less the amount of any liabilities outstanding. 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.

Early adoption of ASU No. 2015-07: As permitted the Company adopted (earlier than the required adoption date) FASB ASU No. 2015-07 “Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or its Equivalent)” as of December 31, 2015. This guidance simplifies disclosure requirements relating to investments for which fair value is measured using the NAV per share, or its equivalent. The update removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the NAV per share practical expedient. The FASB determined that including those assets in the fair value hierarchy is potentially confusing and misleading to financial statement users. The fair value of the commingled equity funds was determined using NAV as an expedient since no significant observable inputs were available (these funds are not publicly traded on an exchange). Because of the requirements of

 

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this update, the commingled equity funds are no longer included in the above fair value hierarchy table as a Level 3 fair value measurement but instead are disclosed as a reconciling item to the table. The associated Fair Value Measurement Using Significant Unobservable Inputs (Level 3) table is no longer presented due to this change, as the commingled equity funds were the only assets whose values were previously indicated to be Level 3 fair value measurements.

 

(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 $2,859,000 (qualified retirement plan – $2,803,000, PBOP – $56,000) and $8,572,000 (qualified retirement plan – $8,312,000, PBOP – $260,000) for 2015 and 2014, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold.

Note 11 – Stock-Based Compensation

At December 31, 2015, 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):

 

		2015				2014				2013
Stock-based compensation plan expense, net of related tax benefits		$	7,278			$	8,130			$	8,012
Stock-based compensation plan related tax benefits			4,461				4,983				4,910

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 had an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years. Therefore, remaining options, if not exercised prior to the anniversary date of the 2006 grant (in 2016), will then expire.

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

 

		2015								2014								2013
		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			36			$	28.97				52			$	27.57				125			$	28.13
Exercised during the year			(19	)			26.69				(16	)			24.31				(72	)			28.44
Forfeited or expired during the year			—				—				—				—				(1	)			33.07
Outstanding and exercisable at year end			17			$	31.64				36			$	28.97				52			$	27.57

 

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

 

		2015				2014				2013
Outstanding and exercisable		$	394			$	1,194			$	1,473
Exercised			590				451				1,402

 

		December 31, 2015				December 31, 2014				December 31, 2013
Market value of Southwest Gas stock		$	55.16			$	61.81			$	55.91

The weighted-average remaining contractual life for outstanding options was less than one year for 2015. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2015 (thousands of options):

 

Options Outstanding and Exercisable

Range of Exercise Price

Number outstanding

Weighted-average remaining contractual life

Weighted-average exercise price

$29.08 to $33.07

17

0.5 Years

$

31.64

The Company received $523,000 in cash from the exercise of options during 2015 and a corresponding tax benefit of $218,000 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 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 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, 2015 (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			271			$	43.71				257			$	41.22
Granted			80				63.09				73				63.09
Dividends			6								7
Forfeited or expired			—				—				—				—
Vested and issued*			(160	)			43.12				(109	)			46.65
Nonvested/unissued at December 31, 2015			197			$	50.63				228			$	44.36

 

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

 

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The average grant date fair value of performance shares and restricted stock/units granted in 2014 and 2013 was $53.73 and $44.83, respectively.

As of December 31, 2015, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million.

Note 12 – 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,		2015				2014				2013
U.S.		$	221,660			$	221,471			$	222,815
Foreign			(2,328	)			(1,950	)			—
Total income before income taxes		$	219,332			$	219,521			$	222,815

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

 

Year Ended December 31,		2015				2014				2013
Current:
Federal		$	21,321			$	1,739			$	3,549
State			9,899				5,073				5,107
Foreign			650				2,193				—
			31,870				9,005				8,656
Deferred:
Federal			51,132				71,439				67,414
State			(2,574	)			614				1,872
Foreign			(526	)			(2,685	)			—
			48,032				69,368				69,286
Total income tax expense		$	79,902			$	78,373			$	77,942

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

 

Year Ended December 31,		2015				2014				2013
Deferred federal and state:
Property-related items		$	65,931			$	52,814			$	62,737
Purchased gas cost adjustments			(32,993	)			15,049				16,189
Employee benefits			623				109				(2,769	)
All other deferred			15,332				2,257				(6,010	)
Total deferred federal and state			48,893				70,229				70,147
Deferred ITC, net			(861	)			(861	)			(861	)
Total deferred income tax expense		$	48,032			$	69,368			$	69,286

 

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A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2013, 2014, and 2015 (and the sources of these differences and the effect of each) are summarized as follows:

 

Year Ended December 31,		2015				2014				2013
U.S. federal statutory income tax rate			35.0	%			35.0	%			35.0	%
Net state taxes			1.8				1.9				2.4
Property-related items			0.1				0.1				0.1
Tax credits			(0.4	)			(0.5	)			(0.4	)
Company owned life insurance			0.1				(1.0	)			(2.1	)
All other differences			(0.2	)			0.2				—
Consolidated effective income tax rate			36.4	%			35.7	%			35.0	%

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

 

December 31,		2015				2014
Deferred tax assets:
Deferred income taxes for future amortization of ITC		$	1,614			$	2,146
Employee benefits			36,923				31,557
Alternative minimum tax credit			4,809				20,172
Net operating losses and credits			868				9,719
Interest rate swap			7,351				8,622
Other			24,636				25,872
Valuation allowance			(499	)			(253	)
			75,702				97,835
Deferred tax liabilities:
Property-related items, including accelerated depreciation			794,850				736,810
Regulatory balancing accounts			743				33,736
Unamortized ITC			2,549				3,410
Debt-related costs			5,497				5,066
Intangibles			9,547				12,792
Other			31,533				27,600
			844,719				819,414
Net deferred tax liabilities			769,017				721,579
Current			—				(2,109	)
Noncurrent			769,017				723,688
Net deferred tax liabilities		$	769,017			$	721,579

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

 

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At December 31, 2015, the Company has U.S. federal net capital loss carryforwards of $505,000, which begin to expire in 2016. At December 31, 2015, the Company has an income tax net operating loss carryforward related to Canadian operations of $3 million which begins to expire in 2032.

As of December 31, 2015, 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.

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

 

		2015				2014
Unrecognized tax benefits at beginning of year		$	305			$	—
Gross increases-tax positions in prior period			—				305
Gross decreases-tax positions in prior period			(9	)			—
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		$	296			$	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 limitation, 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, 2015. 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. There was no tax-related interest income for 2015, 2014, and 2013.

 

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

Early Adoption of ASU No. 2015-17. As permitted, the Company adopted FASB ASU No. 2015-17 Income Taxes (Topic 740) as of December 31, 2015. This ASU simplifies the presentation of deferred income taxes in that deferred tax liabilities and assets will now be classified as noncurrent in the Consolidated Balance Sheets instead of current and noncurrent. The adoption of this ASU is considered a change in accounting principle. The Company chose to apply the content of the update prospectively as permitted. Prior periods were not retrospectively updated.

Note 13 – Derivatives and Fair Value Measurements

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

The fixed-price contracts and Swaps are utilized by Southwest under its ongoing volatility mitigation programs to effectively fix the price on a portion (up to 25% in the Arizona and California jurisdictions) 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 2016 through March 2018. 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, 2015				December 31, 2014
Contract notional amounts			7,407				5,105

In late 2013, the Company suspended using swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. The Company, along with its regulators, will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.

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

 

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The following table sets forth the gains and (losses) recognized on the Company’s Swaps (derivatives) for the years ended December 31, 2015, 2014, and 2013 and their location in the Consolidated Statements of Income:

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				2015				2014				2013
Swaps		Net cost of gas sold				$	(7,598	)		$	(2,363	)		$	976
Swaps		Net cost of gas sold					7,598	*			2,363	*			(976	)*
Total						$	—			$	—			$	—

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

No gains (losses) were recognized in net income or other comprehensive income during the periods presented for derivatives designated as cash flow hedging instruments. Previously, 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 debt. The first FSIRS terminated in December 2010. The second FSIRS terminated in March 2012. Losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) into interest expense.

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, 2015 Instrument		Balance Sheet Location				Asset Derivatives				Liability Derivatives				Net Total
Swaps		Other current liabilities				$	—			$	(4,267	)		$	(4,267	)
Swaps		Other deferred credits					4				(1,223	)			(1,219	)
Total						$	4			$	(5,490	)		$	(5,486	)
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	)

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 (in the settlement month) 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.

 

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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, 2015				Year ended December 31, 2014				Year ended December 31, 2013
(Thousands of dollars)
Paid to counterparties		$	7,537			$	829			$	3,148
Received from counterparties		$	—			$	4,713			$	915

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

 

December 31, 2015 Instrument		Balance Sheet Location				Net Total
Swaps			Prepaids and other current assets			$	4,267
Swaps			Deferred charges and other assets				1,219
December 31, 2014 Instrument		Balance Sheet Location				Net Total
Swaps			Prepaids and other current assets			$	5,062
Swaps			Deferred charges and other assets				363

Fair Value Measurements.     The estimated fair values of Southwest’s Swaps were determined at December 31, 2015 and 2014 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 measurement.

 

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

Level 2—Significant other observable inputs

 

		December 31, 2015				December 31, 2014
(Thousands of dollars)
Liabilities at fair value:
Other current liabilities—Swaps		$	(4,267	)		$	(5,062	)
Other deferred credits—Swaps			(1,219	)			(363	)
Net Assets (Liabilities)		$	(5,486	)		$	(5,425	)

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 14 – Segment Information

Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems, and providing industrial construction solutions. Over 99% of the total Company’s long-lived assets are in the United States.

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, 2015				December 31, 2014
Accounts receivable for Centuri services		$	10,006			$	9,169

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

 

		December 31, 2015				December 31, 2014
Revenues (a)
United States		$	2,289,133			$	2,069,513
Canada			174,492				52,194
Total		$	2,463,625			$	2,121,707

 

(a)

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

 

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The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2015 is as follows (thousands of dollars):

 

2015		Gas Operations				Construction Services				Adjustments				Total
Revenues from unaffiliated customers		$	1,454,639			$	904,870							$	2,359,509
Intersegment sales			—				104,116								104,116
Total		$	1,454,639			$	1,008,986							$	2,463,625
Interest revenue		$	1,754			$	419							$	2,173
Interest expense		$	64,095			$	7,784							$	71,879
Depreciation and amortization		$	213,455			$	56,656							$	270,111
Income tax expense		$	61,355			$	18,547							$	79,902
Segment net income		$	111,625			$	26,692							$	138,317
Segment assets		$	4,822,845			$	535,840							$	5,358,685
Capital expenditures		$	438,289			$	49,711							$	488,000
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		$	4,652,307			$	566,589			$	(10,599	)		$	5,208,297
Capital expenditures		$	350,025			$	46,873							$	396,898
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

 

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(a)

Construction services segment assets included 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 included income taxes payable of $666,000 in 2013, which was netted against gas operations segment income taxes receivable, net during consolidation.

Note 15 – Quarterly Financial Data (Unaudited)

 

		Quarter Ended
		March 31				June 30				September 30				December 31
(Thousand of dollars, except per share amounts)
2015
Operating revenues		$	734,220			$	538,604			$	505,396			$	685,405
Operating income			129,556				25,047				16,143				117,586
Net income (loss)			71,879				5,063				(4,210	)			66,698
Net income (loss) attributable to Southwest Gas Corporation			71,983				4,949				(4,734	)			66,119
Basic earnings (loss) per common share*			1.54				0.11				(0.10	)			1.40
Diluted earnings (loss) per common share*			1.53				0.10				(0.10	)			1.38
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

 

*	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

 

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discussion of operating results. Additionally, see Note 16 – Construction Services Noncontrolling Interests regarding allocation of earnings and Note 17 – Acquisition of Construction Services Businesses regarding the acquisition in the last quarter of 2014.

Note 16 – Construction Services Noncontrolling Interests

Associated with the agreement reached in conjunction with the acquisition of the Canadian constriction businesses, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses. The agreement, associated with that approximate 10% equity interest, provided special dividend rights which entitled 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 could become exchangeable for a 3.4% equity interest in Centuri. In consideration of the underlying exchange rights of the original agreement, earnings attribution by Centuri to the previous owners also occurred in an amount equivalent to 3.4% of Centuri earnings since October 2014. During the third quarter of 2015, the sellers formally exercised their exchange rights under the terms of the original agreement. No new rights were conveyed to the noncontrolling parties as a result of the exchange and no new consideration was involved. The previous owners continue to be able to exit their investment retained by requiring the purchase of a portion of their interest commencing July 2017 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 beginning in July 2022. Due to the continued ability of the noncontrolling parties to redeem their interest for cash, their interest continues to be presented on the Company’s Consolidated Balance Sheet at December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance. However, that interest, previously associated with the Canadian businesses, is now formally an interest in Centuri.

Significant changes in the value of the redeemable noncontrolling interest are recognized as they occur, and the carrying value is adjusted as necessary at each reporting date. Guidance by the SEC indicates that downward adjustments in the value of redeemable noncontrolling interests are only permitted to the extent that upward adjustments in value were previously recognized. A floor for the noncontrolling interest was originally set at the acquisition date (in October 2014). However, U.S. GAAP generally views changes in ownership interest, where the parent retains its controlling interest, as an equity transaction, whereby the carrying amount of the noncontrolling interest is adjusted to reflect the change in ownership interest in the subsidiary. In connection with the exchange rights being exercised during the third quarter, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized, due in part to the exchange option no longer being subject to probability estimates. In light of the U.S. GAAP requirement to adjust the carrying amount, a new floor was set for the redeemable noncontrolling interest at the exchange date (July 31, 2015), with a corresponding adjustment made to additional paid in capital of the Company. Future adjustments to the redemption value are not permitted below the new floor. The following depicts impacts to the balance of the redeemable noncontrolling interest between the indicated periods.

 

		Redeemable Noncontrolling Interest
(Thousands of dollars):
Balance, December 31, 2014		$	20,042
Net Income (loss) attributable to redeemable noncontrolling interest			939
Foreign currency exchange translation adjustment			(66	)
Centuri distribution to redeemable noncontrolling interest			(99	)
Adjustment to redemption value			(4,708	)
Balance, December 31, 2015		$	16,108

The redemption value of the redeemable noncontrolling interest utilizes a market approach to determine a construction services enterprise value. Publicly traded “guideline” companies are identified by using a selection criteria, including actively

 

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traded equities, their financial solvency, and other factors. Once the guideline companies are determined, enterprise value is 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 is determined, it is multiplied by 3.4%. A discount is then applied due to limitations of the nonpublic noncontrolling interest being valued. Prior to the exchange rights being exercised in the third quarter of 2015, a Monte Carlo simulation methodology was used to assign a value to the redeemable noncontrolling interest. Each quarter, market changes in the guideline companies are considered and the weighted approach to projected EBIT and EBITDA, in relation to the guideline companies, is re-evaluated to determine if value changes are necessary at each quarterly reporting date. The negative adjustment to the redemption value in the table above reflects the sum of adjustments made during the year.

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, but is identified as the Noncontrolling interest within Total equity on the Consolidated Balance Sheets.

Note 17 – Acquisition of Construction Services Businesses

In October 2014, the Company, through its subsidiaries, completed the acquisition of three privately held, affiliated construction businesses. The acquisition extended 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 7 – Long-Term Debt. The acquired companies comprise: (i) Link-Line Contractors Ltd., an Ontario corporation (“Link-Line”), (ii) W.S. Nicholls Construction, Inc., an Ontario corporation, as well as two additional companies also operating under the name W.S. Nicholls (collectively “W.S. Nicholls”); and (iii) via asset purchase, the business of Brigadier Pipelines Inc., a Delaware corporation, operating primarily in Pennsylvania (“Brigadier”).

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 in 2014. The Company’s allocation of the purchase price in 2014 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 been completed. The October 1, 2014 fair values of assets acquired and liabilities assumed, revised during the first quarter of 2015, are as follows (in millions of dollars):

 

		Acquisition Date				Measurement Period Adjustments				Revised Acquisition Date
Cash, cash equivalents, and restricted cash		$	3			$	—			$	3
Contracts receivable and other receivables			62				—				62
Property, plant and equipment			17				—				17
Other assets			17				(2	)			15
Intangible assets			52				—				52
Goodwill			130				1				131
Total assets acquired			281				(1	)			280
Current liabilities			39				1				40
Deferred income tax—long-term			17				—				17
Other long-term liabilities			4				—				4
Net assets acquired		$	221			$	(2	)		$	219

 

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The Company incurred and expensed acquisition costs of $5 million in 2014; no acquisition costs were incurred during 2015.

The allocation of the purchase price of Link-Line, W.S. Nicholls, and Brigadier was accounted for in accordance with the applicable accounting guidance. Goodwill consisted of the value associated with the assembled workforce and consolidation of operations. When acquisition-date values were updated in the first quarter of 2015, as reflected in the table above, there was no significant overall impact to the Company’s Consolidated Balance Sheets.

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

 

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

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the “Internal Control – Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2015. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 25, 2016

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Southwest Gas Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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.

As discussed in Note 12 to the Consolidated Financial Statements, the Company changed the manner in which it classifies deferred income taxes in 2015.

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.

 

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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.

PricewaterhouseCoopers LLP

Las Vegas, Nevada

February 25, 2016

 

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