UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
Commission File Number 1-07850
SOUTHWEST GAS CORPORATION
(Exact name of registrant as specified in its charter)
| California | 88-0085720 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
| 5241 Spring Mountain Road Post Office Box 98510 Las Vegas, Nevada |
89193-8510 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (702) 876-7237
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Southwest Gas Holdings, Inc., the successor company to Southwest Gas Corporation Common Stock, $1 par value | New York Stock Exchange, Inc. |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☑ | Accelerated filer | ☐ | |||
| Non-accelerated filer | ☐ | Smaller reporting company | ☐ | |||
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
Aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant, Southwest Gas Corporation, the predecessor company to Southwest Gas Holdings, Inc.:
$3,736,883,501 as of June 30, 2016
The number of shares outstanding of Southwest Gas Holdings, Inc., the successor company to Southwest Gas Corporation, common stock:
Common Stock, $1 Par Value, 47,546,825 shares as of February 15, 2017
All of the outstanding shares of common stock ($1 par value) of Southwest Gas Corporation were held by Southwest Gas Holdings, Inc. as of February 15, 2017.
DOCUMENTS INCORPORATED BY REFERENCE
| Description |
Part Into Which Incorporated | |
|
Annual Report to Shareholders for the Year Ended December 31, 2016 Southwest Gas Holdings, Inc. 2017 Proxy Statement |
Parts I, II, and IV Part III |
| 1 | ||||||
| Item 1. |
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| Item 1A. |
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| Item 1B. |
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| Item 2. |
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| Item 3. |
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| Item 4. |
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| Item 4A. |
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| Item 5. |
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| Item 6. |
14 | |||||
| Item 7. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
14 | ||||
| Item 7A. |
14 | |||||
| Item 8. |
15 | |||||
| Item 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
15 | ||||
| Item 9A. |
15 | |||||
| Item 9B. |
16 | |||||
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| Item 10. |
17 | |||||
| Item 11. |
18 | |||||
| Item 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
18 | ||||
| Item 13. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
19 | ||||
| Item 14. |
19 | |||||
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| Item 15. |
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| Item 16. |
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| 25 |
| BUSINESS |
In 2015, the Board of Directors (“Board”) of Southwest Gas Corporation 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. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri”) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company, Southwest Gas Holdings, Inc. (“Southwest Gas Holdings”); whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of the reorganization were filed with the Arizona Corporation Commission (“ACC”), the California Public Utilities Commission (“CPUC”), and the Public Utilities Commission of Nevada (“PUCN”) in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The reorganization, which was approved by the Board of Directors in December 2016, became effective in January 2017. Each outstanding share of Southwest Gas Corporation’s common stock automatically converted into a share of stock in Southwest Gas Holdings, on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. This report is as of the balance sheet date of December 31, 2016 and periods up to that date (prior to the effective date of the holding company formation), with disclosures, where appropriate, for events following that date. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016.
The Company was incorporated in March 1931 under the laws of the state of California. The Company is composed 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.
Centuri (the “construction services” segment), a 96.6% owned subsidiary of the Company, is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operations are generally conducted under the business names of NPL Construction Co. (“NPL”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd.), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). In May 2016, Centuri completed the acquisition of two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”).
Financial information concerning the Company’s business segments is included in Note 14 of the Notes to Consolidated Financial Statements, which is included in the 2016 Annual Report to Shareholders and is incorporated herein by reference.
Southwest Gas Holdings maintains a website (www.swgasholdings.com) for the benefit of shareholders, investors, customers, and other interested parties. Similarly, Southwest maintains a website (www.swgas.com) mainly focused on utility operations. The annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available, free of charge, through the www.swgasholdings.com website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). All Company SEC filings are also available on the www.swgasholdings.com website. The Corporate Governance Guidelines, Code of Business Conduct and Ethics, and charters of the nominating and corporate governance, audit, and compensation committees of the board of directors are also available on the www.swgasholdings.com website. Print versions of these documents are available to shareholders upon request directed to the Corporate Secretary, Southwest Gas Holdings, Inc., 5241 Spring Mountain Road, Las Vegas, NV 89150.
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Southwest is subject to regulation by the ACC, the PUCN, and the CPUC. These commissions regulate public utility rates, practices, facilities, and service territories in their respective states. The CPUC also regulates the issuance of all debt securities by Southwest, with the exception of short-term borrowings. Certain accounting practices, transmission facilities, and rates are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Centuri is not regulated by the state utilities commissions or by the FERC in any of its operating areas.
As of December 31, 2016, Southwest purchased and distributed or transported natural gas to 1,984,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. Southwest added 28,000 net new customers during 2016. Southwest expects similar customer growth in 2017.
The table below lists the percentage of operating margin (operating revenues less net cost of gas) by major customer class for the years indicated:
| For the Year Ended |
Distribution | Transportation | ||||
| Residential and Small Commercial |
Other Sales Customers |
|||||
| December 31, 2016 |
85% | 3% | 12% | |||
| December 31, 2015 |
85% | 4% | 11% | |||
| December 31, 2014 |
85% | 4% | 11% | |||
Southwest is not dependent on any one or a few customers such that the loss of any one or several would have a significant adverse impact on earnings or cash flows. See Risk Factors below regarding impacts in the event of loss of significant customers in the construction services segment.
Transportation of customer-secured gas to end-users accounted for 47% of total system throughput in 2016, but only 12% of operating margin as shown in the table above. Customers who utilized this service transported 97 million dekatherms in 2016, 104 million dekatherms in 2015, and 91 million dekatherms in 2014.
The demand for natural gas is seasonal, with greater demand in the colder winter months and decreased demand in the warmer summer months. It is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in operations. The decoupled rate mechanisms in place in the three-state service territory are structured with seasonal variations. Also, earnings for interim periods can be significantly affected by the timing of general rate relief.
Rates that Southwest is authorized to charge its distribution system customers are determined by the ACC, PUCN, and CPUC in general rate cases and are derived using rate base, cost of service, and cost of capital experienced in an historical test year, as adjusted in Arizona and Nevada, and projected for a future test year in California. The FERC regulates the northern Nevada transmission and liquefied natural gas (“LNG”) storage facilities of Paiute Pipeline Company (“Paiute”), a wholly owned subsidiary, and the rates it charges for transportation of gas directly to certain end-users and to various local distribution companies (“LDCs”). The LDCs transporting on the Paiute system are: NV Energy (serving Reno and Sparks, Nevada) and Southwest (serving Truckee, South and North Lake Tahoe in California and various locations throughout northern Nevada).
Rates charged to customers vary according to customer class and rate jurisdiction and are set at levels that are intended to allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt as well as a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service net of amounts associated with costs borne by third parties, plus certain other assets such as working capital and inventories, less accumulated depreciation on utility plant in service, net deferred income tax liabilities, and certain other deductions.
Rate structures in all service territories allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption, though decoupled structures (alternative revenue programs), vary by state. In California, authorized operating margin levels vary by month. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin. In Arizona, a full revenue decoupling mechanism (currently, with a winter-period monthly weather adjuster) is in place for most customer classes.
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Rate schedules in all service areas contain deferred energy or purchased gas adjustment provisions, which allow Southwest to file for rate adjustments as the cost of purchased gas changes. Deferred energy and purchased gas adjustment (collectively “PGA”) rate changes affect cash flows, but have no direct impact on profit margin. Filings to change rates in accordance with PGA clauses are subject to audit by the appropriate state regulatory commission staff.
Information with respect to recent general rate cases and PGA filings is included in the Rates and Regulatory Proceedings section of Management’s Discussion and Analysis (“MD&A”) in the 2016 Annual Report to Shareholders.
The table below lists recent docketed general rate filings and the status of such filing within each ratemaking area:
| Ratemaking Area |
Type of Filing |
Month Filed |
Month Final Rates Effective | |||
| Arizona: |
General rate case | May 2016 | Pending | |||
| California: |
||||||
| Northern and Southern |
Annual attrition | November 2016 | January 2017 | |||
| Northern and Southern |
General rate case | December 2012 | June 2014 | |||
| Nevada: |
||||||
| Northern and Southern |
General rate case | April 2012 | April 2013 | |||
| FERC: |
||||||
| Paiute |
General rate case | February 2014 | February 2015 |
While Southwest is subject to regulatory rules and oversight with regard to rates and operating requirements under its various state tariffs (and federal tariff, in the case of Paiute Pipeline), it is also subject to regulation with regard to the safety and integrity of its pipeline systems. The Department of Transportation (“DOT”) administers pipeline regulations through the Office of Pipeline Safety, within the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). In recent years, various pieces of legislation have been passed in the areas of distribution pipeline integrity, control room management, and pipeline safety. The Pipeline Inspection, Protection, Enforcement, and Safety (“PIPES”) Act of 2006 mandated, among other things, a graduated implementation program for control room management, a requirement to install excess flow valves on single-family residential customer locations, and a Distribution Integrity Management Program (“DIMP”), which was required to be in place by August 2011, and includes evaluation and mitigation of risks, as well as certain reporting requirements. Additionally, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“the Bill”), effective January 2012, which increased/strengthened previously existing safety requirements, including damage prevention programs, penalty provisions, and requirements related to automatic and remote-controlled shut-off valves, public awareness programs, incident notification, and maximum allowable operating pressure for certain facilities. The Bill required the DOT to conduct further study of existing programs and future requirements; these studies are nearing their completion and proposed regulation changes are anticipated in some form in 2017/2018. The PHMSA is in the process of proposing a series of significant rulemakings that are expected to further transform the regulatory requirements for pipelines. In October 2016, PHMSA issued a final rule regarding expanding the use of excess flow valves in natural gas distribution systems. The new rule has an effective date of April 2017. Southwest continues to evaluate potential impacts of this regulation on its operations and customers. Southwest continues to monitor changing pipeline safety legislation and participates to the extent possible in developing associated mandates and reporting requirements. Additionally, it works with its state and federal commissions, where possible, to develop customer rates that are responsive to incremental costs of compliance. However, due to the timing of when rates are implemented in response to new requirements, and as additional rules are developed, compliance requirements could impact expenses and the timing and amount of capital expenditures.
Deliveries of natural gas by Southwest are made under a priority system established by state regulatory commissions. The priority system is intended to ensure that the gas requirements of higher-priority customers, primarily residential customers and other customers who use 500 therms or less of gas per day, are fully satisfied on a daily basis before lower-priority customers, primarily electric utility and large industrial customers able to use alternative fuels, are provided any quantity of gas or capacity.
Demand for natural gas is greatly affected by temperature. On cold days, use of gas by residential and commercial customers can be as much as seven times greater than on warm days because of increased use of gas for space heating. To fully satisfy this increased high-priority demand, gas is withdrawn from storage in certain service areas, or peaking supplies are purchased from suppliers. If necessary, service to interruptible lower-priority customers may be curtailed to provide the needed delivery system capacity. Southwest maintains no significant backlog on its orders for gas service.
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Southwest is responsible for acquiring and arranging delivery of natural gas to its system in sufficient quantities to meet its sales customers’ needs. Southwest’s primary natural gas procurement objective is to ensure that adequate supplies of natural gas are available at a reasonable cost. Southwest acquires natural gas from a wide variety of sources and a mix of purchase provisions, which includes spot market and firm supplies. The purchases may have terms from one day to several years and utilize both fixed and indexed pricing. During 2016, Southwest acquired natural gas from 40 suppliers. Southwest regularly monitors the number of suppliers, their performance, and their relative contribution to the overall customer supply portfolio. New suppliers are contracted when possible, and solicitations for supplies are extended to the largest practicable list of suppliers, taking into account each supplier’s creditworthiness. Competitive pricing, flexibility in meeting Southwest’s requirements, and demonstrated reliability of service are instrumental to any one supplier’s inclusion in Southwest’s portfolio. The goal of this practice is to mitigate the risk of nonperformance by any one supplier and ensure competitive prices in the portfolio.
Balancing reliability with supply cost results in a continually changing mix of purchase provisions within the supply portfolios. To address the unique requirements of its various market areas, Southwest assembles and administers a separate natural gas supply portfolio for each of its jurisdictional areas. Southwest facilitates most natural gas purchases through competitive bid processes.
To mitigate customer exposure to short-term market price volatility, Southwest seeks to fix the price on a portion (up to 25% in the Arizona and California jurisdictions) of its forecasted annual normal-weather volume requirement, primarily using firm, fixed-price purchasing arrangements that are secured periodically throughout the year. Southwest’s price volatility mitigation program includes the use of financial derivatives, in the form of fixed-for-floating-index-price swaps combined with indexed-price physical purchases, to secure a portion of the fixed-price portfolio for the Arizona rate jurisdiction. The combination of fixed-price contracts and financial derivatives is designed to increase flexibility for Southwest and increase supplier diversification. The cost of such financial derivatives combined with the associated indexed-price physical purchases is recovered from customers through the PGA mechanism.
In late 2013, the utilization of fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) was suspended for the Nevada territories served by Southwest. Management evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions. Any future decision concerning Nevada VMP purchases will be documented and retained to facilitate regulatory review in accordance with a previous regulatory stipulation. Southwest schedules quarterly meetings with the PUCN Staff and the Bureau of Consumer Protection to discuss market fundamentals, along with any decision by management concerning VMP purchases for the Nevada service territories.
For the 2016/2017 heating season, fixed-price physical commodity purchases ranged from approximately $2.65 to approximately $4.15 per dekatherm. Southwest makes non-fixed-price natural gas purchases under variable-price contracts with firm quantities or on the spot market. Prices for these contracts are determined at the beginning of each month to reflect that month’s published first-of-month index price or based on a published daily price index. These monthly or daily index prices are not published or known until the purchase period begins.
The firm natural gas supply arrangements are structured such that a stated volume of natural gas is required to be nominated by Southwest and delivered by the supplier. Contracts provide for fixed or market-based penalties to be paid by the non-performing party.
Storage availability can influence the average annual price of natural gas, as storage allows a company to purchase natural gas quantities during the off-peak season and store it for use in high demand periods when prices may be greater or supplies/capacity tighter. Southwest currently has no storage availability in its southern Nevada rate jurisdiction. Limited storage availability exists in southern and northern California, northern Nevada, and the Arizona rate jurisdiction.
Southwest has a contract with Southern California Gas Company that is intended for delivery only within Southwest’s southern California rate jurisdiction. In addition, contracts with Paiute for its LNG facility allow for peaking capability only in northern Nevada and northern California. For all storage options, Southwest purchases natural gas for injection during the off-peak period for use in the high demand months, but these supplies have a limited impact on the overall price.
Southwest also has interruptible storage contracts with Northwest Pipeline Corporation (“NWPL”) for the northern Nevada and northern California rate jurisdictions. NWPL has the discretion to limit Southwest’s ability to inject or withdraw
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from this interruptible storage, which consequently limits Southwest’s use of this interruptible storage capacity. As such, this storage provides limited operational flexibility to adjust daily flowing supplies to meet demand, and has limited impact on the overall price of natural gas supplies.
Southwest also has an agreement for its Arizona rate jurisdiction with Enstor Grama Ridge Storage and Transportation, LLC (“Enstor”) which provides for a maximum quantity of 600,000 dekatherms of natural gas underground storage in New Mexico that is deliverable on the El Paso system. Southwest previously received approval to construct, operate and maintain a 233,000 dekatherm LNG facility in southern Arizona. 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. The site for the facility was purchased in October 2015. Southwest solicited requests for proposals for the engineering, procurement and construction (“EPC”) phase of the project, and in October 2016 made a filing with the ACC to modify the previously issued Order to update the pre-approved costs to reflect a not-to-exceed amount of $80 million, which is intended to update the pre-approval to reflect the current pricing information made available through the recently completed EPC phase. The filing was approved by the ACC in December 2016. Through December 2016, Southwest has incurred approximately $4.1 million in capital expenditures toward the project (including land acquisition costs). Southwest included a proposal for the ratemaking treatment of facility costs as part of its current Arizona rate case filing. A settlement (contingent on ACC approval) in the general rate case was reached between several parties at a December 2016 settlement meeting and a formal draft settlement was filed with the ACC in January 2017. The draft settlement included an agreement to defer the revenue requirement associated with all costs incurred before December 31, 2020 for recovery in Southwest’s next general rate case proceeding and extended the authorization to defer costs through the same date. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. Construction is expected to be completed by the end of 2019.
Natural gas supplies for Southwest’s southern system (Arizona, southern Nevada, and southern California properties) are primarily obtained from producing regions in Colorado and New Mexico (San Juan basin), Texas (Permian basin), and Rocky Mountain areas. For its northern system (northern Nevada and northern California properties), Southwest primarily obtains natural gas from Rocky Mountain producing areas and from Canada.
The landscape for national natural gas supply is continuously changing. Advanced drilling techniques continue to provide access to abundant and sustainable natural gas supplies. The natural gas market has responded to the abundant supply of natural gas with reductions to both price volatility and the total price of the commodity. Forecasts show that an ample and diverse natural gas supply is available to Southwest’s customers at a highly competitive price when compared with competing forms of energy.
Southwest arranges for transportation of natural gas to its Arizona, Nevada, and California service territories through the pipeline systems of El Paso Natural Gas Company (“El Paso”), Kern River Gas Transmission Company (“Kern River”), Transwestern Pipeline Company (“Transwestern”), NWPL, Tuscarora Gas Pipeline Company (“Tuscarora”), Southern California Gas Company, and Paiute. Southwest regularly monitors short- and long-term supply and pipeline capacity availability to ensure the reliability of service to its customers. Southwest currently receives firm transportation service, both on a short- and long-term basis, for all of its service territories on the pipeline systems noted above. Southwest also contracts for firm natural gas supplies that are delivered to Southwest’s city gates to supplement its firm capacity on the interstate pipelines and to meet projected peak-day demands. Southwest could also utilize its interruptible contracts on the interstate pipelines for the transportation of additional natural gas supplies.
Southwest believes that the current levels of contracted firm interstate capacity and delivered purchases are sufficient to serve each of its service territories’ forecasted peak-day requirements. As the need arises to acquire additional capacity on one of the interstate pipeline transmission systems, primarily due to customer growth, Southwest will continue to consider available options to obtain that capacity, either through the use of firm contracts with a pipeline company, by purchasing capacity on the open market, or through the purchase of firm delivered natural gas supplies.
Electric utilities are the principal competitors of Southwest for the residential and small commercial markets throughout its service areas. Competition for space heating, general household, and small commercial energy needs generally occurs at the initial installation phase when the customer/builder typically makes the decision as to which type of equipment to install and operate. The customer will generally continue to use the chosen energy source for the life of the equipment. Southwest interfaces directly with the various home builders and commercial property developers in its service territories to ensure that natural gas appliances are considered in new developments and commercial centers. As a result of its efforts,
5
Southwest has continued to experience growth in the new construction market among residential and small commercial customer classes.
Unlike residential and small commercial customers, certain large commercial, industrial, and electric generation customers have the capability to switch to alternative energy sources. To date, Southwest has been successful in retaining most of these customers by setting rates (subject to conditions of the respective state tariffs) at levels competitive with commercially available alternative energy sources such as electricity, fuel oils, and coal. However, high natural gas prices can impact Southwest’s ability to retain some of these customers. Overall, management does not anticipate any material adverse impact on operating margin from fuel switching by these large customers.
Southwest competes with interstate transmission pipeline companies, such as El Paso, Kern River, Transwestern and Tuscarora, to provide service to certain large end-users. End-use customers located in proximity to these interstate pipelines pose a potential bypass threat. Southwest attempts to closely monitor each customer situation and provide competitive service in order to retain the customer. Southwest has remained competitive through the use of negotiated transportation contract rates (subject to conditions of the respective state tariffs), special long-term contracts with electric generation and cogeneration customers, and other tariff programs. These competitive response initiatives have mitigated the loss of margin earned from large customers.
Federal, state, and local laws and regulations governing the discharge of materials into the environment have a direct impact upon Southwest. Environmental efforts, with respect to matters such as storm water management, emissions of air pollutants, hazardous material management, protection of endangered species and archeological resources, directly impact the complexity and time required to obtain pipeline rights-of-way and construction permits. However, increased environmental legislation and regulation can also be beneficial to the natural gas industry. Natural gas is one of the most environmentally-friendly fossil fuels currently available and its use can help energy users to comply with stricter environmental air quality standards.
The United States Environmental Protection Agency (“EPA”) and the State of California Environmental Protection Agency (“Cal/EPA”) have issued regulations that require the reporting of greenhouse gas emissions (“GHG”) from large sources and suppliers in order to facilitate the development of policies and programs to reduce GHGs. Southwest reports required information to the EPA and Cal/EPA under respective rules including the volumes of natural gas that it receives for distribution to LDC customers, and the GHG emissions that result from the operation of its LDC pipelines. While some aspects of the mandatory reporting rules do not apply to Southwest, other required information is being reported to the Department of Energy, the Department of Transportation, or is available in existing databases. Management also monitors the development of climate legislation (including the State of California Global Warming Solutions Act), which could result in additional requirements or have financial implications.
California Assembly Bill Number 32 and the regulations promulgated by the California Air Resources Board (“CARB”), require Southwest, as a covered entity, to comply with all of the requirements associated with the California GHG Emissions Reporting Program and the California Cap and Trade Program. The objective of these programs is to reduce California statewide GHG emissions to 1990 levels by 2020. Southwest must report annual GHG emissions by April of each year and third-party verification of those reported amounts is required by September of each year. Starting in 2015, the CARB annually allocates to Southwest a certain number of allowances based on Southwest’s reported 2011 GHG emissions. Southwest received its allocation for 2016 in the third quarter of 2015 and, for 2017, in the third quarter of 2016. Of those allocated allowances, Southwest must consign a certain percentage to the CARB for auction. Southwest 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. In addition to allowances, Southwest can satisfy a portion of its compliance obligation through the purchase of offsets, which are credits available in the OTC market from industries that generate reductions in greenhouse gas emissions.
There are two triennial compliance periods; one ending in 2017 and the other ending in 2020. To meet its compliance obligations, during each triennial compliance period, Southwest must surrender a combination of allowances and offsets equal to 30% of its annual reported GHG emissions for the prior year by November 1 of each year (2016 through 2020). Also by November 1 of the year following each of the triennial compliance periods (2018 and 2021), Southwest must surrender a sufficient number of allowances and offsets to meet the amount of GHG emissions reported during that triennial compliance period, less the amount previously surrendered.
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The CPUC has issued a decision that provides for the regulatory treatment of the program costs and there is no expected impact on earnings.
At December 31, 2016, Southwest had 2,247 regular full-time equivalent employees. Southwest believes it has a good relationship with its employees and that compensation, benefits, and working conditions afforded its employees are comparable to those generally found in the utility industry. No employees are represented by a union.
Centuri is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri contracts primarily with LDCs to install, repair, and maintain energy distribution systems from the town border station to the end-user. The primary focus of Centuri operations is distribution pipe and service hook-up replacements as well as line installations for new business development. Construction work varies from relatively small projects to the piping of entire communities. Construction activity is seasonal in most areas. Peak construction periods are the summer and fall months in colder climate areas, such as the North East, Midwest, and Canada. In the warmer climate areas, such as the southwestern United States, construction continues year round.
During the past few years, several factors have resulted in an increase in large multi-year distribution pipe replacement projects. The U.S. Department of Transportation’s PHMSA instituted DIMP which required operators of gas distribution pipelines to develop and implement integrity management programs to enhance safety by identifying and reducing pipeline integrity risks. Also contributing to the increase in replacement projects were bonus depreciation tax deduction incentives. The Protecting Americans from Tax Hikes Act of 2015 extended 50% bonus depreciation tax deduction incentives through 2017 and at lesser rates through 2019. Finally, funding for customers’ planned replacement projects improved due to greater access to credit markets.
In connection with the increased construction activity, several large multi-year distribution pipe replacement projects were awarded to Centuri. Centuri was selected as the sole contractor on certain of these projects, or one of several contractors to work on others. Centuri continues to bid on pipe replacement projects throughout the United States and Canada and has made structural and transitional changes to match the increased size and complexity of the business. The amount of work completed by Centuri on these multi-year contracts will vary from year to year.
Centuri’s business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with Centuri to provide pipe replacement services and new line installations. Contract terms generally specify unit-price or fixed-price arrangements. Unit-price contracts establish prices for all of the various services to be performed during the contract period. These contracts often have annual pricing reviews. During 2016, approximately 86% of revenue was earned under unit-price contracts. As of December 31, 2016, a backlog of approximately $88 million existed with respect to outstanding fixed-priced construction contracts.
Materials used by Centuri in its construction activities are typically specified, purchased, and supplied by Centuri’s customers. Construction contracts also contain provisions which make customers generally liable for remediating environmental hazards encountered during the construction process. Such hazards might include digging in an area that was contaminated prior to construction, finding endangered animals, digging in historically significant sites, etc. Otherwise, Centuri’s operations have limited environmental impact (dust control, normal waste disposal, handling harmful materials, etc.).
Competition within the industry has traditionally been limited to several regional and numerous local competitors in what has been a largely fragmented industry. Some national competitors also exist within the industry. Centuri currently operates in 20 major markets within the United States and also within the Canadian provinces of British Columbia and Ontario. Its customers are primarily the principal LDCs in those markets. During 2015, Centuri served over 100 customers, with Southwest accounting for approximately 9% of total revenues. Additionally, two customers combined accounted for approximately 24% of total revenue, while four other customers individually accounted for 5% or more of total revenue.
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Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2016, Centuri had 4,030 regular full-time equivalent employees. Employment peaked in September 2016 when there were 5,938 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.
Centuri’s operations are conducted from 24 field locations throughout the United States and 12 field locations within Canada, with corporate headquarters located in Phoenix, Arizona. Buildings and equipment storage yards are normally leased from third parties. The lease terms are typically five years or less.
Centuri is not directly affected by regulations promulgated by the ACC, PUCN, CPUC, or FERC. Centuri is an unregulated subsidiary of the Company. However, because Centuri performs work for Southwest, its associated construction costs are subject indirectly to “prudency reviews” just as any other capital work that is performed by third parties or directly by Southwest. However, such “prudency reviews” would not bring Centuri under the regulatory jurisdiction of any of the commissions noted above.
Centuri has a 65% interest in IntelliChoice Energy, LLC (“ICE”) and consolidates ICE as a majority owned subsidiary. ICE was established in 2009 and markets natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. To date, ICE has not been a significant component of Centuri operating results.
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 that specializes in construction of underground aviation fueling systems and storage tanks. The Company is not the primary beneficiary of Western; therefore, Western is not consolidated with Centuri and is accounted for under the equity method of accounting. Furthermore, Centuri, through its subsidiaries, also has a 25% interest in CCI-TBN Toronto, Inc., and a 50% interest in Matheson-Nicholls Joint Venture, subject to equity method accounting as well. To date, neither Western, CCI-TBN Toronto, Inc., nor Matheson-Nicholls Joint Venture have been a significant component of Centuri’s financial results.
| RISK FACTORS |
Described below (and in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of this report) are risk factors that we have identified that may have a negative impact on our future financial performance or affect whether we achieve the goals or expectations expressed or implied in any forward-looking statements contained herein. Because Southwest Gas Holdings, Inc. was formed as the successor issuer (to Southwest Gas Corporation) of public equity securities subsequent to December 31, 2016, and because these discussions relate to ongoing risks and future impacts, unless indicated otherwise, references below to “we,” “us,” and “our” should be read to refer to Southwest Gas Holdings, Inc. and its subsidiaries, including Southwest Gas Corporation.
As a holding company, Southwest Gas Holdings, Inc. depends on operating subsidiaries to meet financial obligations.
Southwest Gas Holdings, Inc. has no significant assets other than the stock of operating subsidiaries and is not expected to have significant operations on its own. Southwest Gas Holdings’ ability to pay dividends to shareholders is dependent on the ability of its subsidiaries to generate sufficient net income and cash flows to service debt and pay upstream dividends. Because of the relative size of subsidiary operations, and their relative impacts to net income and cash flows, substantial dependency on the utility operations of Southwest Gas Corporation exists. The ability of Southwest Holdings’ subsidiaries to pay upstream dividends and make other distributions would be subject to applicable state law and regulatory restrictions.
Governmental policies and regulatory actions can reduce our earnings.
Regulatory commissions set our utility customer rates and determine what we can charge for our rate-regulated services. Our ability to obtain timely future rate increases depends on regulatory discretion. Governmental policies and regulatory actions, including those of the ACC, CPUC, FERC, and PUCN relating to allowed rates of return, rate structure, purchased gas and investment recovery, operation and construction of facilities, present or prospective wholesale and retail competition, changes in tax laws and policies, and changes in and compliance with environmental and safety laws such as the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and policies, can reduce our earnings. Risks and uncertainties relating to delays in obtaining, or failure to obtain, regulatory approvals, conditions imposed in regulatory approvals, and determinations in regulatory investigations can also impact financial performance. In particular, the timing and amount of rate relief can materially impact results of operations.
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We are unable to predict what types of conditions might be imposed on Southwest or what types of determinations might be made in pending or future regulatory proceedings or investigations. We nevertheless believe that it is not uncommon for conditions to be imposed in regulatory proceedings, for Southwest to agree to conditions as part of a settlement of a regulatory proceeding, or for determinations to be made in regulatory investigations that reduce our earnings and liquidity. For example, we may request recovery of a particular operating expense in a general rate case filing that a regulator disallows, negatively impacting our earnings if the expense continues to be incurred. Southwest records regulatory assets in its consolidated financial statements to reflect the ratemaking and regulatory decision-making authority of the regulators, as allowed by generally accepted accounting principles. The creation of a regulatory asset allows for the deferral of costs which, absent a mechanism to recover such costs from customers in rates approved by regulators, would be charged to expense in the consolidated income statement in the period incurred. If there was a change in regulatory positions surrounding the collection of these deferred costs, there could be a material impact on financial position, results of operations, and cash flows.
We may be subject to disallowances, penalties or fines related to the operation of natural gas pipelines under recent regulations concerning natural gas pipeline safety, which could have an adverse effect on our results of operations, financial condition, and/or cash flows.
We are committed to consistently monitoring and maintaining our distribution system and storage operations to ensure that natural gas is acquired, stored and delivered safely, reliably and efficiently. Due to the combustible nature of our product, we anticipate that the natural gas industry could be the subject of increased federal, state, and local regulatory oversight over time. We continue to work diligently with industry associations and federal, state, and local regulators to ensure compliance with any new laws, such as the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and the series of significant rulemakings to be proposed by the Pipeline and Hazardous Materials Safety Administration. We expect there to be increased costs associated with compliance (and potential penalties for any non-compliance) with these and similar laws. If these costs are not recoverable in our customer rates, or if there are delays in recoverability due to regulatory lag, they could have a negative impact on our operating costs and financial results.
Our operating results may be adversely impacted by another economic downturn.
The 2007/2008 economic slowdown in the United States, and particularly in our service areas, resulted in a marked decline in the new housing market and an increase in the inventory of idle/vacant homes. Commercial entities (including restaurants and other service establishments) were also impacted, resulting in reductions in operations or closures. The impacts of that slowdown have eased in our service territories and most of the idle/vacant homes have returned to service. If another economic slowdown occurs, our financial condition, results of operations, and cash flows could be adversely affected. Fluctuations and uncertainties in the economy make it challenging for us to accurately forecast and plan future business activities and to identify risks that may affect our business, financial condition, and operating results. We cannot predict the timing, strength, or duration of any future economic slowdowns. If the economy or the markets in which we operate decline from present levels, it may have an adverse effect on our business, financial condition, and results of operations.
We rely on having access to interstate pipelines’ transportation capacity. If these pipelines were not available, it could impact our ability to meet our customers’ full requirements.
We must acquire both sufficient natural gas supplies and interstate pipeline capacity to meet customer requirements. We must contract for reliable and adequate delivery capacity for our distribution system, while considering the dynamics of the interstate pipeline capacity market, our own in-system resources, as well as the characteristics of our customer base. Interruptions to or reductions of interstate pipeline service caused by physical constraints, excessive customer usage, or other force majeure could reduce our normal supply of gas. A prolonged interruption or reduction of interstate pipeline service in any of our jurisdictions, particularly during the winter heating season, would reduce cash flow and earnings.
Our earnings may be materially impacted due to volatility in the cash surrender value of our company-owned life insurance policies during periods in which stock market changes are significant.
We have life insurance policies with a net death benefit value at December 31, 2016 of approximately $241 million on members of management and other key employees to indemnify ourselves against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The net cash surrender value of these policies (which is the cash amount we would receive if we voluntarily terminated the policies) is approximately $107 million at December 31, 2016 and is included in the caption “Other property and investments” on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both
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equity and fixed income (mutual fund) investments. As a result, the cash surrender value (but not the net death benefits) moves up and down consistent with the movements in the broader stock and bond markets. During 2016, the Company recognized income of $7.4 million in Other income (deductions) due to increases in the cash surrender values of its company-owned life insurance policies and net death benefits recognized compared to a loss of $500,000 due to decreases in cash surrender values during 2015. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, changes in the cash surrender value components of company-owned life insurance policies, as they progress towards the ultimate death benefits, are also recorded without tax consequences. Currently, we intend to hold the company-owned life insurance policies for their duration. Changes in the cash surrender value of company-owned life insurance policies, except as related to the purchase of additional policies, affect our earnings but not our cash flows.
The cost of providing pension and postretirement benefits is subject to changes in pension asset values, changing demographics, and actuarial assumptions which may have an adverse effect on our financial results.
We provide pension and postretirement benefits to eligible employees. Our costs of providing such benefits are subject to changes in the market value of our pension fund assets, changing demographics, life expectancies of beneficiaries, current and future legislative changes, and various actuarial calculations and assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, withdrawal rates, interest rates, and other factors. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods. For example, lower than assumed returns on investments and/or reductions in bond yields could result in increased contributions and higher pension expense which would have a negative impact on our cash flows and reduce net income.
Our liquidity, and in certain circumstances our earnings, may be reduced during periods in which natural gas prices are rising significantly or are more volatile.
Increases in the cost of natural gas may arise from a variety of factors, including weather, changes in demand, the level of production and availability of natural gas, transportation constraints, transportation capacity cost increases, federal and state energy and environmental regulation and legislation, the degree of market liquidity, natural disasters, wars and other catastrophic events, national and worldwide economic and political conditions, the price and availability of alternative fuels, and the success of our strategies in managing price risk.
Rate schedules in each of our service territories contain purchased gas adjustment clauses which permit us to file for rate adjustments to recover increases in the cost of purchased gas. Increases in the cost of purchased gas have no direct impact on our profit margins, but do affect cash flows and can therefore impact the amount of our capital resources. We have used short-term borrowings in the past to temporarily finance increases in purchased gas costs, and we expect to do so during 2017, if the need again arises.
We may file requests for rate increases to cover the rise in the cost of purchased gas. Due to the nature of the regulatory process, there is a risk of disallowance of full recovery of these costs during any period in which there has been a substantial run-up of these costs or our costs are more volatile. Any disallowance of purchased gas costs would reduce cash flow and earnings.
The nature of our operations presents inherent risks of loss that could adversely affect our results of operations.
Our operations are subject to inherent hazards and risks such as gas leaks, fires, natural disasters, catastrophic accidents, explosions, pipeline ruptures, and other hazards and risks that may cause unforeseen interruptions, personal injury, or property damage. Additionally, our facilities, machinery, and equipment, including our pipelines, are subject to third party damage from construction activities, vandalism, or acts of terrorism. Such incidents could result in severe business disruptions, significant decreases in revenues, and/or significant additional costs to us. Any such incident could have an adverse effect on our financial condition, earnings, and cash flows. In addition, any of these or similar events could cause environmental pollution, personal injury or death claims, damage to our properties or the properties of others, or loss of revenue by us or others.
We maintain liability insurance for some, but not all, risks associated with the operation of our natural gas pipelines and facilities. In connection with these liability insurance policies, we are 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. These liability insurance policies require us to be responsible for the first $1 million (self-insured retention) of each incident plus the first $4 million in total claims above our self-insured retention in the policy year. We cannot predict the likelihood
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that any future event will occur which will result in a claim exceeding $1 million; however, a large claim for which we were deemed liable would reduce our earnings up to and including these self-insurance maximums.
Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.
Our ability to implement our business strategy and serve our customers is dependent upon our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the knowledge and expertise of our workforce to new employees as our aging employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor could adversely affect our ability to manage and operate our business.
We may not be able to rely on rate decoupling to maintain stable financial position, results of operations, and cash flows.
Management has worked with 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. Rate structures in all service territories allow Southwest to separate or “decouple” the recovery of operating margin from natural gas consumption, though decoupled structures vary by state. In California, authorized operating margin levels vary by month. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin. In Arizona, a full revenue decoupling mechanism (currently, with a winter-period monthly weather adjuster) is in place for most customer classes. Significantly warmer-than-normal weather conditions in our service territories and other factors, such as climate change and alternative energy sources, may result in decreased cash flows attributable to lower natural gas sales and delays in recovering regulatory asset balances. Furthermore, continuation of the decoupled rate designs currently in place are subject to regulatory discretion, and if unfavorably modified or discontinued could adversely impact our financial position and results of operations.
A significant reduction in our credit ratings could materially and adversely affect our business, financial condition, and results of operations.
We cannot be certain that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Our credit ratings are subject to change at any time in the discretion of the applicable ratings agencies. Numerous factors, including many which are not within our control, are considered by the ratings agencies in connection with assigning credit ratings.
Any future downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in certain current, as well as future, financings, and our potential pool of investors and funding sources could decrease. A downgrade could require additional support in the form of letters of credit or cash or other collateral and otherwise adversely affect our business, financial condition and results of operations.
Uncertain economic conditions may affect our ability to finance capital expenditures.
Our ability to finance capital expenditures and other matters will depend upon general economic conditions in the capital markets. Declining interest rates are generally believed to be favorable to utilities while rising interest rates are believed to be unfavorable because of the high capital costs of utilities. In addition, our authorized rate of return is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, our authorized rate of return in the future could be reduced. If interest rates are higher than assumed rates, it will be more difficult for us to earn our currently authorized rate of return.
We require numerous permits and other approvals from various federal, state, and local governmental agencies to operate our business; any failure to obtain or maintain required permits or approvals could negatively affect our business and results of operations.
All of our existing and planned development projects require multiple permits. The acquisition, ownership and operation of natural gas pipelines and storage facilities require numerous permits, approvals and certificates from federal, state, and local governmental agencies. Once received, approvals may be subject to litigation, and projects may be delayed or approvals reversed in litigation. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approvals or to comply with any applicable laws or regulations, we may not be able to construct or operate our facilities, or we may be forced to incur additional costs.
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A cybersecurity incident has the potential to disrupt normal business operations, expose sensitive information, and/or lead to physical damages.
As a utility provider, maintaining business operations is critical for our customers, business partners, suppliers, and our employees. A disruption in service could adversely impact our reputation, ability to provide utility services for our customers, as well as impact the media used to communicate and exchange information both internally and externally.
We process and store sensitive information including personal identifiable information, intellectual property, and business proprietary information as part of normal business operations. A cybersecurity breach of this information could expose us to monetary and other damages from customers, suppliers, business partners, government agencies, and others. In addition, a breach could increase costs incurred to protect against such risks, introduce financial penalties, and increase regulation for the industry.
Physical damage due to a cybersecurity incident or acts of cyber terrorism could impact utility services provided to our customers and could lead to material liabilities. We have taken the initiative in fortifying the core infrastructure that supports the utility services provided to our customers. While these measures do not eliminate the threats, they do provide layers of defense to mitigate these risks. Even though we have insurance coverage in place for cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.
We may pursue acquisitions and other strategic transactions, the success of which may impact our results of operations, cash flows and financial condition.
The integration of acquisitions requires significant time and resources. Investments of resources would be required to support any acquisition, which could result in significant ongoing operating expenses and may divert resources and management attention from other areas of our business. If we fail to successfully integrate companies we acquire, we may not realize the benefits expected from the transaction and goodwill recorded as a result of the acquisition could be impaired. We assess existing goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of an operating segment below its carrying value. We also assess long-lived assets, including intangible assets associated with acquisitions for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets becomes impaired, the impairment charges could have a material impact on our results of operations.
Weather conditions in Centuri’s operating areas can adversely affect operations, financial position, and cash flows.
Centuri’s results of operations, financial position, and cash flows can be significantly impacted by changes in weather that affect the ability of Centuri to provide utility companies with contracted-for trenching, installation, and replacement of underground pipes, as well as maintenance services for energy distribution systems. Generally, Centuri’s revenues are lowest during the first quarter of the year due to less favorable winter weather conditions.
Fixed-price contracts at Centuri are subject to potential losses that could adversely affect results of operations.
Centuri enters into a variety of types of contracts customary in the underground utility construction industry. These contracts include unit-priced contracts, unit-priced contracts with revenue caps, and fixed-price (lump sum) contracts. Contracts with caps and fixed-price arrangements can be susceptible to constrained profits, or even losses, especially those contracts that cover an extended-duration performance period. This is due, in part, to the necessity of estimating costs far in advance of the completion date (at bid inception). Unforeseen inflation, or other costs unanticipated at inception, can detrimentally impact profitability for these types of contracts.
Loss of one or more significant customers could adversely affect the results of the construction services segment.
During 2016, over half of the construction services revenues were generated from seven customers. This concentration of risk could be impactful to operating results if construction work slowed or halted with one or more of these customers, if competition for work increased, or if existing contracts were not replaced or extended.
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Disruptions in labor relations with Centuri’s employees could adversely affect results of operations.
The majority of Centuri’s labor force is covered by collective bargaining agreements with labor unions, which is typical of the utility construction industry. Labor disruptions, boycotts, strikes, or significant negotiated wage and benefit increases at Centuri, whether due to employee turnover or otherwise, could have a material adverse effect on Centuri’s business and our results of operations and cash flows.
| UNRESOLVED STAFF COMMENTS |
None.
| PROPERTIES |
The plant investment of Southwest consists primarily of transmission and distribution mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators, which comprise the pipeline systems and facilities located in and around the communities served. Southwest also includes other properties such as land, buildings, furnishings, work equipment, vehicles, and software systems in plant investment. The northern Nevada and northern California properties of Southwest are referred to as the northern system; the Arizona, southern Nevada, and southern California properties are referred to as the southern system. Several properties are leased by Southwest. Total gas plant, exclusive of leased property, at December 31, 2016 was $6.3 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.
Substantially all gas main and service lines are constructed across property owned by others under right-of-way grants obtained from the record owners thereof, on the streets and grounds of municipalities under authority conferred by franchises or otherwise, or on public highways or public lands under authority of various federal and state statutes. None of the numerous county and municipal franchises are exclusive, and some are of limited duration. These franchises are renewed regularly as they expire, and Southwest anticipates no serious difficulties in obtaining future renewals.
With respect to the right-of-way grants, Southwest has had continuous and uninterrupted possession and use of all such rights-of-way, and the associated gas mains and service lines, commencing with the initial stages of construction of such facilities. Permits have been obtained from public authorities and other governmental entities in certain instances to cross or to lay facilities along roads and highways. These permits typically are revocable at the election of the grantor and Southwest occasionally must relocate its facilities when requested to do so by the grantor. Permits have also been obtained from railroad companies to cross over or under railroad lands or rights-of-way, which in some instances require annual or other periodic payments and are revocable at the election of the grantors.
Southwest operates two primary pipeline transmission systems:
| • |
a system (including an LNG storage facility) owned by Paiute extending from the Idaho-Nevada border to the Reno, Sparks, and Carson City areas and communities in the Lake Tahoe area in both California and Nevada and other communities in northern and western Nevada; and |
| • |
a system extending from the Colorado River at the southern tip of Nevada to the Las Vegas distribution area. |
Southwest provides natural gas service in parts of Arizona, Nevada, and California. Service areas in Arizona include most of the central and southern areas of the state including Phoenix, Tucson, Yuma, and surrounding communities. Service areas in northern Nevada include Carson City, Yerington, Fallon, Lovelock, Winnemucca, and Elko. Service areas in southern Nevada include the Las Vegas valley (including Henderson and Boulder City) and Laughlin. Service areas in southern California include Barstow, Big Bear, Needles, and Victorville. Service areas in northern California include the Lake Tahoe area and Truckee.
Information on properties of Centuri can be found in this Form 10-K under Construction Services.
| LEGAL PROCEEDINGS |
We are named as a defendant in various legal proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that none of this litigation individually or in the aggregate will have a material adverse impact on our financial position, results of operations, or cash flows.
| MINE SAFETY DISCLOSURES |
Not applicable.
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| EXECUTIVE OFFICERS OF THE REGISTRANT |
The listing of the executive officers is set forth under Part III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE, which by this reference is incorporated herein.
| MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The principal market on which the common stock of Southwest Gas Holdings, Inc. is traded is the New York Stock Exchange. At February 15, 2017, there were 13,488 holders of record of common stock, and the market price of the common stock was $82.93. The quarterly market price of, and dividends on, common stock required by this item are included in the Company’s 2016 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.
Dividends are payable on the Company’s common stock at the discretion of the Board of Directors (“Board”). In setting the dividend rate, the Board considers, among other factors, current and expected future earnings levels, our ongoing capital expenditure plans and expected external funding needs, our payout ratio, and our ability to maintain strong credit ratings and liquidity. The Company has paid dividends on its common stock since 1956 and has increased that dividend each year since 2007. In February 2017, the Board elected to increase the quarterly dividend from $0.45 to $0.495 per share, representing a 10% increase, effective with the June 2017 payment. The Board currently targets a payout ratio of 55% to 65% of consolidated earnings per share. The quarterly common stock dividend declared was 36.5 cents per share throughout 2014, 40.5 cents per share throughout 2015, and 45 cents per share throughout 2016.
| SELECTED FINANCIAL DATA |
Information required by this item is included in the 2016 Annual Report to Shareholders and is incorporated herein by reference.
| MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Information required by this item is included in the 2016 Annual Report to Shareholders and is incorporated herein by reference.
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We are exposed to various forms of market risk, including commodity price risk, weather risk, interest rate risk, and foreign currency exchange rate risk. The following describes our exposure to these risks.
Commodity Price Risk
In managing its natural gas supply portfolios, Southwest has historically entered into short duration (generally one year or less) fixed-price contracts and variable-price contracts (firm and spot). Southwest has experienced price volatility over the past several years and such volatility is expected to continue into 2017 and beyond.
Southwest is protected financially from commodity price risk by deferred energy or purchased gas adjustment (collectively “PGA”) mechanisms in each of its jurisdictions. These mechanisms generally allow Southwest to defer over- or under-collections of gas costs to PGA balancing accounts. With regulatory approval, Southwest can either refund amounts over-collected or recoup amounts under-collected in future periods. In addition to the PGA mechanism, Southwest utilizes volatility mitigation programs to attempt to further reduce price volatility for customers. Under these programs, Southwest fixes the price of a portion (up to 25% in the Arizona and California jurisdictions) of its natural gas portfolio using fixed-price contracts and/or derivative instruments (fixed-for-floating swaps), and where available, natural gas storage.
In late 2013, the utilization of swaps and fixed-price purchases pursuant to the Volatility Mitigation Program was suspended for Southwest’s Nevada service territories. Management along with regulators will continue to evaluate this strategy in light of prevailing or anticipated changing market conditions.
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Southwest’s natural gas purchasing practices are subject to prudence review by the various regulatory bodies in each jurisdiction. PGA changes affect cash flows and potentially short-term borrowing requirements, but do not directly impact profit margin.
Weather Risk
Rate design is the primary mechanism available to Southwest to mitigate weather risk. All of Southwest’s service territories have decoupled rate structures which mitigate weather risk. In California, CPUC regulations allow Southwest to decouple operating margin from usage and offset weather risk. In Nevada, a decoupled rate structure applies to most customer classes providing stability in annual operating margin by insulating us from the effects of lower usage (including volumes associated with unusual weather). In Arizona, a full revenue decoupling mechanism (currently, with a winter-period monthly weather adjuster), is in place for most customer classes. With decoupled rate structures, Southwest’s operating margin is limited during unusually cold weather. Additionally, Southwest is not assured that decoupled rate structures will continue to be supported in future rate cases.
Interest Rate Risk
Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. The primary interest rate risk for us is the risk of increasing interest rates on variable-rate obligations. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. In Nevada, fluctuations in interest rates on $150 million of variable-rate Industrial Development Revenue Bonds (“IDRBs”) are tracked and recovered from ratepayers through an interest balancing account, which mitigates risk to earnings and cash flows from interest rate fluctuations on these IDRBs between general rate cases. As of December 31, 2016 and 2015, Southwest had $55 million and $218 million, respectively, in variable-rate debt outstanding, excluding the IDRBs noted above. Assuming a constant outstanding balance on variable-rate debt for the next twelve months, a hypothetical 1% change in interest rates would increase or decrease interest expense for the next twelve months by approximately $550,000. As of December 31, 2016 and 2015, Centuri had approximately $148 million and $173 million, respectively, in variable-rate debt outstanding. Assuming a constant outstanding balance in variable-rate debt for the next twelve months, a hypothetical 1% change in interest rates would increase or decrease interest expense for the next twelve months by approximately $1,480,000.
Foreign Currency Exchange Rate Risk
We own construction services businesses that operate in Canada. Due to these operations, we are exposed to market risk associated with foreign currency exchange rate fluctuations between the Canadian dollar and the U.S. dollar. Foreign currency translation risk is the risk that exchange rate gains or losses arise from translating foreign entities’ statements of income and balance sheets from their functional currency (the Canadian Dollar) to our reporting currency (the U.S. Dollar) for consolidation purposes. During 2016, translation adjustments due to fluctuations in exchange rates were not significant. We do not have exposure to other foreign currency exchange rate fluctuations.
Other risk information is included in Item 1A. Risk Factors of this report.
| FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The Consolidated Financial Statements of Southwest Gas Corporation (the predecessor to Southwest Gas Holdings, Inc., which was formed in January 2017) and Subsidiaries including the Notes thereto, together with the report of PricewaterhouseCoopers LLP, are included in the 2016 Annual Report to Shareholders and are incorporated herein by reference.
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
We have established disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management,
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including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and benefits of controls must be considered relative to their costs. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected.
Based on the most recent evaluation, as of December 31, 2016, management, including the Chief Executive Officer and Chief Financial Officer, believes our disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.
Internal Control Over Financial Reporting
The report of management required to be reported herein is incorporated by reference to the information reported in the 2016 Annual Report to Shareholders under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 91.
The Attestation Report of the Independent Registered Public Accounting Firm required to be reported herein is incorporated by reference to the information reported in the 2016 Annual Report to Shareholders under the caption “Report of Independent Registered Public Accounting Firm” on page 92.
There have been no changes in our internal controls over financial reporting (as defined in Rules 13a–15(f) and 15d-15(f) under the Exchange Act) that occurred during the most recent fiscal quarter that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.
| OTHER INFORMATION |
On February 23, 2017, the Board of Directors of Southwest Gas Holdings, Inc. approved the following compensation program established by the Compensation Committee, which established, for eligible employees, new annual and long-term incentive programs under the Management Incentive Plan and the 2006 Restricted Stock/Unit Plan. The named executive officers currently serving as officers are participants in both programs.
Annual incentives under the Management Incentive Plan will be payable in cash and will be based on net income measures, customer satisfaction, safety, and operations and maintenance expense per customer. The annual incentives will be subject to minimum thresholds. The target annual incentive opportunity and the range of payments for the named executive officers are as follows:
| Named Executive Officer |
Target Annual Incentive (as percentage of base salary) |
Range of Payment Relative to Target (if earned) | ||
| John P. Hester, President and Chief Executive Officer |
100% | 70% to 140% | ||
| Roy R. Centrella, Senior Vice President/Chief Financial Officer |
60% | 70% to 140% | ||
| Karen S. Haller, Senior Vice President/General Counsel and Corporate Secretary |
60% | 70% to 140% | ||
| Eric DeBonis, Senior Vice President/Operations |
50% | 70% to 140% |
As of January 1, 2017, the named executive officers were granted time-based restricted stock unit awards under the 2006 Restricted Stock/Unit Plan. Each time-based restricted stock unit award is eligible to vest as to 40% of the covered shares on the first anniversary of the grant date, and as to 30% of the covered shares on each of the second and third anniversaries of the grant date. The restricted stock unit awards for the named executive officers are as follows:
| Named Executive Officer |
Award (as percentage of base salary) | |
| John P. Hester |
60% | |
| Roy R. Centrella |
30% | |
| Karen S. Haller |
30% | |
| Eric DeBonis |
30% |
16
Performance-based incentive opportunities under the 2006 Restricted Stock/Unit Plan were granted in the form of performance shares and will be based on, depending on the officer, consolidated earnings per share, utility net income, and return on equity, with an adjustment based on relative total shareholder return, in each case measured over three years. The target performance share opportunities and the range of performance share payments for the three-year performance period from January 1, 2017, to December 31, 2019, for the named executive officers are as follows:
| Named Executive Officer |
Target Award (as percentage of base salary) |
Range of Award Payment Relative to Target (if earned) |
||||
| John P. Hester |
140% | 50% to 195% | ||||
| Roy R. Centrella |
70% | 50% to 195% | ||||
| Karen S. Haller |
70% | 50% to 195% | ||||
| Eric DeBonis |
60% | 50% to 195% | ||||
The foregoing descriptions of the awards are qualified by reference to the applicable administrative provisions of the Management Incentive Plan and the 2006 Restricted Stock/Unit Plan, which are incorporated herein by reference to the 2016 Proxy Statement filed on Schedule 14A on March 31, 2016 and 2014 Proxy Statement filed on Schedule 14A on March 26, 2014, respectively.
| DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
(a) Identification of Directors. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(b) Identification of Executive Officers. The name, age, position, and period position held during the last five years for each of the Executive Officers of the Company as of December 31, 2016 are as follows:
| Name |
Age |
Position |
Period Position Held | |||
| John P. Hester |
54 | President and Chief Executive Officer President Executive Vice President Senior Vice President/Regulatory Affairs & Energy Resources |
2015-Present 2014-2015 2013-2014 2012-2013 | |||
| Roy R. Centrella |
59 | Senior Vice President/Chief Financial Officer |
2012-Present | |||
| Eric DeBonis |
49 | Senior Vice President/Operations Senior Vice President/Staff Operations & Technology |
2012-Present 2012 | |||
| Karen S. Haller |
53 | Senior Vice President/General Counsel and Corporate Secretary Vice President/General Counsel, Compliance Officer, and Corporate Secretary |
2012-Present 2012 | |||
| Anita M. Romero |
54 | Senior Vice President/Staff Operations & Technology Vice President/Information Services Vice President/Special Projects |
2013-Present 2012-2013 2012 | |||
| Kenneth J. Kenny |
54 | Vice President/Finance/Treasurer |
2012-Present | |||
| Gregory J. Peterson |
57 | Vice President/Controller and Chief Accounting Officer |
2012-Present | |||
(c) Identification of Certain Significant Employees. None.
(d) Family Relationships. No Directors or Executive Officers are related either by blood, marriage, or adoption.
(e) Business Experience. Information with respect to Directors is set forth under the heading “Election of Directors” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein. All Executive Officers have held responsible positions with us for at least five years as described in (b) above.
(f) Involvement in Certain Legal Proceedings. None.
(g) Promoters and Control Persons. None.
17
(h) Audit Committee Financial Expert. Information with respect to the financial expert of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(i) Identification of the Audit Committee. Information with respect to the composition of the Board of Directors’ audit committee is set forth under the heading “Committees of the Board” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(j) Material Changes in Director Nomination Procedures for Security Holders. None.
Section 16(a) Beneficial Ownership Reporting Compliance. We have adopted procedures to assist directors and executive officers in complying with Section 16(a) of the Exchange Act which includes assisting in the preparation of forms for filing. Based upon a review of filings with the SEC and written representations that no other reports were required, we believe that all directors and executive officers complied during 2016 with the reporting requirements of Section 16(a) of the Exchange Act.
Code of Business Conduct and Ethics. We have adopted a code of business conduct and ethics for employees, including the president and chief executive officer, chief financial officer, chief accounting officer, and non-employee directors. A code of ethics is defined as written standards that are reasonably designed to deter wrongdoing and to promote: 1) honest and ethical conduct; 2) full, fair, accurate, timely, and understandable disclosure in reports and documents that a registrant files; 3) compliance with applicable governmental laws, rules, and regulations; 4) the prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and 5) accountability for adherence to the code. The Code of Business Conduct and Ethics can be viewed on the website (www.swgasholdings.com). If any substantive amendments to the Code of Business Conduct and Ethics are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct & Ethics, to our president and chief executive officer, chief financial officer and chief accounting officer, the nature of such amendment or waiver will be disclosed on www.swgasholdings.com.
| EXECUTIVE COMPENSATION |
Information with respect to executive compensation is set forth under the heading “Executive Compensation” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(a) Compensation Committee Interlocks and Insider Participation. Information with respect to Compensation Committee interlocks and insider participation is set forth under the heading “Governance of the Company” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(b) Compensation Committee Report. Information with respect to the Compensation Committee Report is set forth under the heading “Compensation Committee Report” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
(a) Security Ownership of Certain Beneficial Owners. Information with respect to security ownership of certain beneficial owners is set forth under the heading “Securities Ownership by Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(b) Security Ownership of Management. Information with respect to security ownership of management is set forth under the heading “Securities Ownership by Directors, Director Nominees, Executive Officers, and Certain Beneficial Owners” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
(c) Changes in Control. None.
(d) Securities Authorized for Issuance Under Equity Compensation Plans. At December 31, 2016, we had stock-based compensation plans for Southwest employees. We previously granted options to purchase shares of common stock to key employees and outside directors. The option grants in 2006 consumed the remaining options that could be issued under the option plan. All options have been exercised. Information with regard to the management incentive plan and the restricted stock/unit plan is provided in the following tables.
18
Pursuant to the terms of the management incentive plan, we may issue performance shares to encourage key employees to remain employed to achieve short-term and long-term performance goals.
| Plan category |
Number of securities to be issued upon vesting of performance shares |
Weighted-average grant date fair value of award |
Number of securities remaining available for future issuance (excluding securities reflected in column a) |
|||||||||
| (a) | (b) | (c) | ||||||||||
| (Thousands of shares) | ||||||||||||
| Equity compensation plans approved by security holders |
168 | $ | 55.62 | 818 | ||||||||
| Equity compensation plans not approved by security holders |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
168 | $ | 55.62 | 818 | ||||||||
|
|
|
|
|
|
|
|||||||
Pursuant to the terms of the restricted stock/unit plan, we may award restricted stock and restricted stock units to attract, motivate, retain and reward key employees with incentives for high levels of individual performance and improved financial performance and to attract, motivate, and retain experienced and knowledgeable independent directors.
| Plan category |
Number of securities to be issued upon vesting of restricted stock units |
Weighted-average grant date fair value of award |
Number of securities remaining available for future issuance (excluding securities reflected in column a) |
|||||||||
| (a) | (b) | (c) | ||||||||||
| (Thousands of shares) | ||||||||||||
| Equity compensation plans approved by security holders |
262 | $ | 46.41 | 365 | ||||||||
| Equity compensation plans not approved by security holders |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
262 | $ | 46.41 | 365 | ||||||||
|
|
|
|
|
|
|
|||||||
Additional information regarding the equity compensation plans is included in Note 11 of the Notes to Consolidated Financial Statements in the 2016 Annual Report to Shareholders.
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information with respect to certain relationships and related transactions, and director independence is set forth under the heading “Governance of the Company” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
| PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information with respect to accounting fees and services associated with PricewaterhouseCoopers LLP is set forth under the heading “Selection of Independent Registered Public Accounting Firm” in the definitive Southwest Gas Holdings, Inc. 2017 Proxy Statement, which by this reference is incorporated herein.
19
| EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| (a) |
The following documents are filed as part of this report on Form 10-K: |
| (1) |
The Consolidated Financial Statements of the Company (including the Report of Independent Registered Public Accounting Firm) required to be reported herein are incorporated by reference to the information reported in the 2016 Annual Report to Shareholders under the following captions: |
| (2) |
All schedules have been omitted because the required information is either inapplicable or included in the Notes to Consolidated Financial Statements. |
| (3) |
See LIST OF EXHIBITS. |
| (b) |
See LIST OF EXHIBITS. |
| FORM 10–K SUMMARY. |
None.
20
| Exhibit Number |
Description of Document | |
| 2.01 |
Plan of Reorganization, dated December 28, 2016, by and among Southwest Gas Corporation, Southwest Reorganization Co., Southwest Gas Holdings, Inc. and Southwest Gas Utility Group, Inc. Incorporated herein by reference to Exhibit 2.1 to Form 8-K dated December 28, 2016, File No. 1-07850. | |
| 2.02 |
Agreement and Plan of Merger, dated December 28, 2016, by and among Southwest Gas Corporation, Southwest Reorganization Co. and Southwest Gas Holdings, Inc. Incorporated herein by reference to Exhibit 2.2 to Form 8-K dated December 28, 2016, File No. 1-07850. | |
| 3(i) |
Articles of Incorporation of Southwest Gas Holdings, Inc. Incorporated herein by reference to Exhibit 3.1 to Form 8-K dated December 28, 2016, File No. 1-07850. | |
| 3(i) |
Articles of Incorporation with Statement of Conversion of Southwest Gas Corporation. | |
| 3(ii) |
Bylaws of Southwest Gas Holdings, Inc. Incorporated herein by reference to Exhibit 3.2 to Form 8-K dated December 28, 2016, File No. 1-07850. | |
| 3(ii) |
Bylaws of Southwest Gas Corporation. | |
| 4.01 |
Indenture between City of Big Bear Lake, California, and Harris Trust and Savings Bank as Trustee, dated December 1, 1993, with respect to the issuance of $50,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation Project), 1993 Series A, due 2028. Incorporated herein by reference to Exhibit 4.11 to Form 10-K for the year ended December 31, 1993, File No. 1-07850. | |
| 4.02 |
Indenture between Southwest Gas Corporation and Harris Trust and Savings Bank dated July 15, 1996, with respect to Debt Securities. Incorporated herein by reference to Exhibit 4.04 to Form 8-K dated July 26, 1996, File No. 1–07850. | |
| 4.03 |
First Supplemental Indenture of Southwest Gas Corporation to Harris Trust and Savings Bank dated August 1, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to 7 1/2% and 8% Debentures, due 2006 and 2026, respectively. Incorporated herein by reference to Exhibit 4.11 to Form 8-K dated July 31, 1996, File No. 1-07850. | |
| 4.04 |
Second Supplemental Indenture of Southwest Gas Corporation to Harris Trust and Savings Bank dated December 30, 1996, supplementing and amending the Indenture dated as of July 15, 1996, with respect to Medium-Term Notes. Incorporated herein by reference to Exhibit 4.04 to Form 8-K dated December 30, 1996, File No. 1–07850. | |
| 4.05 |
Certificate of Trust of Southwest Gas Capital III. Incorporated herein by reference to Exhibit 4.04 to Form S–3 dated August 7, 2003, File No. 333-106419. | |
| 4.06 |
Certificate of Trust of Southwest Gas Capital IV. Incorporated herein by reference to Exhibit 4.05 to Form S–3 dated August 7, 2003, File No. 333-106419. | |
21
| Exhibit Number |
Description of Document | |
| 4.07 |
Trust Agreement of Southwest Gas Capital III. Incorporated herein by reference to Exhibit 4.07 to Form S-3 dated August 7, 2003, File No. 333-106419. | |
| 4.08 |
Trust Agreement of Southwest Gas Capital IV. Incorporated herein by reference to Exhibit 4.08 to Form S-3 dated August 7, 2003, File No. 333-106419. | |
| 4.09 |
Form of Southwest Gas Holdings, Inc. Common Stock Certificate. Incorporated herein by reference to Exhibit 4.1 to Form S-3 dated January 4, 2017, File No. 333-208609-01. | |
| 4.10 |
Form of Southwest Gas Corporation Common Stock Certificate. Incorporated herein by reference to Exhibit 4 to Form 8-K dated July 22, 2003, File No. 1-07850. | |
| 4.11 |
Indenture of Trust between Clark County, Nevada, and the Bank of New York Trust Company, N.A. as Trustee, dated as of October 1, 2005, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2005A. Incorporated herein by reference to Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005, File No. 1-07850. | |
| 4.12 |
Indenture of Trust between Clark County, Nevada, and the Bank of New York Trust Company, N.A. as Trustee, dated as of September 1, 2006, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2006A. Incorporated herein by reference to Exhibit 4.01 to Form 10-Q for the quarter ended September 30, 2006, File No. 1-07850. | |
| 4.13 |
Indenture of Trust between Clark County, Nevada, and the BNY Midwest Trust Company, as Trustee, dated as of March 1, 2003, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2003. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850. | |
| 4.14 |
Indenture of Trust between Clark County, Nevada and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated as of September 1, 2008, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2008A. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850. | |
| 4.15 |
Indenture of Trust between Clark County, Nevada and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated December 1, 2009, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2009A. Incorporated herein by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2009, File No. 1-07850. | |
| 4.16 |
Note Purchase Agreement, dated November 18, 2010, by and between Southwest Gas Corporation and Metropolitan Life Insurance Company, John Hancock Life Insurance Company (U.S.A.), certain of their respective affiliates, and Union Fidelity Life Insurance Company. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated November 18, 2010, File No. 1-07850. | |
| 4.17 |
Amendment No. 1 to Note Purchase Agreement, dated March 28, 2014, by and among Southwest Gas Corporation and the holders of the Notes. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated March 31, 2014, File No. 1–07850. | |
| 4.18 |
Amendment No. 2 to Note Purchase Agreement, dated September 30, 2016, by and among Southwest Gas Corporation and the holders of the Notes. Incorporated herein by reference to Exhibit 4.02 to Form 10-Q for the quarter ended September 30, 2016, File No. 1–07850. | |
| 4.19 |
Form of 6.1% Senior Note due 2041. Incorporated herein by reference to Exhibit 4.2 to Form 8-K dated November 18, 2010, File No. 1-07850. | |
| 4.20 |
Indenture, dated December 7, 2010, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 7, 2010, File No. 1-07850. | |
| 4.21 |
First Supplemental Indenture, dated as of December 10, 2010, supplementing and amending the indenture dated as of December 7, 2010, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (including the Form of 4.45% Senior Notes due 2020). Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 10, 2010, File No. 1-07850. | |
| 4.22 |
Indenture, dated March 23, 2012, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. 3.875% Notes due 2022. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated March 20, 2012, File No. 1-07850. | |
22
| Exhibit Number |
Description of Document | |
| 4.23 |
Indenture, dated as of October 4, 2013, by and between Southwest Gas Corporation and the Bank of New York Mellon Trust Company, N.A., as Trustee. 4.875% Notes due 2043. Incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 1, 2013. File No. 1-07850. | |
| 4.24 |
Southwest Gas Corporation Dividend Reinvestment and Direct Stock Purchase Plan. Incorporated by reference to Exhibit 4.4 to Form S-3ASR dated December 18, 2015, File No. 333-208609. | |
| 4.25 |
Indenture, dated September 29, 2016, by and between Southwest Gas Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. 3.80% Senior Notes due 2046. Incorporated herein by reference to Exhibit 4.01 to Form 10-Q for the quarter ended September 30, 2016, File No. 1-07850. | |
| 4.26 |
The Company and Southwest hereby agree to furnish to the SEC, upon request, a copy of any instruments defining the rights of holders of long-term debt issued by Southwest Gas Holdings or its subsidiaries; the total amount of securities authorized thereunder does not exceed 10% of the consolidated total assets of Southwest Gas Holdings and its subsidiaries. | |
| 10.01 |
Project Agreement between Southwest Gas Corporation and City of Big Bear Lake, California, dated as of December 1, 1993. Incorporated herein by reference to Exhibit 10.05 to Form 10-K for the year ended December 31, 1993, File No. 1-07850. | |
| 10.02 * |
Southwest Gas Corporation Supplemental Retirement Plan, amended and restated as of January 1, 2005. Incorporated herein by reference to Exhibit 10.03 to Form 10-K for the year ended December 31, 2007, File No. 1–07850. | |
| 10.03 * |
Southwest Gas Corporation Board of Directors Retirement Plan, amended and restated as of January 1, 2005. Incorporated herein by reference to Exhibit 10.04 to Form 10-K for the year ended December 31, 2007, File No. 1-07850. | |
| 10.04 * |
Form of Change in Control Agreement with Officers. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated November 14, 2013, File No. 1-07850. | |
| 10.05 * |
Southwest Gas Corporation Management Incentive Plan, amended and restated. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 26, 2014, File No. 1–07850. | |
| 10.06 * |
Southwest Gas Corporation Executive Deferral Plan, amended and restated March 1, 2008, effective January 1, 2005. Southwest Gas Corporation Executive Deferral Plan, amended and restated effective January 1, 2009. Incorporated herein by reference to Exhibit 10.10 to Form 10-K for the year ended December 31, 2008, File No. 1-07850. | |
| 10.07 * |
Southwest Gas Corporation Directors Deferral Plan, amended and restated effective January 1, 2009. Incorporated herein by reference to Exhibit 10.11 to Form 10-K for the year ended December 31, 2008, File No. 1-07850. | |
| 10.08 |
Financing agreement dated as of March 1, 2003 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2003A, Series 2003B, Series 2003C, Series 2003D and Series 2003E. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 2003, File No. 1-07850. | |
| 10.09 |
First Amendment to Financing Agreement by and between Clark County, Nevada, and Southwest Gas Corporation dated as of July 1, 2005, amending the Financing Agreement dated as of March 1, 2003, with respect to Clark County, Nevada Industrial Development Revenue Bonds Series 2003A, Series 2003B, Series 2003C, Series 2003D, and Series 2003E. Incorporated herein by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2005, File No. 1-07850. | |
23
| Exhibit Number |
Description of Document | |
| 10.10 |
Financing Agreement between Clark County, Nevada, and Southwest Gas Corporation, dated as of September 1, 2008, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2008A. Incorporated herein by reference to Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2008, File No. 1-07850. | |
| 10.11 |
Financing Agreement between Clark County, Nevada and Southwest Gas Corporation, dated December 1, 2009, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2009A. Incorporated herein by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 2009, File No. 1-07850. | |
| 10.12 |
Southwest Gas Corporation $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 15, 2012, File No. 1-07850. | |
| 10.13 |
Amendment No. 1 to Revolving Credit Agreeement, dated as of March 25, 2014, by and among Southwest Gas Corporation, each of the lenders parties to the Revolving Credit Agreeement referred to therein, and the Bank of New York Mellon, as Administrative Agent. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 25, 2014, File No. 1–07850. | |
| 10.14 |
Amendment No. 2 to Revolving Credit Agreeement, dated as of March 25, 2015, by and among Southwest Gas Corporation, each of the lenders parties to the Revolving Credit Agreeement referred to therein, and the Bank of New York Mellon, as Administrative Agent. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 24, 2015, File No. 1–07850. | |
| 10.15 |
Amendment No. 3 to Revolving Credit Agreeement, dated as of March 28, 2016, by and among Southwest Gas Corporation, each of the lenders parties to the Revolving Credit Agreeement referred to therein, and the Bank of New York Mellon, as Administrative Agent. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 28, 2016, File No. 1–07850. | |
| 10.16 * |
Southwest Gas Corporation 2006 Restricted Stock/Unit Plan, as amended and restated. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 31, 2016, File No. 1-07850. | |
| 10.17 |
NPL (Centuri) $300 million Credit Facility Agreement. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2014, File No. 1-07850. | |
| 10.18 |
Amendment No. 1 to Credit Agreeement, dated as of January 13, 2016, by and among NPL Construction Co. and Centuri Construction Group, Inc., as US Borrowers, Lynxus Construction Group Inc., a corporation organized under the laws of the Province of Ontario, Canada, as Canadian Borrower, the Lenders party thereto, and Wells Fargo Bank, as Administrative Agent. Incorporated herein by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 2015, File No. 1-07850. | |
| 10.19 * |
Form of Performance Share Award Agreement with Named Executive Officers | |
| 10.20 * |
Form of Restricted Stock Unit Award Agreement with Named Executive Officers | |
| 12.02 |
Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation. | |
| 13.01 |
Portions of Southwest Gas Corporation 2016 Annual Report to Shareholders incorporated by reference to the Form 10-K. | |
| 21.01 |
List of subsidiaries of Southwest Gas Corporation. | |
| 23.01 |
Consent of PricewaterhouseCoopers LLP, an independent registered public accounting firm. | |
| 31.02 |
Southwest Gas Corporation Section 302 Certifications. | |
| 32.01 |
Southwest Gas Corporation Section 906 Certifications. | |
| 101.INS |
XBRL Instance Document | |
| 101.SCH |
XBRL Schema Document | |
| 101.CAL |
XBRL Calculation Linkbase Document | |
| 101.LAB |
XBRL Label Linkbase Document | |
| 101.PRE |
XBRL Presentation Linkbase Document | |
| 101.DEF |
XBRL Definition Linkbase Document | |
| * |
Management Contracts or Compensation Plans |
24
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| SOUTHWEST GAS CORPORATION | ||||||
|
(registrant) | ||||||
| Date: February 28, 2017 |
By: |
/S/ JOHN P. HESTER | ||||
| John P. Hester | ||||||
| President and Chief Executive Officer | ||||||
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| Signature |
Title |
Date | ||
| /S/ JOHN P. HESTER (John P. Hester) |
Director, President and Chief Executive Officer |
February 28, 2017 | ||
| /S/ MICHAEL J. MELARKEY (Michael J. Melarkey) |
Director |
February 28, 2017 | ||
| /S/ KAREN S. HALLER (Karen S. Haller) |
Director, Senior Vice President/General Counsel and Corporate Secretary |
February 28, 2017 | ||
| /S/ ROY R. CENTRELLA (Roy R. Centrella) |
Director, Senior Vice President/Chief Financial Officer |
February 28, 2017 | ||
| /S/ GREGORY J. PETERSON (Gregory J. Peterson) |
Vice President, Controller, and Chief Accounting Officer |
February 28, 2017 | ||
26
Exhibit 3(i)
Articles of Incorporation with Statement of Conversion
I
The name of the corporation is Southwest Gas Corporation.
II
The purpose of the corporation is to engage in any lawful act or activity for which a corporation may be organized under the General Corporation Law of California other than the banking business, the trust company business or the practice of a profession permitted to be incorporated by the California Corporations Code.
III
This corporation is authorized to issue three classes of shares of stock, to be designated respectively, as “Preferred Stock;” “Preference Stock;” and “Common Stock.” The total number of shares which this corporation shall have authority to issue is 67,000,000 and the aggregate par value of all shares that are to have a par value shall be $100,000,000. The number of shares of Preferred Stock shall be 5,000,000 and without par value; the number of shares of Preference Stock shall be 2,000,000 and shall have a par value of each share of said class of $20; the number of shares of Common Stock shall be 60,000,000 and shall have a par value of each share of said class of $1.
| 1. | PREFERRED STOCK |
Except as otherwise provided by law, shares of Preferred Stock may be issued from time to time, in one or more series, and the Board of Directors of the corporation is authorized to fix the rights, preferences, privileges and restrictions granted to or imposed upon any such wholly unissued series.
| 2. | PREFERENCE STOCK |
Except as otherwise provided by law, shares of Preference Stock may be issued from time to time, in one or more series, and the Board of Directors of the corporation is authorized to fix the dividend rights, dividend rates, conversion rights, voting rights, rights and terms of redemption (including sinking fund provisions), the redemption price or prices, or the liquidation preferences of any wholly unissued series, together with the designation of any such series and the number of shares which shall constitute any such unissued series, and to increase or decrease (but not below the number of shares of such series then outstanding) the number of shares of any series subsequent to the issue of that series.
| 3. | COMMON STOCK |
Subject to the voting rights and other rights, preferences and privileges above provided in this Article III with respect to the Preferred Stock and the Preference Stock, and except as otherwise provided by law, shares of Common Stock and/or the holders thereof shall have full voting rights and powers for the election of directors and for all other purposes, voting together as a single class, and shall be entitled to receive dividends as and when they are declared by the Board of Directors. Upon liquidation, distribution or winding up of the corporation, the assets
of the corporation available for distribution to the holders of the Common Stock shall be distributed ratably among the holders of all shares of the Common Stock at the time outstanding. The Common Stock shall have no conversion, subscription or preemptive rights, nor shall it be subject to redemption, call or assessment.
IV
(Statement of Conversion)
The name of the converting California limited liability company is Southwest Gas, LLC. The limited liability company’s California Secretary of State file number is 201700310456. The principal terms of the plan of conversion were approved by a vote of the members, which equaled or exceeded the vote required under California Corporations Code section 17710.03. There is one class of members entitled to vote and the percentage vote required is a majority in interest of the members. The limited liability company is converting into a California stock corporation.
V
A. The initial street address and mailing address of the converted corporation is:
5241 Spring Mountain Road, Las Vegas, NV 89150-0002
B. The name and California street address of the converted corporation’s initial agent for service of process are:
Samuel Grandlienard
13471 Mariposa Road, Victorville, CA 92395-5315
VI
The liability of the directors of this corporation for monetary damages shall be eliminated to the fullest extent permissible under California law. This corporation is authorized to provide indemnification of agents (as defined in Section 317 of the California Corporations Code) through bylaws, resolutions, agreements with agents, vote of shareholders or disinterested directors, or otherwise, in excess of the indemnification otherwise permitted by Section 317 of the California Corporations Code, subject only to the applicable limits set forth in Section 204 of the California Corporations Code.
I declare that I am the person who executed this instrument, which execution is my act and deed.
| /s/ John P. Hester |
| John P. Hester |
Incorporator and President and Chief Executive Officer of Southwest Gas Utility Group, Inc., the Managing Member of Southwest Gas, LLC
Exhibit 3(ii)
BYLAWS
OF
SOUTHWEST GAS CORPORATION,
a California corporation
ARTICLE 1
OFFICES
Section 1.1 Principal Executive Office.
The principal executive office of the corporation is hereby fixed and located at: 5241 Spring Mountain Road, in the City of Las Vegas, County of Clark, State of Nevada. The Board of Directors is hereby granted full power and authority to change said principal executive office from one location to another. Any such change shall be noted on these Bylaws by the Secretary opposite this Section, or this Section may be amended to state the new location.
Section 1.2 Other Offices.
Other business offices may at any time be established at any place or places specified by the Board of Directors.
ARTICLE 2
MEETINGS OF SHAREHOLDERS
Section 2.1 Place of Meetings.
All meetings of shareholders shall be held at the principal executive office of the corporation or at any other place within or without the State of California specified by the Board of Directors, or, to the extent permitted by and in accordance with Section 2.6, by electronic transmission by and to the corporation (as these terms are defined Sections 20 and 21 of the General Corporate Law of the State of California, as may be amended from time to time (“General Corporation Law”)) or by electronic video screen communication.
Section 2.2 Annual Meeting.
The annual meeting of the shareholders, after the year 2016, shall be held at the time and date in each year fixed by the Board of Directors. At the annual meeting directors shall be elected, reports of the affairs of the corporation shall be considered, and any other business may be transacted that is within the power of the shareholders.
Section 2.3 Notice of Annual Meeting.
Written notice of each annual meeting shall be given to each shareholder entitled to vote not less than ten (10) days before nor more than sixty (60) days before each annual meeting.
Such notice shall specify:
(1) the place, the date, and the hour of such meeting;
(2) those matters that the Board of Directors, at the time of the mailing of the notice, intends to present for action by the shareholders;
(3) if directors are to be elected, the names of nominees intended at the time of the notice to be presented by the Board of Directors for election;
(4) the general nature of a proposal, if any, to take action with respect to approval of (i) a contract or other transaction with an interested director, (ii) amendment of the Articles of Incorporation, (iii) a reorganization of the corporation as defined in Section 181 of the General Corporation Law, (iv) voluntary dissolution of the corporation, or (v) a distribution in dissolution other than in accordance with the rights of outstanding preferred shares, if any; and
(5) such other matters, if any, as may be expressly required by statute.
Notice shall not be construed to mean personal notice, but such notice may be given in writing, by mail or by a form of electronic transmission consented to by the shareholder or director to whom the notice is given, except to the extent prohibited by the General Corporation Law, addressed to such director or shareholder, at his address, or electronic mail address, as it appears on the records of the corporation, with postage thereon prepaid if applicable, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail or sent by a form of electronic transmission. Whenever any notice is required to be given, waiver thereof in writing, signed by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto.
Section 2.4 Special Meetings.
Special meetings of the shareholders for any purpose or purposes whatsoever may be called at any time by the Chairman of the Board (if there be such an officer appointed), by the President, by the Board of Directors, or by one or more shareholders entitled to cast not less than ten percent (10%) of the votes at the meeting.
Section 2.5 Notice of Special Meetings.
Upon request in writing (as defined in Section 8 of the General Corporation Law.) that a special meeting of shareholders be called for any proper purpose, directed to the Chairman of the Board (if there be such an officer appointed), President, Vice President or Secretary by any person (other than the Board of Directors) entitled to call a special meeting of shareholders, the officer forthwith shall cause notice to be given to the shareholders entitled to vote that a meeting will be held at a time requested by the person or persons calling the meeting, not less than thirty-five (35) nor more than sixty (60) days after the receipt of the request. Except in special cases where other express provision is made by statute, notice of any special meeting of shareholders
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shall be given in the same manner as for annual meetings of shareholders. In addition to the matters required by Section 2.3(1) and, if applicable, Sections 2.3 (2)-(5) of these Bylaws, notice of any special meeting shall specify the general nature of the business to be transacted, and no other business may be transacted at such meeting.
Section 2.6 Quorum.
The presence in person or by proxy of persons entitled to vote a majority of the voting shares at any meeting shall constitute a quorum for the transaction of business. If a quorum is present, the affirmative vote of a majority of the shares represented and voting at the meeting (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be the act of the shareholders, unless the vote of a different number or voting by classes is required by the General Corporation Law, the Articles of Incorporation or these Bylaws. Any meeting of shareholders, whether or not a quorum is present, may be adjourned from time to time by the vote of the holders of a majority of the shares present in person or represented by proxy thereat and entitled to vote, but in the absence of a quorum no other business may be transacted at such meeting, except that the shareholders present or represented by proxy at a duly called or held meeting, at which a quorum is present, may continue to transact business until adjournment, notwithstanding the withdrawal of enough shareholders to leave less than a quorum, if any action taken (other than adjournment) is approved by at least a majority of the shares required to constitute a quorum, or if required by the General Corporation Law or the Articles of Incorporation, the vote of a greater number or voting by classes.
Section 2.7 Adjourned Meeting and Notice.
When any shareholders’ meeting, either annual or special, is adjourned for more than forty-five (45) days, or if after adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting shall be given as in the case of an original meeting. Except as provided above, it shall not be necessary to give any notice of the time and place of the adjourned meeting (or the means of electronic transmission by and to the corporation (as these terms are defined in Sections 20 and 21 of the General Corporation Law) or electronic video screen communication, if any, by which the shareholders may participate), or of the business to be transacted thereat, other than by announcement of the time and place thereof at the meeting at which such adjournment is taken.
Section 2.8 Record Date.
The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders or entitled to give consent to corporate action in writing (as defined in Section 8 of the General Corporation Law) without a meeting, to receive any report, to receive any dividend or other distribution, or allotment of any rights, or to exercise rights in respect of any other lawful action. The record date so fixed shall be not more than sixty (60) days nor less than ten (10) days prior to the date of such meeting, nor more than sixty (60) days prior to any other action. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to
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any adjournment of the meeting unless the Board of Directors fixes a new record date for the adjourned meeting, but the Board of Directors shall fix a new record date if the meeting is adjourned for more than forty-five (45) days from the date set for the original meeting. When a record date is so fixed, only shareholders of record at the close of business on that date are entitled to notice of and to vote at any such meeting, to give consent without a meeting, to receive any report, to receive the dividend, distribution, or allotment of rights, or to exercise the rights, as the case may be, notwithstanding any transfer of any shares on the books of the corporation after the record date, except as otherwise provided in the Articles of Incorporation or these Bylaws.
Section 2.9 Voting.
(a) Except as may be otherwise provided in the Articles of Incorporation, each outstanding share, regardless of class, shall be entitled to one vote on each matter submitted to a vote of shareholders. Any holders of shares entitled to vote on any matter may vote part of the shares in favor of the proposal and refrain from voting the remaining shares or vote them against the proposal, other than elections to office, but, if the shareholder fails to specify the number of shares such shareholder is voting affirmatively, it will be conclusively presumed that the shareholder’s approving vote is with respect to all shares such shareholder is entitled to vote.
(b) Subject to the provisions of Sections 702 through 704 of the General Corporation Law (relating to voting of shares held by a fiduciary, receiver, pledgee, or minor, in the name of a corporation, or in joint ownership), persons in whose names shares entitled to vote stand on the stock records of the corporation at the close of business on the record date shall be entitled to vote at the meeting of shareholders. Such vote may be viva voce or by ballot; provided, however, that all elections for directors must be by ballot upon demand made by a shareholder at any election and before the voting begins. Shares of this corporation owned by a corporation more than twenty-five percent (25%) of the voting power of which is owned directly by this corporation, or indirectly through one or more majority-owned subsidiaries of this corporation, shall not be entitled to vote on any matter.
(c) The candidates for directors receiving the highest number of affirmative votes of shares entitled to be voted for them, up to the number of directors to be elected by such shares, shall be elected and votes against a director and votes withheld shall have no legal effect.
Section 2.10 Proxies.
(a) Every person entitled to vote shares (including voting by written consent) may authorize another person or other persons to act by proxy with respect to such shares by a written proxy executed by such person or his duly authorized agent and filed with the Secretary of the corporation; provided that no such proxy shall be valid after the expiration of eleven (11) months from the date of its execution, unless the person executing it specifies therein the length of time for which such proxy is to continue in force, which in no case shall exceed seven (7) years from the date of its execution.
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Section 2.11 Validation of Defectively Called or Noticed Meetings.
The transactions of any meeting of shareholders, however called and noticed, and wherever held, are as valid as though had at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy, and if, either before or after the meeting, each of the persons entitled to vote, not present in person or by proxy, provides a waiver of notice or consent to the holding of the meeting or approval of the minutes thereof in writing (as defined in Section 8 of the General Corporation Law). All such waivers, consents and approvals shall be filed with the corporate records or made a part of the minutes of the meeting. Attendance of a person at a meeting shall constitute a waiver of notice of and presence at such meeting, except when the person objects, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened and except that attendance at a meeting is not a waiver of any right to object to the consideration of matters required by these Bylaws or by the General Corporation Law to be included in the notice if such objection is expressly made at the meeting. Neither the business to be transacted at nor the purpose of any regular or special meeting of shareholders need be specified in any written waiver of notice, consent to the holding of the meeting or approval of the minutes thereof, unless otherwise provided in the Articles of Incorporation or these Bylaws, or unless the meeting involves one or more matters specified in Section 2.3(3) of these Bylaws.
Section 2.12 Action Without Meeting.
(a) Directors may be elected without a meeting by a consent in writing (as defined in Section 8 of the General Corporation Law), setting forth the action so taken, signed by all of the persons who would be entitled to vote for the election of directors, provided that, without notice except as hereinafter set forth, a director may be elected at any time to fill a vacancy not filled by the directors (other than a vacancy created by removal of a director) by the written consent of persons holding a majority of the outstanding shares entitled to vote for the election of directors.
Any other action that may be taken at a meeting of the shareholders, may be taken without a meeting, and without prior notice except as hereinafter set forth, if a consent in writing (as defined in Section 8 of the General Corporation Law), setting forth the action so taken, is signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.
(b) Unless the consents of all shareholders entitled to vote have been solicited in writing (as defined in Section 8 of the General Corporation Law):
(1) notice of any proposed shareholder approval of (i) a contract or other transaction with an interested director, (ii) indemnification of an agent of the corporation, (iii) a reorganization of the corporation as defined in Section 181 of the General Corporation Law, or (iv) a distribution in dissolution other than in accordance with the rights of outstanding preferred shares, if any, without a meeting by less than unanimous written consent, shall be given at least
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ten (10) days before the consummation of the action authorized by such approval in accordance with Section 2.3 of these Bylaws; and
(2) prompt notice shall be given of the taking of any other corporate action approved by shareholders without a meeting by less than unanimous written consent to those shareholders entitled to vote who have not consented in writing (as defined in Section 8 of the General Corporation Law). Such notices shall be given in the manner provided in Section 2.3 of these Bylaws.
Any shareholder giving a written consent, or the shareholder’s proxyholders, or a transferee of the shares or a personal representative of the shareholder or their respective proxyholders, may revoke the consent personally or by proxy by a writing (as defined in Section 8 of the General Corporation Law) received by the corporation prior to the time that written consents of the number of shares required to authorize the proposed action have been filed with the Secretary of the corporation, but may not do so thereafter. Such revocation is effective upon its receipt by the Secretary of the corporation.
ARTICLE 3
BOARD OF DIRECTORS
Section 3.1 Powers.
Subject to the provisions of the General Corporation Law and any limitations in the Articles of Incorporation relating to action required to be approved by the shareholders or by the outstanding shares, the business and affairs of the corporation shall be managed and all corporate powers shall be exercised by or under the direction of the Board of Directors. The Board of Directors may delegate the management of the day-to-day operation of the business of the corporation to a management company or other person, provided that the business and affairs of the corporation shall be managed and all corporate powers shall be exercised under the ultimate direction of the Board of Directors.
Notwithstanding the foregoing, for so long as Southwest Gas Utility Group, Inc., a California corporation primarily engaged in the business of holding stock of the corporation, or its successors (the “Group Corporation”) directly or indirectly owns the capital stock of the corporation, the Board of Directors shall not be authorized or empowered, nor shall they permit the corporation, without the prior unanimous written consent of all of the members of the Board of Directors, including the Independent Director(s) (as defined herein), to: (a) dissolve, liquidate or sell all or substantially all of the corporation’s assets; (b) institute proceedings to have the corporation adjudicated bankrupt or insolvent; (c) consent to the institution bankruptcy or insolvency proceedings against the corporation; (d) file a voluntary petition seeking, or consenting, reorganization or relief with respect to the corporation under any applicable federal or state law relating to bankruptcy; (e) consent to the appointment of a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the corporation or a substantial part of its property; (f) make any assignment for the benefit of creditors of the corporation; (g) admit in
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writing the corporation’s inability to pay its debts generally as they become due; or (h) to the fullest extent permitted by law, take any action in furtherance of any such action. Moreover, the Board of Directors may not vote on, or authorize the taking of, any of the foregoing actions unless there is at least one Independent Director then serving in such capacity.
Section 3.2 Number and Qualification of Directors; Independent Directors
The number of directors of the corporation shall not be less than three (3) nor more than five (5) until changed by amendment of the Articles of Incorporation or by a Bylaw amending this Section 3.2 duly adopted by the vote or written consent of holders of a majority of the outstanding shares. The exact number of directors shall be fixed from time to time, within the limits specified in the Articles of Incorporation or in this Section 3.2, by a bylaw or amendment thereof duly adopted by the vote of a majority of the shares entitled to vote represented at a duly held meeting at which a quorum is present, or by the written consent of the holders of a majority of the outstanding shares entitled to vote, or by the Board of Directors.
Subject to the foregoing provisions for changing the number of directors, the number of directors of the corporation has been fixed at four (4).
Notwithstanding the number of directors of the corporation at any given time, the Board of Directors shall consist of at least one director who is (i) not at the time of initial appointment or at any time while serving on the Board of Directors also serving as a director of the Group Corporation and (ii) not at the time of initial appointment, at any time while serving on the Board of Directors and/or has not been at any time during the preceding five years: (a) an officer, employee, attorney or counsel of the corporation or any affiliate of the corporation (except as a director or stockholder of any affiliate of the corporation); (b) a creditor, customer (other than a consumer), supplier or other person who has derived in any one of the preceding five years revenues from its activities with the corporation or any affiliate of the corporation (except as a director or stockholder of any affiliate of the corporation); (c) a person whose immediate family includes or who is employed by any person described in clause (a) or clause (b) above; or (d) a trustee, conservator or receiver for the corporation or any affiliate of the corporation (such a director meeting the foregoing qualifications, an “Independent Director”).
Section 3.3 Election and Term of Office.
The directors shall be elected at each annual meeting of shareholders, but, if any such annual meeting is not held or the directors are not elected thereat, the directors may be elected at any special meeting of shareholders held for that purpose. Each director, including a director elected to fill a vacancy, shall hold office until the expiration of the term for which elected and until a successor has been elected and qualified, subject, however, to such director’s prior death, resignation, retirement, disqualification or removal from office.
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Section 3.4 Vacancies.
A vacancy in the Board of Directors shall be deemed to exist in case of the death, resignation or removal of any director, if a director has been declared of unsound mind by order of court or convicted of a felony, if the authorized number of directors is increased, if the incorporator or incorporators have failed to appoint the authorized number of directors in any resolution for appointment of directors upon the initial organization of the corporation, or if the shareholders fail, at any annual or special meeting of shareholders at which any director or directors are elected, to elect the full authorized number of directors to be voted for at that meeting.
Vacancies in the Board of Directors, except for a vacancy created by the removal of a director, may be filled by a majority of the directors present at a meeting at which a quorum is present, or if the number of directors then in office is less than a quorum, (a) by the unanimous written consent of the directors then in office, (b) by the vote of a majority of the directors then in office at a meeting held pursuant to notice or waivers of notice in compliance with these Bylaws, or (c) by a sole remaining director. Each director so elected shall hold office until his or her successor is elected at an annual or a special meeting of the shareholders. A vacancy in the Board of Directors created by the removal of a director may be filled only by the vote of a majority of the shares entitled to vote represented at a duly held meeting at which a quorum is present, or by the written consent of all of the holders of the outstanding shares.
The shareholders may elect a director or directors at any time to fill any vacancy or vacancies not filled by the directors. Any such election by written consent other than to fill a vacancy created by removal which requires the unanimous written consent of all shares entitled to vote for the election of directors shall require the consent of holders of a majority of the outstanding shares entitled to vote. Any such election by written consent to fill a vacancy created by removal shall require the unanimous written consent of all shares entitled to vote for the election of directors.
Any director may resign effective upon giving written notice to the Chairman of the Board (if there be such an officer appointed), the President, the Secretary or the Board of Directors of the corporation, unless the notice specifies a later time for the effectiveness of such resignation. If the resignation is effective at a future time, a successor may be elected to take office when the resignation becomes effective.
No reduction of the authorized number of directors shall have the effect of removing any director prior to the expiration of the director’s term of office.
No director may be removed (unless the entire Board of Directors is removed) when the votes cast against removal, or not consenting in writing (as defined in Section 8 of the General Corporation Law) to the removal, would be sufficient to elect the director if voted cumulatively at an election at which the same total number of votes were cast (or, if the action is taken by written consent, all shares entitled to vote were voted) and the entire number of directors authorized at the time of the director’s most recent election were then being elected.
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Section 3.5 Time and Place of Meetings.
The Board of Directors shall hold regular meetings without notice at such time and at such place as shall from time to time be determined by the Board of Directors. Special meetings of the Board of Directors may be held at any time whenever called by the Chairman of the Board (if there be such an officer appointed), the President, any Vice-President, the Secretary or any two directors.
All meetings of the Board of Directors may be held by means of conference telephone, electronic video screen communication or electronic transmission by and to the corporation (as these terms are defined in Sections 20 and 21 of the General Corporation Law).
Section 3.6 Notice of Special Meetings.
Notice of each special meeting of the Board of Directors shall be given to each of the directors by: (i) mailing to each of them a copy of such notice at least five days; or (ii) delivering personally or by telephone, including voice messaging system or other system or technology designed to record and communicate messages, telegraph, facsimile, electronic mail, or other electronic means such notice at least 48 hours, prior to the time affixed for such meeting to the address of such director as shown on the books of the corporation. If his address does not appear on the books of the corporation, then such notice shall be addressed to him at the principal office of the corporation.
Notice of a meeting need not be given to any director who provides a waiver of notice or a consent to holding the meeting or an approval of the minutes thereof in writing (as defined in Section 8 of the General Corporation Law), whether before or after the meeting, or who attends the meeting without protesting, prior thereto or at its commencement, the lack of notice to such director. All such waivers, consents and approvals shall be filed with the corporate records or made a part of the minutes of the meetings.
Section 3.7 Action at a Meeting: Quorum and Required Vote.
(a) Presence of a majority of the authorized number of directors at a meeting of the Board of Directors constitutes a quorum for the transaction of business, except as hereinafter provided.
(b) Members of the Board of Directors may participate in a meeting through use of conference telephone or similar communications equipment, so long as all members participating in such meeting can hear one another. Participation in a meeting pursuant to this section shall constitute presence in person at such meeting.
(c) Every act or decision done or made by a majority of the directors present at a meeting duly held at which a quorum is present is the act of the Board of Directors, unless a greater number, or the same number after disqualifying one or more directors from voting, is required by law, by the Articles of Incorporation, or by these Bylaws. A meeting at which a
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quorum is initially present may continue to transact business notwithstanding the withdrawal of directors, if any action taken is approved by at least a majority of the required quorum for such meeting.
Section 3.8 Action Without a Meeting.
Any action required or permitted to be taken by the Board of Directors may be taken without a meeting, if all members of the Board of Directors shall individually or collectively consent in writing (as defined in Section 8 of the General Corporation Law) to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. Such action by written consent shall have the same force and effect as a unanimous vote of such directors.
Section 3.9 Adjourned Meeting and Notice.
A majority of the directors present, whether or not a quorum is present, may adjourn any meeting to another time and place. If the meeting is adjourned for more than twenty-four (24) hours, notice of any adjournment to another time or place shall be given prior to the time of the adjourned meeting to the directors who were not present at the time of the adjournment.
Section 3.10 Fees and Compensation.
Directors and members of committees may receive such compensation, if any, for their services, and such reimbursement for expenses, as may be fixed or determined by resolution of the Board of Directors.
Section 3.11 Appointment of Executive and Other Committees.
The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, create and appoint committees and prescribe and from time to time change their duties and compensation. Any action permitted to be taken by the Board of Directors pursuant to these Bylaws may be taken by an authorized committee thereof except to the extent prescribed by resolution of the Board of Directors or by law (for the avoidance of doubt, no such committee may act in lieu of the Board of Directors with respect to the matters set forth in the second paragraph of Sections 3.1 and 3.4 of these Bylaws and in Sections 3.10, 3.11 and 8.2 of these Bylaws).
The provisions of Sections 3.4 through 3.8 of these Bylaws apply also to committees of the Board of Directors and action by such committees, mutatis mutandis (with the necessary changes having been made in the language thereof).
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ARTICLE 4
OFFICERS
Section 4.1 Officers.
The officers of the corporation shall consist of the President, the Secretary and the Chief Financial Officer, and each of them shall be appointed by the Board of Directors. The corporation may also have a Chairman of the Board, one or more Vice-Presidents, a Controller, a Treasurer, one or more Assistant Secretaries and Assistant Chief Financial Officers, and such other officers as may be appointed by the Board of Directors, or with authorization from the Board of Directors by the President. The order of the seniority of the Vice-Presidents shall be in the order of their nomination, unless otherwise determined by the Board of Directors. Any two or more of such offices may be held by the same person. The Board of Directors may appoint, and may empower the President to appoint, such other officers as the business of the corporation may require, each of whom shall have such authority and perform such duties as are provided in these Bylaws or as the Board of Directors may from time to time determine.
All officers of the corporation shall hold office from the date appointed to the date of the next succeeding regular meeting of the Board of Directors following the meeting of shareholders at which the Board of Directors is elected, and until their successors are elected; provided that all officers, as well as any other employee or agent of the corporation, may be removed at any time at the pleasure of the Board of Directors, or, except in the case of an officer chosen by the Board of Directors, by any officer upon whom such power of removal may be conferred by the Board of Directors, and upon the removal, resignation, death or incapacity of any officer, the Board of Directors or the President, in cases where he or she has been vested by the Board of Directors with power to appoint, may declare such office vacant and fill such vacancy. Nothing in these Bylaws shall be construed as creating any kind of contractual right to employment with the corporation.
Any officer may resign at any time by giving written notice to the Board of Directors, the President, or the Secretary of the corporation, without prejudice, however, to the rights, if any, of the corporation under any contract to which such officer is a party. Any such resignation shall take effect at the date of the receipt of such notice or at any later time specified therein; and, unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective.
The salary and other compensation of the officers shall be fixed from time to time by resolution of or in the manner determined by the Board of Directors.
Section 4.2 The Chairman of the Board.
The Chairman of the Board (if there be such an officer appointed) shall, when present, preside at all meetings of the Board of Directors and shall perform all the duties commonly incident to that office. The Chairman of the Board shall have authority to execute in the name of
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the corporation bonds, contracts, deeds, leases and other written instruments to be executed by the corporation (except where by law the signature of the President is required), and shall perform such other duties as the Board of Directors may from time to time determine.
Section 4.3 The President.
Subject to such supervisory powers, if any, as may be given by the Board of Directors to the Chairman of the Board, the President shall be the chief executive officer of the corporation and shall perform all the duties commonly incident to that office. The President shall have authority to execute in the name of the corporation bonds, contracts, deeds, leases and other written instruments to be executed by the corporation. The President shall preside at all meetings of the shareholders and, in the absence of the Chairman of the Board or if there is none, at all meetings of the Board of Directors, and shall perform such other duties as the Board of Directors may from time to time determine.
Section 4.4 Vice-Presidents.
The Vice-Presidents (if there be such officers appointed), in the order of their seniority (unless otherwise established by the Board of Directors), may assume and perform the duties of the President in the absence or disability of the President or whenever the offices of the Chairman of the Board and President are vacant. The Vice-Presidents shall have such titles, perform such other duties, and have such other powers as the Board of Directors, the President or these Bylaws may designate from time to time.
Section 4.5 The Secretary.
The Secretary shall record or cause to be recorded, and shall keep or cause to be kept, at the principal executive office and such other place as the Board of Directors may order, a record of minutes of actions taken at all meetings of directors and committees thereof and of shareholders, with the time and place of holding, whether regular or special, and, if special, how authorized, the notice thereof given, the names of those present at directors’ meetings, the number of shares present or represented at shareholders’ meetings, and the proceedings thereof. Minutes and other books and records shall be kept either in written form or in another form capable of being converted into clearly legible tangible form or in any a combination of the foregoing.
The Secretary shall keep, or cause to be kept, at the principal executive office or at the office of the corporation’s transfer agent, a share register or a duplicate share register in a form capable of being converted into written form, showing the names of the shareholders and their addresses, the number and classes of shares held by each, the number and date of certificates issued for the same, and the number and date of cancellation of every certificate surrendered for cancellation.
The Secretary shall give, or cause to be given, notice of all the meetings of the shareholders and of the Board of Directors and committees thereof required by these Bylaws or
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by law to be given, and shall have such other powers and perform such other duties as may be prescribed by the Board of Directors or by these Bylaws.
The President may direct any Assistant Secretary to assume and perform the duties of the Secretary in the absence or disability of the Secretary, and each Assistant Secretary shall perform such other duties and have such other powers as the Board of Directors or the President may designate from time to time.
Section 4.6 Chief Financial Officer.
The Chief Financial Officer shall keep and maintain, or cause to be kept and maintained, adequate and correct accounts of the properties and business transactions of the corporation. The books of account shall at all reasonable times be open to inspection by any director.
The Chief Financial Officer shall deposit all moneys and other valuables in the name and to the credit of the corporation with such depositaries as may be designated by the Board of Directors. The Chief Financial Officer shall disburse the funds of the corporation as may be ordered by the Board of Directors, shall render to the President and directors, whenever they request it, an account of all of the Chief Financial Officer’s transactions as Chief Financial Officer and of the financial condition of the corporation, and shall have such other powers and perform such other duties as may be prescribed by the Board of Directors or these Bylaws.
The President may direct any Assistant Chief Financial Officer to assume and perform the duties of the Chief Financial Officer in the absence or disability of the Chief Financial Officer, and each Assistant Chief Financial Officer shall perform such other duties and have such other powers as the Board of Directors or the President may designate from time to time.
Section 4.7 The Controller.
The Controller (if there be such an officer appointed) shall be responsible for the establishment and maintenance of accounting and other systems required to control and account for the assets of the corporation and provide safeguards therefor, and to collect information required for management purposes, and shall perform such other duties and have such other powers as the Board of Directors or the President may designate from time to time.
The President may direct any Assistant Controller to assume and perform the duties of the Controller, in the absence or disability of the Controller, and each Assistant Controller shall perform such other duties and have such other powers as the Board of Directors, the Chairman of the Board (if there be such an officer appointed) or the President may designate from time to time.
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ARTICLE 5
EXECUTION OF CORPORATE INSTRUMENTS,
RATIFICATION, AND VOTING OF STOCKS
OWNED BY THE CORPORATION
Section 5.1 Execution of Corporate Instruments.
In its discretion, the Board of Directors may determine the method and designate the signatory officer or officers or other person or persons, to execute any corporate instrument or document, or to sign the corporate name without limitation, except where otherwise provided by law, and such execution or signature shall be binding upon the corporation.
All checks and drafts drawn on banks or other depositaries on funds to the credit of the corporation, or in special accounts of the corporation, shall be signed by such person or persons as the Board of Directors shall authorize to do so.
The Board of Directors shall designate an officer who personally, or through his representative, shall vote shares of other corporations standing in the name of this corporation. The authority to vote shares shall include the authority to execute a proxy in the name of the corporation for purposes of voting the shares.
Section 5.2 Ratification by Shareholders.
In its discretion, the Board of Directors may submit any contract or act for approval or ratification of the shareholders at any annual meeting of shareholders, or at any special meeting of shareholders called for that purpose; and any contract or act that shall be approved or ratified by the holders of a majority of the voting power of the corporation shall be as valid and binding upon the corporation and upon the shareholders thereof as though approved or ratified by each and every shareholder of the corporation, unless a greater vote is required by law for such purpose.
Section 5.3 Voting of Stocks Owned by the Corporation.
All stock of other corporations owned or held by the corporation for itself, or for other parties in any capacity, shall be voted, and all proxies with respect thereto shall be executed, by the person authorized to do so by resolution of the Board of Directors, or in the absence of such authorization, by the Chairman of the Board (if there be such an officer appointed), the President or any Vice-President, or by any other person authorized to do so by the Chairman of the Board, the President or any Vice President.
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ARTICLE 6
SHARES OF STOCK
Section 6.1 Stock Certificates.
Every holder of shares in the corporation shall be entitled to have a certificate signed in the name of the corporation by the Chairman or Vice Chairman of the Board (if there be such officers appointed) or the President or a Vice-President and by the Chief Financial Officer or any Assistant Chief Financial Officer or the Secretary or any Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder. Any of the signatures on the certificate may be a facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate has ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the corporation with the same effect as if such person were an officer, transfer agent or registrar at the date of issue.
Any such certificate shall also contain such legends or other statements as may be required by Sections 417 and 418 of the General Corporation Law, the Corporate Securities Law of 1968, federal or other state securities laws, and any agreement between the corporation and the issuee of the certificate.
Certificates for shares may be issued prior to full payment, under such restrictions and for such purposes as the Board of Directors or these Bylaws may provide; provided, however, that the certificate issued to represent any such partly paid shares shall state on the face thereof the total amount of the consideration to be paid therefor, the amount remaining unpaid and the terms of payment.
No new certificate for shares shall be issued in lieu of an old certificate unless the latter is surrendered and canceled at the same time; provided, however, that a new certificate will be issued without the surrender and cancellation of the old certificate if (1) the old certificate is lost, apparently destroyed or wrongfully taken; (2) the request for the issuance of the new certificate is made within a reasonable time after the owner of the old certificate has notice of its loss, destruction, or theft; (3) the request for the issuance of a new certificate is made prior to the receipt of notice by the corporation that the old certificate has been acquired by a bona fide purchaser; (4) the owner of the old certificate files a sufficient indemnity bond with or provides other adequate security to the corporation; and (5) the owner satisfies any other reasonable requirement imposed by the corporation. In the event of the issuance of a new certificate, the rights and liabilities of the corporation, and of the holders of the old and new certificates, shall be governed by the provisions of Sections 8104 and 8405 of the California Commercial Code.
Section 6.2 Uncertificated Shares.
Notwithstanding Section 6.1, the corporation may adopt a system of issuance, recordation and transfer of its shares by electronic or other means not involving any issuance of certificates,
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including provisions for notice to purchasers in substitution for the required statements on certificates under Sections 417, 418, and 1302 of the California Corporations Code, and as may be required by the commissioner in administering the Corporate Securities Law of 1968, which system (1) has been approved by the United States Securities and Exchange Commission, (2) is authorized in any statute of the United States, or (3) is in accordance with Division 8 (commencing with Section 8101) of the California Commercial Code. Any system so adopted shall not become effective as to issued and outstanding certificated securities until the certificates therefor have been surrendered to the corporation.
ARTICLE 7
INDEMNIFICATION OF OFFICERS, DIRECTORS, EMPLOYEES AND AGENTS
Section 7.1 Indemnification of Directors and Officers.
Each person who was or is a party or is threatened to be made a party to or is involved in any threatened, pending or completed action, suit or proceeding, formal or informal, whether brought in the name of the corporation or otherwise and whether of a civil, criminal, administrative, or investigative nature (hereinafter a “proceeding”), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director or officer of the corporation or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation or of a partnership, joint venture, trust, or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is an alleged action or inaction in an official capacity, or in any other capacity while serving as a director or officer, shall, subject to the terms of any agreement between the corporation and such person, be indemnified and held harmless by the corporation to the fullest extent permissible under California law and the corporation’s Articles of Incorporation, against all costs, charges, expenses, liabilities, and losses (including attorneys’ fees, judgments, fines, ERISA excise tax or penalties, and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith, and such indemnification shall continue as to a person who has ceased to be a director or officer and shall inure to the benefit of his or her heirs, executors, and administrators; provided, however, that: (a) the corporation shall indemnify any such person seeking indemnification in connection with a proceeding (or part thereof) initiated by such person only if such proceeding (or part thereof) was authorized by the Board of Directors, (b) the corporation shall indemnify such person seeking indemnification in connection with a proceeding (or part thereof) other than a proceeding by or in the name of the corporation to procure a judgment in its favor only if any settlement of such a proceeding is approved in writing by the corporation, and (c) that no such person shall be indemnified (i) on account of any suit in which judgment is rendered against such person for an accounting of profits made from the purchase or sale by such person of securities of the corporation pursuant to the provisions of Section 16(b) of the Securities Exchange Act of 1934 and amendments thereto or similar provisions of any federal, state, or local statutory law; (ii) if a court of competent jurisdiction finally determines that any indemnification hereunder is unlawful; (iii) for acts or omissions involving intentional misconduct or knowing and culpable violation of law; (iv) for acts or
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omissions that the director or officer believes to be contrary to the best interests of the corporation or its shareholders or that involve the absence of good faith on the part of the director or officer; (v) for any transaction for which the director or officer derived an improper personal benefit; (vi) for acts or omissions that show a reckless disregard for the director’s or officer’s duty to the corporation or its shareholders in circumstances in which the director or officer was aware, or should have been aware, in the ordinary course of performing his or her duties, of a risk of serious injury to the corporation or its shareholders; (vii) for acts or omissions that constitute an unexcused pattern of inattention that amounts to an abdication of the director’s or officer’s duties to the corporation or its shareholders; (viii) for costs, charges, expenses, liabilities, and losses arising under Section 310 or 316 of the General Corporation Law; and (ix) as to circumstances in which indemnity is expressly prohibited by Section 317 of the General Corporation Law. The right to indemnification conferred in this Article shall be a contract right and shall include the right to be paid by the corporation expenses incurred in defending any proceeding in advance of its final disposition; provided, however, that if the General Corporation Law requires the payment of such expenses incurred by a director or officer in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such person while a director or officer, including, without limitation, service to an employee benefit plan) in advance of the final disposition of a proceeding, such advances shall be made only upon delivery to the corporation of an undertaking, by or on behalf of such director or officer, to repay all amounts to the corporation if it shall be ultimately determined that such person is not entitled to be indemnified.
Section 7.2 Indemnification of Employees and Agents.
A person who was or is a party or is threatened to be made a party to or is involved in any proceedings by reason of the fact that he or she is or was an employee or agent of the corporation or is or was serving at the request of the corporation as an employee or agent of another enterprise, including service with respect to employee benefit plans, whether the basis of such action is an alleged action or inaction in an official capacity or in any other capacity while serving as an employee or agent, may, subject to the terms of any agreement between the corporation and such person, be indemnified and held harmless by the Corporation to the fullest extent permitted by California law and the corporation’s Articles of Incorporation, against all costs, charges, expenses, liabilities, losses (including attorneys’ fees, judgments, fines, ERISA excise taxes or penalties, and amounts paid or to be paid in settlement), reasonably incurred or suffered by such person in connection therewith. The immediately preceding sentence is not intended to be and shall not be considered to confer a contract right on any employee or agent (other than directors and officers) of the corporation.
Section 7.3 Right of Directors and Officers to Bring Suit.
If a claim under Section 7.1 of this Article is not paid in full by the corporation within 30 days after a written claim has been received by the corporation, the claimant may at any time thereafter bring suit against the corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall also be entitled to be paid the expense of prosecuting such claim. Neither the failure of the corporation (including the Board of Directors,
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independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is permissible in the circumstances because he or she has met the applicable standard of conduct, if any, nor an actual determination by the corporation (including the Board of Directors, independent legal counsel, or its shareholders) that the claimant has not met the applicable standard of conduct, shall be a defense to the action or create a presumption for the purpose of an action that the claimant has not met the applicable standard of conduct.
Section 7.4 Successful Defense.
Notwithstanding any other provision of this Article, to the extent that a director or officer has been successful on the merits or otherwise (including the dismissal of an action without prejudice or the settlement of a proceeding or action without admission of liability) in defense of any proceeding referred to in Section 7.1 or in defense of any claim, issue or matter therein, he or she shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred in connection therewith.
Section 7.5 Non-Exclusivity of Rights; No Duplication of Payments.
The right to indemnification provided by this Article shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, bylaw, agreement, vote of shareholders, disinterested directors, or otherwise. The corporation shall not be liable under this Article to make any payment to a person hereunder to the extent such person has otherwise actually received payment (under any insurance policy, agreement or otherwise) of the amounts otherwise payable hereunder.
Section 7.6 Insurance.
The corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee, or agent of the corporation or another corporation, partnership, joint venture, trust, or other enterprise against any expense, liability or loss, whether or not the corporation would have the power to indemnify such person against such expense, liability, or loss under the General Corporation Law.
Section 7.7 Expenses as a Witness.
To the extent that any director, officer, employee, or agent of the corporation is by reason of such position, or a position with another entity at the request of the corporation, a witness in any action, suit, or proceeding, he or she shall be indemnified against all costs and expenses actually and reasonably incurred by him or her on his or her behalf in connection therewith.
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Section 7.8 Indemnity Agreements.
The corporation may enter into agreements with any director, officer, employee, or agent of the corporation providing for indemnification to the fullest extent permissible under the General Corporation Law and the corporation’s Articles of Incorporation.
Section 7.9 Separability.
Each and every paragraph, sentence, term, and provision of this Article is separate and distinct so that if any paragraph, sentence, term, or provision hereof shall be held to be invalid or unenforceable for any reason, such invalidity or unenforceability shall not affect the validity or unenforceability of any other paragraph, sentence, term, or provision hereof. To the extent required, any paragraph, sentence, term, or provision of this Article may be modified by a court of competent jurisdiction to preserve its validity and to provide the claimant with, subject to the limitations set forth in this Article and any agreement between the corporation and claimant, the broadest possible indemnification permitted under applicable law.
Section 7.10 Effect of Repeal or Modification
Any repeal or modification of this Article shall not adversely affect any right of indemnification of a director or officer existing at the time of such repeal or modification with respect to any action or omission occurring prior to such repeal or modification.
ARTICLE 8
AMENDMENTS
Section 8.1 Power of Shareholders.
New bylaws may be adopted or these Bylaws may be amended or repealed by the affirmative vote of a majority of the outstanding shares entitled to vote, or by the written assent of shareholders entitled to vote such shares, except (i) as otherwise provided by law or by the Articles of Incorporation or by these Bylaws and (ii) for so long as the Group Corporation owns the capital stock of the corporation, any amendment to the second paragraph of Section 3.1, the third paragraph of Section 3.2, this clause (ii) of Section 8.1, the final proviso of Section 8.2 and Article 11 shall require the approval of the Independent Director.
Section 8.2 Power of Directors.
Subject to the right of shareholders as provided in Section 8.1 of this Article 8 to adopt, amend or repeal these Bylaws, these Bylaws (other than a bylaw or amendment thereof changing the authorized number of directors, or providing for the approval by the Board of Directors, acting alone, of a loan or guarantee to any officer or an employee benefit plan providing for the same) may be adopted, amended or repealed by the Board of Directors, provided that for so long
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as Group Corporation directly or indirectly owns the capital stock of the corporation, the vote of at least one Independent Director shall be required for any such action by the Board of Directors.
ARTICLE 9
CORPORATE SEAL
The corporate seal shall consist of a circular die bearing the name of the corporation, the state in which it was incorporated and the date of its incorporation. If and when authorized by the Board of Directors, a duplicate of the corporate seal may be kept and used by such officer or person as the Board of Directors may designate.
ARTICLE 10
DEFINITIONS
Unless the context otherwise requires, the general provisions, rules of construction and definitions contained in the General Corporation Law as amended from time to time shall govern the construction of these Bylaws. Without limiting the generality of the foregoing, the masculine gender includes the feminine and neuter, the singular number includes the plural and the plural number includes the singular, and the term “person” includes a corporation as well as a natural person.
ARTICLE 11
MANAGEMENT AND CONDUCT
Section 11.1 Special Provisions for the Management and Conduct of the Affairs of the Corporation
(a) The corporation shall for so long as the Group Corporation directly or indirectly owns the capital stock of the corporation:
i. maintain its own separate books and records, financial statements and bank accounts;
ii. except for tax and accounting purposes, at all times hold itself out to the public as a legal entity separate from the Group Corporation and any other affiliate or other person and not identify itself as a division of any other person;
iii. have a Board of Directors, the composition of which includes an Independent Director;
iv. file its own tax returns to the extent required under applicable law and pay any taxes required to be paid under applicable law;
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v. not (x) commingle its funds or other assets with the funds or other assets of any other person (provided that the corporation’s funds may be held in designated intercompany accounts pursuant to the corporation’s cash management policies, to the extent not prohibited by the following clause (y)), nor (y) maintain any funds or other assets in such a manner that it will be costly or difficult to segregate, ascertain or identify its individual funds or other assets from those of its shareholders or any other person;
vi. conduct its business in its own name and hold all of its assets in its own name;
vii. pay its own liabilities only out of its own funds (whether held in bank accounts, designated intercompany accounts or otherwise);
viii. maintain an arm’s length relationship with its affiliates, including the Group Corporation;
ix. from its own funds (whether held in bank accounts, designated intercompany accounts or otherwise), pay the salaries of its own employees (if any);
x. not hold out its credit as being available to satisfy the obligations of others;
xi. allocate fairly and reasonably any overhead for shared overhead costs;
xii. not pledge its assets for the benefit of any other person;
xiii. correct any known misunderstanding regarding its separate identity;
xiv. maintain adequate capital in light of its contemplated business purposes;
xv. not acquire any obligations or securities of the Group Corporation or its affiliates; and
xvi. comply with all corporate formalities to maintain its separate existence.
(b) For so long as the Group Corporation directly or indirectly owns the capital stock of the corporation, assets shall not be transferred to or from the Group Corporation without fair consideration (except for any dividend or other distribution made in the ordinary course by the corporation, to the extent permitted by the Bylaws and applicable law) or with the intent to hinder, delay or defraud the creditors of the corporation, Southwest Gas Holdings, Inc. or the Group Corporation and its subsidiaries.
(c) For so long as the Group Corporation directly or indirectly owns the capital stock of the corporation, the corporation will not transfer any of its assets in contemplation of insolvency or with the intent to hinder, delay or defraud any present or future creditor of the corporation, Southwest Gas Holdings, Inc. or the Group Corporation and its subsidiaries. The transaction by which the capital stock of the corporation is transferred from Southwest Gas Holdings, Inc. to the Group Corporation shall not create conditions which would cause such transaction to be a fraudulent transfer or fraudulent conveyance under the laws which govern these Bylaws.
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(d) For so long as the Group Corporation directly or indirectly owns the capital stock of the corporation, the corporation shall not enter into, or be a party to, any transaction with any of its affiliates except: (1) pursuant to the reasonable requirements and purposes of its business; and (2) upon fair and reasonable terms (and, to the extent material, pursuant to written agreements) that are consistent with market terms of any such transactions entered into by unaffiliated parties.
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CERTIFICATE OF SECRETARY
The undersigned, Secretary of Southwest Gas Corporation, a California corporation, hereby certifies that the foregoing is a full, true and correct copy of the Bylaws of the corporation with all amendments to date of this Certificate.
WITNESS the signature of the undersigned this 4rd day of January, 2017.
| /s/ Karen S. Haller |
| Karen S. Haller Corporate Secretary |
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Exhibit 10.19
PERFORMANCE SHARE AWARD AGREEMENT
This Performance Share Award Agreement (“Award Agreement”) is dated as of , 201 , by and between Southwest Gas Holdings, Inc., a California corporation (the “Company”), and (“Grantee”).
Overview of Your Award
Aggregate Target Performance Shares: [determined by award opportunity and Beginning Stock Price]
| • | [ ] shares |
Performance Period: January 1, 20[ ] to December 31, 20[ ]
Peer Index:
[Peer index to be determined by the Committee.]
1. Grant and Description of Performance Shares. The Company hereby grants the Grantee performance shares (“Performance Shares”). Each Performance Share represents a share of Common Stock. Until the final number of Performance Shares is determined, the Grantee shall not have any of the rights of a shareholder of the Company with respect to the Performance Shares, except for the crediting of dividend equivalents as provided for in Section 8 below.
2. Restrictions on Alienation. Performance Shares may not be sold, transferred, pledged, assigned, or otherwise alienated in any manner, whether voluntarily, by operation of law, or otherwise, until the restrictions on the Performance Shares are removed and the Performance Shares are delivered to the Grantee in the form of shares of Common Stock.
3. Performance Shares. Vesting of Performance Shares is contingent upon achieved by the Company for the three (3) year measurement cycle (such cycle, the “Measurement Cycle”) beginning with the fiscal year in which the Performance Shares are granted, subject to modification based on relative total shareholder return (“TSR”). shall be calculated using generally accepted accounting principles, adjusted to exclude the impacts of company owned life insurance.
Subject to adjustment based on TSR, Performance Shares will vest as illustrated in the performance schedule below. Should the performance levels achieved be between the stated criteria below, the percentage of Performance Shares vesting will be determined by straight-line interpolation.
Performance Schedule Fiscal Years 20 -20
| Performance Level |
Measure |
Vested Performance Shares |
||||
| Below Threshold |
Less than [ ] | 0 | % | |||
| Threshold |
[ ] | 50 | % | |||
| Target |
[ ] | 100 | % | |||
| Maximum |
[ ] | 150 | % | |||
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4. TSR Modifier. The vesting of both Performance Shares is subject to further adjustment based upon the achievement of the following TSR performance goals pre-established by the Committee. For example, if the vesting percentage of Performance Shares determined based on for the Measurement Cycle is 150% and TSR for the Measurement Cycle is in the top 75th Percentile, the percentage of Performance Shares vesting would be adjusted upward by 30% such that 195% of the target number of Performance Shares would vest.
| TSR Performance Relative to Peer Index |
Payout (% Adjustment) | |
| 75th Percentile or Above |
30% upward | |
| Below 75th Percentile and above 25% Percentile |
0% (i.e., no adjustment) | |
| 25th Percentile or Below |
15% downward | |
If performance is above threshold, in the event of a downward adjustment based on TSR, the lowest percentage of Performance Shares (as applicable) that vest will be 50% of the target number of Performance Shares.
TSR shall be calculated as follows:
TSR = (Change in Stock Price + Dividends paid) / Beginning Stock Price
“Beginning Stock Price” shall mean the closing price on the applicable stock exchange of one share of Common Stock on the last trading day immediately prior to the first day of the Performance Period. “Ending Stock Price” shall mean the closing price on the applicable stock exchange of one share of Common Stock for the last trading day of the Performance Period. “Change in Stock Price” shall mean the difference between the Beginning Stock Price and the Ending Stock Price; and Dividends Paid shall mean the total of all dividends paid on one share of stock during the Performance Period.
Following the TSR calculation, the Company’s Percentile Rank shall be determined as follows:
Percentile Rank shall be determined by listing from highest TSR to lowest TSR of each company in the Peer Index (excluding the Company). The top company would have a one hundred percentile (100%) rank and the bottom company would have a zero percentile (0.0%) rank. Each company in between would be one hundred divided by n minus one (100/(n-1)) above the company below it, where “n” is the total number of companies in the Peer Index. The Company percentile rank would then be interpolated based on the Company TSR. [The companies in the Peer Index shall remain constant throughout the entire Performance Period.]
5. Forfeiture of Performance Shares.
All Performance Shares granted shall be forfeited if, prior to the removal of restrictions on the Performance Shares, the Grantee has experienced a Termination for any reason other than as described below in Section 6. Each Grantee shall execute any documents reasonably requested by the Company in connection with such forfeiture. Upon any forfeiture, all rights of the Grantee with respect to the forfeited Performance Shares shall cease and terminate, without any further obligation on the part of the Company.
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6. Removal of Restrictions.
(a) Death, Disability, Certain Involuntary Terminations and Terminations following a Change in Control.
Upon Grantee’s death, Termination due to Disability, Termination due to a general reduction in force or specific elimination of the Grantee’s job (except if contemporaneously with such elimination Grantee’s suffers a Termination for Cause), or Termination for any reason following a Change in Control, restrictions placed on each Performance Share shall be removed, and the Measurement Cycle for purposes of Section 7 and Section 8 below shall be deemed to have ended. The prorated number of Performance Shares awarded shall be determined by multiplying the percentage of Performance Shares awarded at the “Target” performance level first stated above, by the ratio of actual months of service to 36 months of the original Measurement Cycle, with the resulting product being increased, if appropriate, as provided below in Section 8. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution of shares of Common Stock equal in number to such prorated number of Performance Shares.
(b) Retirement.
Upon Grantee’s Retirement, the restrictions placed on the Performance Shares under Section 2 above shall not be removed and the percentage of Performance Shares earned shall not be determined until the end of the Measurement Cycle. The vested number of Performance Shares shall be determined by multiplying the ratio of actual months of service to 36 months of the original Measurement Cycle by the percentage of Performance Shares earned, based on actual performance achieved over the original Measurement Cycle with the resulting product being increased, if appropriate, as provided below in Section 8. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution of shares of Common Stock equal in number to such prorated number of Performance Shares.
7. Credit of Dividend Equivalents.
The Grantee’s account shall be credited with a number of Performance Shares based on the amount of dividends that were declared and paid on shares of Common Stock during each fiscal quarter of the Measurement Cycle. The number of Performance Shares upon which dividend equivalents shall be credited for the benefit of the Grantee is the total number of Performance Shares finally determined to have been earned by the Grantee at the end of the Measurement Cycle in accordance with Sections 3 and 4 and/or 6, as appropriate. The total amount of each quarterly dividend equivalent shall be converted to the number of Performance Shares attributable to that quarterly dividend equivalent, by dividing such dividend equivalent amount by the average of the closing price of the Common Stock on the dividend payment date during the appropriate Measurement Cycle. Incremental Performance Shares credited for dividends may also earn dividend equivalents.
8. Distribution of Common Stock or Cash.
The Grantee shall receive a distribution of whole shares of Common Stock equal to the number of vested Performance Shares plus dividend equivalents, as applicable, provided the Grantee has remained in continuous service with the Company during the entire term of the Measurement Cycle (except in the event of Retirement pursuant to Section 6(b)). Distribution of shares of Common Stock shall occur as soon as administratively possible following the last trading day of the quarter in which the Measurement Cycle ends (the “Distribution Date”), but in no event later than 90 days following the last trading day of the applicable quarter. Notwithstanding the immediately preceding sentence, in the case of a distribution of shares of Common Stock on account of any Termination pursuant to Section 5, other than death,
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distribution of vested Performance Shares, plus any dividends payable with respect to such number of shares, on behalf of the Grantee, if the Grantee is a “specified employee” as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A, to the extent otherwise required under Section 409A, shall not occur until the date which is six (6) months following the date of the Grantee’s Termination (or, if earlier, upon the death of the Grantee). Upon a distribution of shares of Common Stock as provided herein, the Company shall cause the Common Stock then being distributed to be registered in the Grantee’s name, but shall not issue certificates for the Common Stock unless the Grantee requests delivery of the certificates for the Common Stock, in writing in accordance with the procedures established by the Company. The Company shall deliver certificates to the Grantee as soon as administratively practicable following the Company’s receipt of a written request from the Grantee for delivery of the certificates. From and after the date of receipt of such distribution, the Grantee or the Grantee’s legal representatives, beneficiaries or heirs, as the case may be, shall have full rights of transfer or resale with respect to such shares subject to applicable state and federal regulations.
9. Administration.
This Award Agreement and the rights of the Grantee hereunder are subject to all the terms and conditions of the Plan. Any inconsistency between this Award Agreement and the Plan shall be resolved in favor of the Plan.
10. Miscellaneous.
(a) Nothing in this Award Agreement or the Plan shall interfere with or limit in any way the right of the Company to terminate the Grantee’s employment, nor confer upon the Grantee any right to continued employment with the Company or continued of service as a Board member.
(b) Upon the approval of the Board in its sole discretion, the Committee may terminate, amend, or modify the Plan; provided, however, that no such termination, amendment, or modification of the Plan may in any way adversely affect the Grantee’s rights under this Award Agreement without the Grantee’s written consent.
(c) The Grantee shall not have voting rights with respect to the Units until the Units are settled and have been distributed as shares of Common Stock.
(d) This Agreement shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.
(e) This Award Agreement shall be governed by the corporate laws of the State of Nevada, without giving effect to any choice of law provisions that might otherwise refer construction or interpretation of the Agreement or the Plan to the substantive law of another jurisdiction.
(f) Notwithstanding the established performance measures in this Award Agreement, in determining attainment of any such performance measures, the Committee shall exclude the impact of the following specified objective events, except where such exclusion would result in the loss of an otherwise available exemption under Code Section 162(m): effects of accounting changes; effects of currency fluctuations; effects of financing activities (e.g., effect on earnings per share of issuing convertible debt securities); expenses for restructuring, productivity initiatives or new business initiatives; non-operating items; acquisition expenses; effects of divestitures; and effects of items that are considered to be of an unusual nature or of a type that indicates infrequency of occurrence or both.
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Grantee acknowledges that this Award Agreement and the Plan set forth the entire understanding between Grantee and the Company regarding the acquisition of the Units granted pursuant to this Award Agreement. Grantee has reviewed and fully understands all provisions of this Award Agreement and the Plan in their entirety. Grantee acknowledges that Performance Shares awarded hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated until the Performance Shares are vested and the Performance Shares are delivered to the Grantee in the form of shares of Common Stock.
| SOUTHWEST GAS HOLDINGS, INC. | ||
| By: |
| |
| John P. Hester President and Chief Executive Officer | ||
| GRANTEE | ||
| By: |
| |
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Exhibit 10.20
AWARD AGREEMENT OF TIME-LAPSE
RESTRICTED STOCK UNITS
This Award Agreement of Time-Lapse Restricted Stock Units (“Award Agreement”) is dated as of , 201 , by and between Southwest Gas Holdings, Inc., a California corporation (the “Company”), and (“Grantee”).
Overview of Your Award
| Number of Units Granted: |
[determined by award opportunity and Beginning Stock Price] | |||
| Date of Grant: |
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| Date of Lapse of Restrictions: | ||||
| Shares |
Date |
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[ %] |
[first anniversary] | |||
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[ %] |
[second anniversary] | |||
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[ %] |
[third anniversary] |
1. Grant of Units. The Company hereby awards Grantee time-lapse restricted stock units (“Units”) under the Plan with the restrictions set forth below. During the time of the restriction period, the Grantee shall not have any of the rights of a shareholder of the Company with respect to the Units.
2. Vesting of Units. Units will vest in accordance with the schedule above. If Grantee attains the age of 55 and has completed ten (10) consecutive years of service with the Company (“Retirement Eligible”) on the Date of the Grant or prior to the Distribution Date, Grantee shall be vested in the Units. However, Grantee shall not be entitled to the removal of the restrictions on such Units or to a distribution of shares of Common Stock represented by the number of Units until the time provided for in Section 6 below.
3. Forfeiture of Units. Notwithstanding Section 2 above, unvested Units shall be forfeited in case of a Termination not described in Section 4. Grantee agrees to execute such documentation that may be reasonably requested by the Company in connection with such forfeiture. All rights of Grantee with respect to any forfeited Units shall cease and terminate upon forfeiture of such Units, without any further obligation on the part of the Company.
4. Removal of Restrictions. Upon Grantee’s Retirement on or after becoming Retirement Eligible, or upon Grantee’s death, Disability, involuntary Termination due to a general reduction in force or specific elimination of the Grantee’s job (except if contemporaneously with such elimination Grantee’s suffers a Termination for Cause), or Termination for any reason following a Change in Control, all Units (plus applicable Dividend Equivalents) shall vest and all other restrictions placed on such Units shall be removed.
1
5. Dividend Equivalents. From the Date of Grant and until the Units are distributed pursuant to Section 6, Grantee’s account will be credited with notional dividends at the same time, in the same form, and in equivalent amounts as dividends that are payable from time to time on Common Stock. Any such notional dividends shall be valued as of the date on which they are credited to the Grantee and reallocated to acquire additional Units. Such additional Units may also earn dividend credits and shall vest in accordance with the vesting schedule set forth above as if such Units had been issued on the Date of Grant.
6. Distribution of Common Stock. As soon as administratively possible, as determined solely by the Company, following the earlier of the date of the occurrence of a Termination described in Section 4 or on the applicable “Date of Lapse of Restrictions” set forth above, but in no event later than 90 days following the Date of Lapse of Restrictions (the “Distribution Date”), the Grantee shall receive a distribution, as provided herein, of shares of Common Stock equal in number to the number of Units set forth above plus any Dividend Equivalents credited to Grantee in respect of such Units (subject to the withholding requirements set forth in the Plan); provided the Grantee has been an employee of the Company or a Subsidiary with continuous service from the date of grant to the Distribution Date, except in the event of the Grantee’s Termination of Service or Retirement as discussed in Section 4 above. Notwithstanding the immediately preceding sentence, in the case of a distribution of shares of Common Stock on account of any Termination of Service as provided for above in Section 4 above, other than death, a distribution of the number of such shares, determined after application of the withholding requirements set forth in the Plan, plus any dividends payable with respect to such number of shares, on behalf of the Grantee, if the Grantee is a “specified employee” as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A, to the extent otherwise required under Section 409A, shall not occur until the date which is six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee). Upon a distribution of shares of Common Stock as provided herein, the Company shall cause the Common Stock then being distributed to be registered in the Grantee’s name. From and after the date of receipt of such distribution, the Grantee or the Grantee’s legal representatives, beneficiaries or heirs, as the case may be, shall have full rights of transfer or resale with respect to such shares subject to applicable state and federal regulations.
7. Administration.
This Award Agreement and the rights of the Grantee hereunder are subject to all the terms and conditions of the Plan. Any inconsistency between this Award Agreement and the Plan shall be resolved in favor of the Plan.
8. Miscellaneous.
(a) Nothing in this Award Agreement or the Plan shall interfere with or limit in any way the right of the Company to terminate the Grantee’s employment, nor confer upon the Grantee any right to continued employment with the Company or continued of service as a Board member.
(b) Upon the approval of the Board in its sole discretion, the Committee may terminate, amend, or modify the Plan; provided, however, that no such termination, amendment, or modification of
2
the Plan may in any way adversely affect the Grantee’s rights under this Award Agreement without the Grantee’s written consent.
(c) The Grantee shall not have voting rights with respect to the Units until the Units are settled and have been distributed as shares of Common Stock.
(d) This Agreement shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.
(e) This Award Agreement shall be governed by the corporate laws of the State of Nevada, without giving effect to any choice of law provisions that might otherwise refer construction or interpretation of the Agreement or the Plan to the substantive law of another jurisdiction.
Grantee acknowledges that this Award Agreement and the Plan set forth the entire understanding between Grantee and the Company regarding the acquisition of the Units granted pursuant to this Award Agreement. Grantee has reviewed and fully understands all provisions of this Award Agreement and the Plan in their entirety. Grantee acknowledges that Units awarded hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated until the restrictions on the Units are removed and the Units are delivered to the Grantee in the form of shares of Common Stock.
| SOUTHWEST GAS HOLDINGS, INC. | ||
| By: |
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| John P. Hester President and Chief Executive Officer | ||
| GRANTEE | ||
| By: |
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[ ] | ||
3
Exhibit 12.02
SOUTHWEST GAS CORPORATION
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
(Thousands of dollars)
| December 31, | ||||||||||||||||||||
| 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||
| 1. Fixed charges: |
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| A) Interest expense |
$ | 73,000 | $ | 71,661 | $ | 71,234 | $ | 62,958 | $ | 67,148 | ||||||||||
| B) Amortization |
1,835 | 1,884 | 2,063 | 2,002 | 2,001 | |||||||||||||||
| C) Interest portion of rentals |
19,438 | 16,678 | 11,802 | 11,809 | 10,605 | |||||||||||||||
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| Total fixed charges |
$ | 94,273 | $ | 90,223 | $ | 85,099 | $ | 76,769 | $ | 79,754 | ||||||||||
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| 2. Earnings (as defined): |
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| D) Pretax income from continuing operations |
$ | 231,523 | $ | 219,332 | $ | 219,521 | $ | 222,815 | $ | 207,915 | ||||||||||
| Fixed Charges (1. above) |
94,273 | 90,223 | 85,099 | 76,769 | 79,754 | |||||||||||||||
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| Total earnings as defined |
$ | 325,796 | $ | 309,555 | $ | 304,620 | $ | 299,584 | $ | 287,669 | ||||||||||
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| 3.46 | 3.43 | 3.58 | 3.90 | 3.61 | ||||||||||||||||
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Exhibit 13.01
Consolidated Selected Financial Statistics
| Year Ended December 31, | 2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| (Thousands of dollars, except per share amounts) | ||||||||||||||||||||
| Operating revenues |
$ | 2,460,490 | $ | 2,463,625 | $ | 2,121,707 | $ | 1,950,782 | $ | 1,927,778 | ||||||||||
| Operating expenses |
2,164,776 | 2,175,293 | 1,837,224 | 1,676,567 | 1,656,254 | |||||||||||||||
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| Operating income |
$ | 295,714 | $ | 288,332 | $ | 284,483 | $ | 274,215 | $ | 271,524 | ||||||||||
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| Net income attributable to Southwest |
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| Gas Corporation |
$ | 152,041 | $ | 138,317 | $ | 141,126 | $ | 145,320 | $ | 133,331 | ||||||||||
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| Total assets at year end |
$ | 5,581,126 | $ | 5,358,685 | $ | 5,208,297 | $ | 4,565,174 | $ | 4,488,057 | ||||||||||
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| Capitalization at year end |
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| Total equity |
$ | 1,661,273 | $ | 1,592,325 | $ | 1,486,266 | $ | 1,412,395 | $ | 1,308,498 | ||||||||||
| Redeemable noncontrolling interest |
22,590 | 16,108 | 20,042 | — | — | |||||||||||||||
| Long-term debt, excluding current maturities |
1,549,983 | 1,551,204 | 1,631,374 | 1,381,327 | 1,268,373 | |||||||||||||||
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| $ | 3,233,846 | $ | 3,159,637 | $ | 3,137,682 | $ | 2,793,722 | $ | 2,576,871 | |||||||||||
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| Current maturities of long-term debt |
$ | 50,101 | $ | 19,475 | $ | 19,192 | $ | 11,105 | $ | 50,137 | ||||||||||
| Common stock data |
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| Common equity percentage of capitalization |
51.4 | % | 50.4 | % | 47.4 | % | 50.6 | % | 50.8 | % | ||||||||||
| Return on average common equity |
9.3 | % | 8.9 | % | 9.7 | % | 10.6 | % | 10.4 | % | ||||||||||
| Basic earnings per share |
$ | 3.20 | $ | 2.94 | $ | 3.04 | $ | 3.14 | $ | 2.89 | ||||||||||
| Diluted earnings per share |
$ | 3.18 | $ | 2.92 | $ | 3.01 | $ | 3.11 | $ | 2.86 | ||||||||||
| Dividends declared per share |
$ | 1.80 | $ | 1.62 | $ | 1.46 | $ | 1.32 | $ | 1.18 | ||||||||||
| Payout ratio |
56 | % | 55 | % | 48 | % | 42 | % | 41 | % | ||||||||||
| Book value per share at year end |
$ | 35.03 | $ | 33.65 | $ | 32.03 | $ | 30.51 | $ | 28.39 | ||||||||||
| Market value per share at year end |
$ | 76.62 | $ | 55.16 | $ | 61.81 | $ | 55.91 | $ | 42.41 | ||||||||||
| Market value to book value per share |
219 | % | 164 | % | 193 | % | 183 | % | 149 | % | ||||||||||
| Common shares outstanding at year end (000) |
47,482 | 47,378 | 46,523 | 46,356 | 46,148 | |||||||||||||||
| Number of common shareholders at year end |
13,619 | 14,153 | 14,749 | 15,359 | 16,028 | |||||||||||||||
| Ratio of earnings to fixed charges |
3.46 | 3.43 | 3.58 | 3.90 | 3.61 | |||||||||||||||
| Southwest Gas Corporation |
14 |
Natural Gas Operations
| Year Ended December 31, | 2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| (Thousands of dollars) | ||||||||||||||||||||
| Operating revenue |
$ | 1,321,412 | $ | 1,454,639 | $ | 1,382,087 | $ | 1,300,154 | $ | 1,321,728 | ||||||||||
| Net cost of gas sold |
397,121 | 563,809 | 505,356 | 436,001 | 479,602 | |||||||||||||||
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| Operating margin |
924,291 | 890,830 | 876,731 | 864,153 | 842,126 | |||||||||||||||
| Expenses |
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| Operations and maintenance |
401,724 | 393,199 | 383,732 | 384,914 | 369,979 | |||||||||||||||
| Depreciation and amortization |
233,463 | 213,455 | 204,144 | 193,848 | 186,035 | |||||||||||||||
| Taxes other than income taxes |
52,376 | 49,393 | 47,252 | 45,551 | 41,728 | |||||||||||||||
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| Operating income |
$ | 236,728 | $ | 234,783 | $ | 241,603 | $ | 239,840 | $ | 244,384 | ||||||||||
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| Contribution to consolidated net income |
$ | 119,423 | $ | 111,625 | $ | 116,872 | $ | 124,169 | $ | 116,619 | ||||||||||
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| Total assets at year end |
$ | 5,001,756 | $ | 4,822,845 | $ | 4,652,307 | $ | 4,272,029 | $ | 4,204,948 | ||||||||||
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| Net gas plant at year end |
$ | 4,131,971 | $ | 3,891,085 | $ | 3,658,383 | $ | 3,486,108 | $ | 3,343,794 | ||||||||||
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| Construction expenditures and property additions |
$ | 457,120 | $ | 438,289 | $ | 350,025 | $ | 314,578 | $ | 308,951 | ||||||||||
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| Cash flow, net |
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| From operating activities |
$ | 507,224 | $ | 497,500 | $ | 288,534 | $ | 265,290 | $ | 344,441 | ||||||||||
| From (used in) investing activities |
(446,238 | ) | (416,727 | ) | (328,645 | ) | (304,189 | ) | (296,886 | ) | ||||||||||
| From (used in) financing activities |
(63,339 | ) | (74,159 | ) | 23,413 | 44,947 | (43,453 | ) | ||||||||||||
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| Net change in cash |
$ | (2,353 | ) | $ | 6,614 | $ | (16,698 | ) | $ | 6,048 | $ | 4,102 | ||||||||
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| Total throughput (thousands of therms) |
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| Residential |
684,626 | 655,421 | 617,377 | 741,327 | 655,046 | |||||||||||||||
| Small commercial |
294,525 | 285,118 | 276,582 | 298,045 | 270,665 | |||||||||||||||
| Large commercial |
90,949 | 92,284 | 94,391 | 102,761 | 116,582 | |||||||||||||||
| Industrial/Other |
30,275 | 30,973 | 32,374 | 50,210 | 47,830 | |||||||||||||||
| Transportation |
970,561 | 1,035,707 | 906,691 | 1,037,916 | 998,095 | |||||||||||||||
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| Total throughput |
2,070,936 | 2,099,503 | 1,927,415 | 2,230,259 | 2,088,218 | |||||||||||||||
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| Weighted average cost of gas purchased ($/therm) |
$ | 0.37 | $ | 0.44 | $ | 0.55 | $ | 0.42 | $ | 0.42 | ||||||||||
| Customers at year end |
1,984,000 | 1,956,000 | 1,930,000 | 1,904,000 | 1,876,000 | |||||||||||||||
| Employees at year end |
2,247 | 2,219 | 2,196 | 2,220 | 2,245 | |||||||||||||||
| Customer to employee ratio |
883 | 881 | 879 | 858 | 836 | |||||||||||||||
| Degree days – actual |
1,613 | 1,512 | 1,416 | 1,918 | 1,740 | |||||||||||||||
| Degree days – ten-year average |
1,771 | 1,792 | 1,816 | 1,876 | 1,866 | |||||||||||||||
| Southwest Gas Corporation |
15 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations
About Southwest Gas Corporation
In 2015, the Board of Directors (“Board”) of Southwest Gas Corporation 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. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company; whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of the reorganization were filed with the Arizona Corporation Commission (“ACC”), the California Public Utilities Commission (“CPUC”), and the Public Utilities Commission of Nevada (“PUCN”) in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The reorganization, which was approved by the Board in December 2016, became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016.
The Company consists 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, 2016, Southwest had 1,984,000 residential, commercial, industrial, and other natural gas customers, of which 1,058,000 customers were located in Arizona, 733,000 in Nevada, and 193,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2016, 54% of operating margin was earned in Arizona, 35% in Nevada, and 11% in California. During this same period, Southwest earned 85% of its operating margin (gas operating revenues less the net cost of gas sold) from residential and small commercial customers, 3% from other sales customers, and 12% 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
| Southwest Gas Corporation |
16 |
infrastructure trackers) and customer growth. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), 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 Southwest to pursue energy efficiency initiatives.
Centuri is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operates in 20 major markets in the United States (primarily as NPL) and in 2 major markets in Canada (as NPL Canada (formerly Link-Line Contractors Ltd.), and W.S. Nicholls). 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, 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 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 81% 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, | 2016 | 2015 | 2014 | |||||||||
| (In thousands, except per share amounts) | ||||||||||||
| Contribution to net income |
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| Natural gas operations |
$ | 119,423 | $ | 111,625 | $ | 116,872 | ||||||
| Construction services |
32,618 | 26,692 | 24,254 | |||||||||
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| Consolidated |
$ | 152,041 | $ | 138,317 | $ | 141,126 | ||||||
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| Average number of common shares outstanding |
47,469 | 46,992 | 46,494 | |||||||||
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| Basic earnings per share |
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| Consolidated |
$ | 3.20 | $ | 2.94 | $ | 3.04 | ||||||
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| Natural Gas Operations |
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| Gas operating revenues |
$ | 1,321,412 | $ | 1,454,639 | $ | 1,382,087 | ||||||
| Net cost of gas sold |
397,121 | 563,809 | 505,356 | |||||||||
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| Operating margin |
$ | 924,291 | $ | 890,830 | $ | 876,731 | ||||||
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| Southwest Gas Corporation |
17 |
2016 Overview
Consolidated results for 2016 increased compared to 2015 as improvements were experienced in both operating segments. Basic earnings per share were $3.20 in 2016 compared to basic earnings per share of $2.94 in 2015.
Natural gas operations highlights include the following:
| • | 28,000 net new customers (1.4% growth rate) |
| • | Operating margin increased $33 million, or 4%, compared to the prior year |
| • | Net financing costs increased $3 million between 2016 and 2015 |
| • | COLI income was $7.4 million in 2016 compared to a loss of $500,000 in 2015 |
| • | Redeemed $100 million of 4.85% and $24.9 million of 4.75% IDRBs |
| • | Issued $300 million of 3.8% senior notes |
| • | Credit facility expiration date extended one year to March 2021 |
| • | Settlement reached among several parties in Arizona general rate case (regulatory approval pending) |
| • | Holding company reorganization became effective in January 2017 |
Construction services highlights include the following:
| • | Revenues in 2016 increased $130 million, or 13%, compared to 2015 |
| • | Construction expenses increased $126 million, or 14%, compared to 2015 |
| • | Contribution to net income increased $6 million compared to 2015 |
| • | Acquisition of ETTI construction businesses in May 2016 |
| • | Hired Paul Daily as CEO of Centuri |
Results of Natural Gas Operations
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| (Thousands of dollars) | ||||||||||||
| Gas operating revenues |
$ | 1,321,412 | $ | 1,454,639 | $ | 1,382,087 | ||||||
| Net cost of gas sold |
397,121 | 563,809 | 505,356 | |||||||||
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| Operating margin |
924,291 | 890,830 | 876,731 | |||||||||
| Operations and maintenance expense |
401,724 | 393,199 | 383,732 | |||||||||
| Depreciation and amortization |
233,463 | 213,455 | 204,144 | |||||||||
| Taxes other than income taxes |
52,376 | 49,393 | 47,252 | |||||||||
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| Operating income |
236,728 | 234,783 | 241,603 | |||||||||
| Other income (deductions) |
8,276 | 2,292 | 7,165 | |||||||||
| Net interest deductions |
66,997 | 64,095 | 68,299 | |||||||||
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| Income before income taxes |
178,007 | 172,980 | 180,469 | |||||||||
| Income tax expense |
58,584 | 61,355 | 63,597 | |||||||||
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| Contribution to consolidated net income |
$ | 119,423 | $ | 111,625 | $ | 116,872 | ||||||
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2016 vs. 2015
The contribution to consolidated net income from natural gas operations increased $7.8 million between 2016 and 2015. The improvement was primarily due to an increase in operating margin and other income, partially offset by an increase in operating expenses and net interest deductions.
Operating margin increased $33 million between years. Combined rate relief in the California jurisdiction and Paiute Pipeline Company provided $10 million in operating margin (see Rates and Regulatory Proceedings). New
| Southwest Gas Corporation |
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customers contributed $8 million in operating margin. The Nevada Conservation and Energy Efficiency (“CEE”) surcharge, which was implemented in January 2016, provided $11 million of the increase. Amounts collected through the surcharge do not impact net income as they also result in an increase in associated amortization expense. Infrastructure replacement mechanisms and customers outside the decoupling mechanisms, as well as other miscellaneous revenues, collectively provided $4 million of operating margin.
Operations and maintenance expense increased $8.5 million, or 2%, between 2016 and 2015 due primarily to general cost increases and higher employee medical costs, partially offset by a decline in pension expense. Higher expenses for pipeline integrity management and damage prevention programs accounted for $2.6 million of the increase.
Depreciation and amortization expense increased $20 million, or 9%. Average gas plant in service for the current year increased $341 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 infrastructure, which collectively resulted in increased depreciation expense. Amortizations associated with the recovery of regulatory assets increased approximately $7.1 million overall, notably due to amortization accompanying the recovery of Nevada CEE costs indicated above.
Taxes other than income taxes increased $3 million, or 6%, between 2016 and 2015 primarily due to higher property taxes associated with net plant additions.
Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, increased $6 million between 2016 and 2015. The current year reflects $7.4 million of COLI-related income associated with cash surrender value increases and recognized net death benefits, while the prior-year period reflected a COLI-related loss of $500,000.
Net interest deductions increased $2.9 million between 2016 and 2015, primarily due to higher interest expense associated with deferred purchased gas adjustment (“PGA”) balances and the issuance of $300 million of senior notes. The increase was substantially offset by reductions associated with the redemption of debt ($20 million of 5.25% 2003 Series D IDRBs in September 2015, $100 million of 4.85% 2005 Series A IDRBs in July 2016, and $24.9 million of 4.75% 2006 Series A in September 2016).
The effective income tax rates in both 2016 and 2015 were impacted by COLI results, which are not subject to tax. Additionally, the Company claimed a federal income tax credit, which resulted in a recognized benefit of approximately $1.7 million during 2016.
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 2015 and 2014. New customers contributed $8 million in operating margin during 2015. Combined rate relief in the California jurisdiction and Paiute Pipeline Company provided $5 million of the increase. Operating margin associated with customers outside the decoupling mechanisms and other miscellaneous revenues increased by $1 million between these years.
| Southwest Gas Corporation |
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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, in 2015. These increases were partially offset by certain expenses that were higher in 2014, including a $5 million legal accrual in 2014 and $1.1 million in rent expense (associated with a previously leased corporate headquarters complex).
Depreciation and amortization expense increased $9.3 million, or 5% between 2015 and 2014. Average gas plant in service increased $276 million, or 5%, between these years. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new infrastructure, which collectively resulted in increased depreciation expense. 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 2015 and 2014 primarily due to higher property taxes associated with net plant additions.
Other income decreased $4.9 million between 2015 and 2014. Cash surrender values of COLI policies decreased $500,000 in 2015, while COLI-related income was $5.3 million in 2014.
Net interest deductions decreased $4.2 million between years. The decrease primarily resulted from the redemptions of $65 million of 5.25% Series A IDRBs in November 2014, $31.2 million of 5.00% 2004 Series B IDRBs in May 2015, and $20 million of 5.25% 2003 Series D IDRBs in September 2015, partially offset by increased interest expense on PGA balances.
Results of Construction Services
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| (Thousands of dollars) | ||||||||||||
| Construction revenues |
$ | 1,139,078 | $ | 1,008,986 | $ | 739,620 | ||||||
| Operating expenses: |
||||||||||||
| Construction expenses |
1,024,423 | 898,781 | 647,857 | |||||||||
| Depreciation and amortization |
55,669 | 56,656 | 48,883 | |||||||||
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| Operating income |
58,986 | 53,549 | 42,880 | |||||||||
| Other income (deductions) |
1,193 | 587 | (58 | ) | ||||||||
| Net interest deductions |
6,663 | 7,784 | 3,770 | |||||||||
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| Income before income taxes |
53,516 | 46,352 | 39,052 | |||||||||
| Income tax expense |
19,884 | 18,547 | 14,776 | |||||||||
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| Net income |
33,632 | 27,805 | 24,276 | |||||||||
| Net income attributable to noncontrolling interests |
1,014 | 1,113 | 22 | |||||||||
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| Contribution to consolidated net income attributable to Centuri |
$ | 32,618 | $ | 26,692 | $ | 24,254 | ||||||
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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. In May 2016, Centuri acquired ETTI. Line items in the tables above reflect the results of ETTI only since the acquisition date, including approximately $6 million in revenues during 2016.
| Southwest Gas Corporation |
20 |
2016 vs. 2015
Contribution to consolidated net income from construction services increased $5.9 million compared to 2015. Additional bid work, lower depreciation and amortization, and decreased interest expense positively impacted net income. The prior year included a $3.4 million pretax loss associated with an industrial construction project in Canada.
Revenues increased $130.1 million, or 13%, when compared to 2015, primarily due to work performed on certain large bid projects and additional pipe replacement work. In addition, higher revenues were recognized due to favorable weather conditions during the year, generally in the mid-western and north-eastern parts of the United States and in Canada, which extended the construction season. Governmental-mandated pipeline safety-related programs resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues include contracts with Southwest totaling $98 million in 2016 and $104 million in 2015. Centuri accounts for services provided to Southwest at contractual prices. Refer to Consolidation under Summary of Significant Accounting Policies in Note 1 to the consolidated financial statements.
Construction expenses increased $125.6 million, or 14%, during the year due to additional pipe replacement work, higher labor costs experienced due to changes in the mix of work with existing customers, and greater operating expenses to support increased growth in operations. General and administrative expense (included in construction expenses) increased approximately $1.6 million overall to support the growth in operations and the increasing size, geographic footprint and complexity of Centuri’s business. Gains on sale of equipment (reflected as an offset to construction expenses) were approximately $7.1 million and $3.4 million for 2016 and 2015, respectively.
Depreciation and amortization expense decreased $1 million between 2016 and 2015 primarily due to a $4 million reduction in depreciation associated with an extension of the estimated useful lives of certain depreciable equipment and to a decline in amortization of certain finite-lived intangible assets recognized from the October 2014 acquisition, partially offset by an increase in depreciation on additional equipment purchased to support the growing volume of work being performed.
Operating income increased $5.4 million, or 10%, when compared to 2015, primarily due to increased bid work at favorable profit margins overall.
Net interest deductions were lower by $1.1 million, primarily due to lower interest rates on outstanding borrowings during 2016 as compared to 2015 and to a decrease in the average line of credit balance outstanding during 2016.
During the past several years, construction services segment efforts have been focused on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2016 and 2015, revenues from replacement work were 65% and 68%, respectively, of total revenues. As noted above, governmental pipeline safety-related programs and U.S. bonus depreciation tax incentives resulted in many utilities undertaking multi-year distribution pipe replacement projects.
2015 vs. 2014
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 to 2015 including a full year of revenues of the acquired companies (an increase of $124 million). NPL revenues in
| Southwest Gas Corporation |
21 |
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 as compared to 2014. Governmental-mandated pipeline safety-related programs resulted in many utilities undertaking multi-year distribution pipe replacement projects. Construction revenues included contracts with Southwest totaling $104 million in 2015 and $92 million in 2014.
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 included a $3.4 million loss on a previous Canadian project. 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.
Depreciation and amortization expense increased $7.8 million between 2015 and 2014 due primarily to incremental amortization in 2015 related to finite-lived intangible assets recognized from the acquisition ($3 million) and to 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.
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) changes, 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 (2014—2016) 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 PUCN in November 2012, and was amended in a Rehearing Decision in April 2013. Ultimately, Southwest 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.
General Revenues Adjustment. As part of the Annual Rate Adjustment (“ARA”) filing in June 2016, Southwest requested authorization to adjust rates associated with its revenue decoupling mechanism (General Revenues
| Southwest Gas Corporation |
22 |
Adjustment, or “GRA”). The ARA, including amounts to refund the over-collected balance in the accounts associated with this mechanism, was approved in December 2016, with rates effective January 2017. The rate adjustment is expected to refund approximately $16.7 million during 2017. While there is no impact to net income overall from this rate adjustment, operating cash flows will be reduced as the regulatory liability balance is refunded.
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 infrastructure that does not currently provide incremental revenues. This mechanism has been in place since that time. Each year, Southwest files a Gas Infrastructure Replacement (“GIR”) Advance Application requesting authority to replace infrastructure under this mechanism and files separately as part of an annual GIR filing to reset the recovery surcharge. In December 2015, the PUCN approved new rates, effective in January 2016, which resulted in approximately $4 million in annualized revenues. For 2016, the annualized revenue requirement associated with the accelerated pipe replacement approved in 2015, to be completed during 2016 was approximately $4.5 million. In June 2016, Southwest filed a GIR Advance Application with the PUCN for projects expected to be completed during 2017. This filing proposed approximately $60 million of accelerated pipe replacement to include early vintage plastic, early vintage steel, and a Customer-Owned Yard Line (“COYL”) program. The COYL program, while not large in magnitude, represents the first of its kind in Nevada, modeled after the program in place in Southwest’s Arizona jurisdiction for several years. The PUCN issued an Order on the Advance Application in October 2016, approving approximately $57.3 million of replacement work with an annualized revenue requirement estimated at approximately $5.3 million. The proposed COYL program was approved for the northern Nevada rate jurisdiction, but consideration for the southern Nevada rate jurisdiction was deferred until 2020, at which time certain early vintage plastic pipe programs are expected to be completed. In September 2016, Southwest filed to adjust the GIR surcharge to recover the annual revenue requirement for amounts previously deferred. This filing was approved in December 2016 and new rates became effective January 2017.
Subsequent to three GIR rate applications, the GIR regulations require Southwest to either file a general rate case or a request for waiver before it can file another GIR advance application. The October 2016 rate application was the third filed by Southwest, necessitating a filing requesting a waiver to allow Southwest to proceed with the GIR program without filing a general rate case in 2017. This waiver was approved by the PUCN in January 2017; however, in order to continue the GIR program in 2018, a general rate case will need to be filed before June 2018.
Conservation and Energy Efficiency(“CEE”). In June 2015, 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 initial program costs was approved as part of the most recent general rate case, amounts incurred subsequent to May 2012 (the certification period) continued to be deferred. Approved rates for the post-May 2012 costs deferred became effective January 2016 and resulted in annualized margin increases of $2 million in northern Nevada and $8.5 million in southern Nevada, and also include amounts representing expected program expenditures for 2016. As part of the ARA filing approved in December 2016, Southwest will modify rates that will result in annualized margin decreases of $1.4 million in northern Nevada and $1.3 million in southern Nevada effective January 2017. There is, however, no anticipated impact to net income overall from these lower recoveries as amortization expense will also be reduced.
| Southwest Gas Corporation |
23 |
California Jurisdiction
General Rate Case. In December 2012, Southwest filed a general rate case application, based on a 2014 future test year, with the 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 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 provided 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, and annual attrition increases were implemented in January of both 2015 and 2016 in accordance with the June 2014 decision.
In November 2016, Southwest made its latest annual PTY attrition filing, requesting annual revenue increases of $2.1 million in southern California, $513,000 in northern California, and $256,000 for South Lake Tahoe. This filing was approved in December 2016 and rates were made effective in January 2017. At the same time, rates were updated to recover the regulatory asset associated with the revenue decoupling mechanism, or margin tracker.
In December 2016, Southwest filed to modify the most recent general rate case decision to extend the annual PTY attrition adjustments through 2020. The original decision would have required Southwest to file its next general rate application by September 2017. Southwest believes this extension would be in the public interest as it allows customers two additional years of reasonable and relatively stable rates, and would not be expected to be detrimental to Southwest. Expedited consideration has been requested; however, Southwest also requested that if a decision has not been received by April 2017, the CPUC suspend the filing requirements until such time as a decision is issued.
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 (in the third quarters of each year 2014 through 2016) its allocations for each year from 2015 through 2017. Of those allocated allowances, Southwest must consign a certain percentage to the CARB for auction. Southwest 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.
| Southwest Gas Corporation |
24 |
Arizona Jurisdiction
Arizona General Rate Case. Southwest filed a general rate application with the ACC in May 2016 requesting an increase in authorized annual operating revenues of approximately $32 million, or 4.2%, to reflect existing levels of expense and requested returns, in addition to reflecting capital investments made by Southwest since June 2010. The application requested an overall rate of return of 7.82% on an original cost rate base of $1.336 billion, a 10.25% return on common equity, and a capital structure utilizing 52% common equity. The filing included a depreciation study that supported a proposal to reduce currently effective depreciation expense by approximately $42 million, which was considered in the overall requested amount. This expense reduction coupled with the requested revenue increase, resulted in a net annual operating income increase request of $74 million. Southwest also sought to continue the current COYL program approved in its last general rate case and to expand this mechanism to include other non-revenue producing projects such as the replacement of vintage steel pipe, while utilizing the same cost recovery methodology. Southwest also requested a property tax tracker and to maintain the current decoupled rate design. A settlement (contingent on ACC approval) was reached among several parties in December 2016 and a formal draft settlement was filed in January 2017. Hearings were held in February 2017. The draft settlement provides for an overall operating revenue increase of $16 million and the capital structure and cost of capital as proposed by Southwest, with the exception of the return on common equity, which would be set at 9.50%. If approved, depreciation expense would be reduced by $44.7 million, for a combined net annual operating income increase of $60.7 million. Other key elements of the draft settlement include approval of the continuation of the current COYL program, a property tax mechanism to defer any changes in property tax expense for recovery in the next general rate case, implementation of a vintage steel pipe replacement program, and a continuation of the current decoupled rate design excluding a winter-period adjustment to rates, making the mechanism fundamentally similar to Nevada. The draft settlement also includes a three-year rate case moratorium prohibiting a new application to adjust base rates from being filed prior to May 2019. Pending ACC approval, new rates are expected to be in place by May 2017.
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, to be 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, up to $50 million. The initial cost estimate was made in 2013 prior to selecting the land and receipt of the detailed engineering design specifications. Following the December 2014 preapproval, Southwest purchased the site for the facility and completed detailed engineering design specifications for the purpose of soliciting bids for the engineering, procurement and construction (“EPC”) of the facility. Southwest solicited requests for proposals for the EPC phase of the project, and in October 2016 made a filing with the ACC to modify the previously issued Order to update the pre-approved costs to reflect a not-to-exceed amount of $80 million, which was intended to update the pre-approval to reflect the current pricing information made available through the recently completed EPC phase. The filing was approved by the ACC in December 2016. Through December 2016, Southwest incurred approximately $4.1 million in capital expenditures toward the project (including land acquisition costs). Southwest included a proposal for the ratemaking treatment of facility costs as part of its current Arizona rate case filing; the draft settlement discussed in the section above includes an agreement to defer the revenue requirement associated with all costs incurred before December 31, 2020 for recovery in Southwest’s next general rate case
| Southwest Gas Corporation |
25 |
proceeding and extended the authorization to defer costs through the same date. Any gas costs incurred that are not related to the initial construction and placement of the facility are to be recovered through the PGA mechanism. Construction is expected to be completed by the end of 2019.
COYL Program. Southwest received approval, in connection with its previous 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 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. Effective June 2013, the ACC authorized a surcharge to recover the costs of depreciation and pre-tax return on the costs incurred to replace and relocate service lines and meters. The surcharge is revised annually as the program progresses. In 2014, Southwest received approval to add a “Phase II” component to the COYL program to include the replacement of non-leaking COYLs. In the most recent annual COYL filing made in February 2016, Southwest requested to increase the annual surcharge revenue from $2.5 million to $3.7 million to reflect additional costs incurred for both Phase I and Phase II. This request was based on total capital expenditures of $23.1 million, $13.4 million of which was incurred during 2014 and 2015. In May 2016, the ACC issued a decision approving the surcharge application, effective in June 2016.
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. In September 2014, Paiute reached an agreement in principle with the FERC Staff and intervenors to settle the case, and in February 2015, the FERC approved the settlement. Tariff changes 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 implied an 11.5% pre-tax rate of return. Also, as part of this agreement, Paiute agreed to file a rate case no later than May 2019. No filing in advance of the date required is currently contemplated.
Elko County Expansion Project. Paiute previously requested to expand its existing transmission system to provide additional firm transportation-service capacity in the Elko County, Nevada area, in order to meet growing natural gas demands caused by increased residential and business load and the greater energy needs of mining operations in the area. 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 project were implemented in January 2016 and are designed to result in $6 million in revenue annually. As of December 31, 2016, costs incurred were approximately $35 million and costs associated with remaining site restoration along the construction corridor are estimated at less than $1 million.
2018 Expansion. In response to growing demand in the Carson City and South Lake Tahoe areas of northern California and northern Nevada, Paiute evaluated shipper interest in acquiring additional transportation capacity and executed precedent agreements for incremental transportation capacity with Southwest during the third quarter of 2016. In October 2016, Paiute initiated a pre-filing review process with the FERC for an expansion project, which was approved during the same month. The project is anticipated to consist of 8.4 miles of additional transmission pipeline infrastructure at an approximate cost of $17 million. A formal certificate application is
| Southwest Gas Corporation |
26 |
expected to be filed in mid-2017, at which time, an environmental assessment will also be facilitated. If the process progresses as planned, the additional facilities could be in place by the end of 2018.
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, 2016, under-collections in California resulted in an asset of $2.6 million, and over-collections in Arizona and northern and southern Nevada collectively resulted in a liability of $90.5 million on Southwest’s balance sheet. Gas cost rates paid to suppliers have been lower than amounts recovered from customers during 2016, resulting in additional over-recoveries since December 31, 2015. Despite surcredits in place during 2016, the lower cost of natural gas resulted in PGA payables existing at December 31, 2016. 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):
| 2016 | 2015 | |||||||
| Arizona |
$ | (20,349 | ) | $ | (3,537 | ) | ||
| Northern Nevada |
(3,339 | ) | (2,311 | ) | ||||
| Southern Nevada |
(66,788 | ) | (39,753 | ) | ||||
| California |
2,608 | 3,591 | ||||||
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| $ | (87,868 | ) | $ | (42,010 | ) | |||
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Arizona PGA Filings. In Arizona, Southwest calculates the change in the gas cost component of customer rates, which are updated monthly, utilizing a rolling twelve-month average. 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 component of $0.06 per therm effective August 2014. After this surcharge component was reduced during 2015, it was then eliminated in August 2015 as the receivable balance was fully collected. A surcredit was implemented in April 2016 to refund the over-collected balance, which has been adjusted monthly through December 2016.
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 2016, 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 2017. These new rates are intended to reduce the outstanding liability over a twelve-month period.
| Southwest Gas Corporation |
27 |
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 2016/2017 heating season, contracts contained in the fixed-price portion of the supply portfolio ranged from approximately $2.65 to approximately $4.15 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, Southwest suspended fixed-for-floating-index-price swaps and fixed-price purchases pursuant to the Volatility Mitigation Program (“VMP”) for its Nevada service territories. Southwest evaluates, on a quarterly basis, the suspension of Nevada VMP purchases in light of prevailing market fundamentals and regulatory conditions.
Pipeline Safety Regulation
The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) is in the process of proposing a series of significant rulemakings that are expected to further transform the regulatory requirements for pipelines. In October 2016, PHMSA issued a final rule regarding expanding the use of excess flow valves in natural gas distribution systems. The new rule has an effective date of April 2017. Management continues to evaluate potential impacts of this regulation on its operations and customers. Management continues to monitor changing pipeline safety legislation and participates to the extent possible in developing associated mandates and reporting requirements. Additionally, it works with its state and federal commissions, where possible, to develop customer rates that are responsive to incremental costs of compliance. However, due to the timing of when rates are implemented in response to new requirements, and as additional rules are developed, compliance requirements could impact operating expenses and the timing and amount of capital expenditures.
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 of Southwest was accelerated during these years to take advantage of bonus depreciation tax incentives and to fortify system integrity and reliability. During the same three-year period, the Company was able to establish long-term cost savings from debt refinancing and strategic debt redemptions. The Company’s capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs. 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 $51.2 million between 2016 and 2015. The improvement in operating cash flows included an increase in net income and benefits from depreciation and deferred income taxes as well as the impacts of working capital components overall. Additionally, new and updated surcharges for decoupling mechanisms, conservation and energy efficiency and gas
| Southwest Gas Corporation |
28 |
infrastructure programs improved cash flows during 2016. Refer to Results of Natural Gas Operations and Rates and Regulatory Proceedings.
Investing Cash Flows. Cash used in consolidated investing activities increased $55.8 million in 2016 as compared to 2015. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by Centuri due to the increased replacement construction work of its customers, as well as the acquisition of ETTI in the construction services segment.
Financing Cash Flows. Net cash used in consolidated financing activities increased $1 million between 2016 and 2015. Southwest issued $300 million in senior notes and redeemed approximately $125 million of IDRBs during the current period (see Note 7 – Long-Term Debt). It also temporarily paid down $145 million of amounts outstanding on the long-term portion, as well as $18 million of amounts outstanding on the short-term portion, of its credit and commercial paper facility during 2016. All other long-term debt issuance amounts and retirements of long-term debt during this period are attributable to Centuri’s borrowing and repayment activity. The Company issued stock under its Equity Shelf Program during 2015, but not in 2016. See Note 6 – Common Stock, and discussion below. Dividends paid increased in 2016 as compared to 2015 as a result of an increase in the quarterly dividend rate and an increase in the number of shares outstanding.
Capital requirements and resources 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.
2016 Construction Expenditures
During the three-year period ended December 31, 2016, total gas plant in service increased from $5.3 billion to $6.2 billion, or at an average annual rate of 6%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as Southwest set approximately 70,000 meters during the three-year period.
During 2016, construction expenditures for the natural gas operations segment were $457 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 $507 million and provided approximately 94% 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.
2016 Financing Activity
The $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) were redeemed at par plus accrued interest in July 2016. In September 2016, the $24.9 million 2006A 4.75% fixed-rate IDRBs (originally due in 2036) were redeemed at par plus accrued interest. Subsequently, in January 2017, Southwest repaid in full $25 million of 7.59% medium-term notes at maturity.
In September 2016, $300 million in 3.8% Senior Notes were issued at a discount of 0.302%. The notes will mature in September 2046. A portion of the net proceeds were used to temporarily pay down amounts outstanding under the credit facility. The remaining net proceeds were used for general corporate purposes.
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29 |
During 2016, approximately 105,000 shares of common stock collectively were issued through the Restricted Stock/Unit Plan, the Management Incentive Plan, and the Stock Incentive Plan. Approximately $735,000 was raised from the issuance of shares of common stock through the Stock Incentive Plan.
Three-Year Construction Expenditures, Debt Maturities, and Financing
Management estimates natural gas segment construction expenditures during the three-year period ending December 31, 2019 will be between $1.6 billion and $1.8 billion. Of this amount, approximately $570 million is expected to be incurred in 2017. Southwest plans to continue, as appropriate, to request regulatory support to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). This includes the recent approval in Nevada to complete $57.3 million in accelerated replacement projects in Nevada in 2017 as well as programs included in the current Arizona general rate case draft settlement (approval of the continuation of the COYL program and implementation of a vintage steel pipe replacement program) 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, 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 of natural gas operations. 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 debt securities, bank and other short-term borrowings, and other forms of financing. See additional discussion in the Notes to our financial statements (specifically, Note 6 – Common Stock).
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 management) 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, the ability to access and obtain capital from external sources, interest rates, changes in income tax laws, pension funding requirements, inflation, and the level of earnings. Natural gas prices and related gas cost recovery rates have historically had the most significant impact on 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 2016, the PGA net payable (over-collected) balance increased from $42 million to $87.9 million at December 31, 2016. See PGA Filings for more information.
In March 2016, Southwest amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020 and was extended to March 2021. 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 2016 occurred during the third quarter and was $230 million ($150 million outstanding on the long-term portion of the credit facility, including $50 million on the commercial paper program, in addition to $80 million outstanding on the short-term portion). At December 31, 2016, $5 million
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was outstanding on the long-term portion of the credit facility (none of which was in commercial paper), and no borrowings were 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 fourth quarters was $68 million, $5 million, and $9 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. At December 31, 2016, the credit facility was deemed adequate for working capital needs outside of funds raised through operations and other types of external financing.
Southwest has a $50 million commercial paper program as noted above. Any issuance under the commercial paper program is supported by the 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, 2016, no borrowings were outstanding on the commercial paper program. The maximum outstanding on the program was $50 million in each of the first and third quarters. Other than the $25 million 7.59% medium-term notes, which were repaid upon maturity in January 2017, there are no other long-term debt maturities in 2017.
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 credit facility during 2016 was $198 million, which occurred in the third quarter, at which point $115 million was outstanding on the term loan facility. At December 31, 2016, $41.2 million was outstanding on the Centuri secured revolving credit facility. At December 31, 2016, there was approximately $95 million, net of letters of credit, available under the line of credit.
Credit Ratings
Credit ratings apply to debt securities such as bonds, notes, and other debt instruments and do not apply to equity securities such as common stock. Borrowing costs and the ability to raise funds are directly impacted by the credit ratings of the Company. Credit ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Credit ratings are important because long-term debt constitutes a significant portion of total capitalization. These credit ratings are a factor considered by lenders when determining the cost of future debt for both Southwest and Southwest Gas Holdings, Inc. (i.e., generally the better the rating, the lower the cost to borrow funds). The current unsecured long-term debt ratings of both companies are all considered investment grade.
The issuer credit rating for Southwest Gas Holdings, Inc. from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as assigned in December 2016. Southwest’s unsecured long-term debt rating from Standard & Poor’s Ratings Services (“S&P”) is BBB+ with a stable outlook as reaffirmed in December 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.
The issuer credit rating of Southwest Gas Holdings, Inc. from Moody’s Investors Service, Inc. (“Moody’s”) is Baa1 with a stable outlook as assigned in December 2016. Southwest Gas Corporation’s senior unsecured long-term
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debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is A3 with a stable outlook as last affirmed 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 long-term issuer default rating (“IDR”) of Southwest Gas Holdings, Inc. from Fitch Ratings (“Fitch”) is BBB+ (with a stable outlook) as assigned in December 2016. Southwest’s senior unsecured long-term debt rating from Fitch Ratings (“Fitch”) is A (with a stable outlook) as affirmed in December 2016. 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.
A credit rating is not a recommendation to buy, sell, or hold a debt security, but is intended to provide an estimation of the relative level of credit risk of debt securities, and is subject to change or withdrawal at any time by the rating agency. The foregoing credit ratings are subject to change at any time in the discretion of the applicable ratings agency. Numerous factors, including many that are not within management’s control, are considered by the ratings agencies in connection with assigning credit ratings.
No debt instruments have credit triggers or other clauses that result in default if these bond ratings are lowered by rating agencies. Certain 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, 2016, the Company is in compliance with all covenants. Under the most restrictive of the covenants, approximately $2.3 billion in additional debt could be issued and the leverage ratio requirement would still be met. At least $1.1 billion of cushion in equity relating to the minimum net worth requirement exists at December 31, 2016.
Certain Centuri debt instruments have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue over $145 million in additional debt and meet the leverage ratio requirement. Centuri has at least $21 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.
Bonus Depreciation
In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (“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 bonus deduction after 2019. Management estimates the bonus depreciation provision of the PATH Act will defer the payment of more than $60 million of federal income taxes for 2016. The actual amount will be dependent upon the ultimate level of qualifying expenditures. The foregoing does not contemplate any further changes not already enacted.
Inflation
Inflation can impact 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
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components of the cost of service, and gas infrastructure 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.
Off-Balance Sheet Arrangements
All debt is recorded in the balance sheet. Long-term operating and capital leases 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 table below summarizes the Company’s contractual obligations at December 31, 2016 (millions of dollars):
| Payments due by period | ||||||||||||||||||||
| Contractual Obligations | Total | 2017 | 2018-2019 | 2020-2021 | Thereafter | |||||||||||||||
| Operating leases (Note 2) |
$ | 21 | $ | 7 | $ | 8 | $ | 4 | $ | 2 | ||||||||||
| Gas purchase obligations |
155 | 108 | 46 | 1 | — | |||||||||||||||
| Pipeline capacity/storage |
1,117 | 137 | 192 | 150 | 638 | |||||||||||||||
| Other commitments |
22 | 12 | 10 | — | — | |||||||||||||||
| Long-term debt, including current maturities (Note 7) |
1,600 | 50 | 159 | 142 | 1,249 | |||||||||||||||
| Interest on long-term debt |
1,088 | 65 | 129 | 114 | 780 | |||||||||||||||
| Capital leases (Note 2) |
2 | 1 | 1 | — | — | |||||||||||||||
|
|
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|
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| Total |
$ | 4,005 | $ | 380 | $ | 545 | $ | 411 | $ | 2,669 | ||||||||||
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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 155 million dekatherms. The fixed-price contracts range in price from approximately $2.65 to approximately $4.15 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 mechanisms. 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 consist 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, 2016 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 2017 is $39 million and is not included in the table above.
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Recently Issued Accounting Standards Updates
The Financial Accounting Standards Board (“FASB”) recently issued Accounting Standards Updates related to revenue recognition, recognition and measurement of financial instruments, leases, stock compensation, measurement of credit losses, classification of certain cash receipts and cash payments in the cash flow statement, accounting for income taxes relating to intra-entity asset transfers other than inventory, consolidation of a variable interest entity involving related parties under common control, and simplifying the test for goodwill impairment. See Note 1 – Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on 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 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. For more information regarding significant accounting policies, 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. Management reviews the regulatory assets to assess their ultimate recoverability within the approved regulatory guidelines. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset (which would be recognized as current-period expense). Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.
Accrued Utility Revenues
Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, operating 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,
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analyses reflecting significant historical trends, seasonality, and experience. The interplay of these assumptions can impact the variability of the accrued utility revenue estimates. All Southwest rate jurisdictions have decoupled rate structures, limiting variability due to extreme weather conditions.
Accounting for Income Taxes
The Company is subject to income taxes in the United States and Canada. Income tax calculations 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 asset and liability method of accounting is utilized 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 management 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. Management 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, financial position, and/or results of operations.
Accounting for Pensions and Other Postretirement Benefits
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, there is a separate unfunded supplemental retirement plan which is limited to officers. Pension obligations and costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans. For example, a change of 0.25% in the discount rate assumption would change the pension plan projected benefit obligation by approximately $36.3 million and future pension expense by $3.6 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.0 million and expense by $1.5 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.9 million (but has no impact on the pension obligation).
At December 31, 2016, the discount rate is 4.50%, the same as at December 31, 2015. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation escalation remains at 3.25%. The asset return assumption of 7.00% to be used for 2017 expense was lowered from the 7.25% rate used for 2016. Pension expense for 2017 is estimated to be similar to that experienced in 2016. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.
Certifications
The Securities and Exchange Commission (“SEC”) requires the filing of certifications of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) of registrants regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to periodic filings. The CEO and CFO certifications for the period ended December 31, 2016 are included as exhibits to the 2016 Annual Report on Form 10-K filed with the SEC.
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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 management’s plans, objectives, goals, intentions, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “if,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “continue,” “forecast,” “intend,” “promote,” “seek,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding operating margin patterns, customer growth, the composition of our customer base, price volatility, seasonal patterns, payment of debt, interest savings, replacement market and new construction market, bonus depreciation tax deductions and future changes not yet enacted, amount and timing for completion of estimated future construction expenditures, including the LNG facility in southern Arizona and the cost of the Paiute 2018 expansion, 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 2017 or future period revenues from regulatory rate proceedings, approval of the Arizona general rate case settlement and effective date of new general rates, PTY rate adjustments and the extension request including period for the next California general rate case, ARA rates and other surcharges, Nevada Conservation and Energy Efficiency programs, PGA, and other rate adjustments, sufficiency of working capital and current credit facilities, bank lending practices, ability to raise funds and receive external financing capacity, 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, effective dates of pipeline regulations, infrastructure replacement mechanisms and COYL programs, 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 ETTI will be deductible for tax purposes, 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 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, 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, management 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 business risks, see Item 1A. Risk
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Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Annual Report on Form 10-K for the year ended December 31, 2016.
All forward-looking statements in this annual report are made as of the date hereof, based on information available to management as of the date hereof, and we assume no obligation to update or revise any 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
| 2016 | 2015 | Dividends Declared | ||||||||||||||||||||||
| High | Low | High | Low | 2016 | 2015 | |||||||||||||||||||
| First quarter |
$ | 67.29 | $ | 53.51 | $ | 63.68 | $ | 52.94 | $ | 0.450 | $ | 0.405 | ||||||||||||
| Second quarter |
79.43 | 62.75 | 59.75 | 51.69 | 0.450 | 0.405 | ||||||||||||||||||
| Third quarter |
79.58 | 67.97 | 58.40 | 51.26 | 0.450 | 0.405 | ||||||||||||||||||
| Fourth quarter |
76.64 | 64.35 | 62.56 | 50.78 | 0.450 | 0.405 | ||||||||||||||||||
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| $ | 1.800 | $ | 1.620 | |||||||||||||||||||||
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The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2017, there were 13,488 holders of record of common stock, and the market price of the common stock was $82.93.
Dividends are payable on the Company’s common stock at the discretion of the Board of Directors (“Board”). In setting the dividend rate, the Board considers, among other factors, current and expected future earnings levels, our ongoing capital expenditure plans and expected external funding needs, our payout ratio, and our ability to maintain strong credit ratings and liquidity. The quarterly common stock dividend declared was 36.5 cents per share throughout 2014, 40.5 cents per share throughout 2015, and 45 cents per share throughout 2016. The Company has paid dividends on its common stock since 1956 and has increased that dividend each year since 2007. In February 2017, the Board elected to increase the quarterly dividend from $0.45 to $0.495 per share, representing a 10% increase, effective with the June 2017 payment. The Board currently targets a payout ratio of 55% to 65% of consolidated earnings per share.
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SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except par value)
| December 31, | 2016 | 2015 | ||||||
| ASSETS |
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| Utility plant: |
||||||||
| Gas plant |
$ | 6,193,564 | $ | 5,854,917 | ||||
| Less: accumulated depreciation |
(2,172,966 | ) | (2,084,007 | ) | ||||
| Acquisition adjustments, net |
196 | 370 | ||||||
| Construction work in progress |
111,177 | 119,805 | ||||||
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| Net utility plant (Note 2) |
4,131,971 | 3,891,085 | ||||||
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| Other property and investments (Note 1) |
342,343 | 313,531 | ||||||
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| Current assets: |
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| Cash and cash equivalents |
28,066 | 35,997 | ||||||
| Accounts receivable, net of allowances (Note 3) |
285,145 | 314,512 | ||||||
| Accrued utility revenue |
76,200 | 74,700 | ||||||
| Income taxes receivable, net |
4,455 | 34,175 | ||||||
| Deferred purchased gas costs (Note 4) |
2,608 | 3,591 | ||||||
| Prepaids and other current assets (Notes 1, 4, and 13) |
136,833 | 95,199 | ||||||
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| Total current assets |
533,307 | 558,174 | ||||||
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| Noncurrent assets: |
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| Goodwill (Note 1) |
139,983 | 126,145 | ||||||
| Deferred income taxes (Note 12) |
1,288 | 428 | ||||||
| Deferred charges and other assets (Notes 2, 4, and 13) |
432,234 | 469,322 | ||||||
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| Total noncurrent assets |
573,505 | 595,895 | ||||||
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| Total assets |
$ | 5,581,126 | $ | 5,358,685 | ||||
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CONSOLIDATED BALANCE SHEETS – Continued
| December 31, | 2016 | 2015 | ||||||
| CAPITALIZATION AND LIABILITIES |
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| Capitalization: |
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| Common stock, $1 par (authorized – 60,000,000 shares; issued and outstanding – 47,482,068 and 47,377,575 shares) (Note 11) |
$ | 49,112 | $ | 49,007 | ||||
| Additional paid-in capital |
903,123 | 896,448 | ||||||
| Accumulated other comprehensive income (loss), net (Note 5) |
(48,008 | ) | (50,268 | ) | ||||
| Retained earnings |
759,263 | 699,221 | ||||||
|
|
|
|
|
|||||
| Total Southwest Gas Corporation equity |
1,663,490 | 1,594,408 | ||||||
| Noncontrolling interest |
(2,217 | ) | (2,083 | ) | ||||
|
|
|
|
|
|||||
| Total equity |
1,661,273 | 1,592,325 | ||||||
| Redeemable noncontrolling interest (Note 16) |
22,590 | 16,108 | ||||||
| Long-term debt, less current maturities (Note 7) |
1,549,983 | 1,551,204 | ||||||
|
|
|
|
|
|||||
| Total capitalization |
3,233,846 | 3,159,637 | ||||||
|
|
|
|
|
|||||
| Commitments and contingencies (Note 9) |
||||||||
| Current liabilities: |
||||||||
| Current maturities of long-term debt (Note 7) |
50,101 | 19,475 | ||||||
| Short-term debt (Note 8) |
— | 18,000 | ||||||
| Accounts payable |
184,669 | 164,857 | ||||||
| Customer deposits |
72,296 | 72,631 | ||||||
| Income taxes payable, net |
1,909 | 940 | ||||||
| Accrued general taxes |
42,921 | 47,337 | ||||||
| Accrued interest |
17,939 | 16,173 | ||||||
| Deferred purchased gas costs (Note 4) |
90,476 | 45,601 | ||||||
| Other current liabilities (Notes 2, 4, and 13) |
168,064 | 150,031 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
628,375 | 535,045 | ||||||
|
|
|
|
|
|||||
| Deferred income taxes and other credits: |
||||||||
| Deferred income taxes and investment tax credits, net (Note 12) |
840,653 | 769,445 | ||||||
| Accumulated removal costs (Note 4) |
308,000 | 303,000 | ||||||
| Other deferred credits and other long-term liabilities (Notes 2, 4, 10, and 13) |
570,252 | 591,558 | ||||||
|
|
|
|
|
|||||
| Total deferred income taxes and other credits |
1,718,905 | 1,664,003 | ||||||
|
|
|
|
|
|||||
| Total capitalization and liabilities |
$ | 5,581,126 | $ | 5,358,685 | ||||
|
|
|
|
|
|||||
The accompanying notes are an integral part of these statements.
| Southwest Gas Corporation |
39 |
SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Operating revenues: |
||||||||||||
| Gas operating revenues |
$ | 1,321,412 | $ | 1,454,639 | $ | 1,382,087 | ||||||
| Construction revenues |
1,139,078 | 1,008,986 | 739,620 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating revenues |
2,460,490 | 2,463,625 | 2,121,707 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating expenses: |
||||||||||||
| Net cost of gas sold |
397,121 | 563,809 | 505,356 | |||||||||
| Operations and maintenance |
401,724 | 393,199 | 383,732 | |||||||||
| Depreciation and amortization |
289,132 | 270,111 | 253,027 | |||||||||
| Taxes other than income taxes |
52,376 | 49,393 | 47,252 | |||||||||
| Construction expenses |
1,024,423 | 898,781 | 647,857 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating expenses |
2,164,776 | 2,175,293 | 1,837,224 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
295,714 | 288,332 | 284,483 | |||||||||
|
|
|
|
|
|
|
|||||||
| Other income and (expenses): |
||||||||||||
| Net interest deductions (Notes 7 and 8) |
(73,660 | ) | (71,879 | ) | (72,069 | ) | ||||||
| Other income (deductions) |
9,469 | 2,879 | 7,107 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total other income and (expenses) |
(64,191 | ) | (69,000 | ) | (64,962 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Income before income taxes |
231,523 | 219,332 | 219,521 | |||||||||
| Income tax expense (Note 12) |
78,468 | 79,902 | 78,373 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income |
153,055 | 139,430 | 141,148 | |||||||||
| Net income (loss) attributable to noncontrolling interests |
1,014 | 1,113 | 22 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income attributable to Southwest Gas Corporation |
$ | 152,041 | $ | 138,317 | $ | 141,126 | ||||||
|
|
|
|
|
|
|
|||||||
| Basic earnings per share (Notes 1 and 15) |
$ | 3.20 | $ | 2.94 | $ | 3.04 | ||||||
|
|
|
|
|
|
|
|||||||
| Diluted earnings per share (Notes 1 and 15) |
$ | 3.18 | $ | 2.92 | $ | 3.01 | ||||||
|
|
|
|
|
|
|
|||||||
| Average number of common shares outstanding |
47,469 | 46,992 | 46,494 | |||||||||
| Average shares outstanding (assuming dilution) |
47,814 | 47,383 | 46,944 | |||||||||
The accompanying notes are an integral part of these statements.
| Southwest Gas Corporation |
40 |
SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of dollars)
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Net Income |
$ | 153,055 | $ | 139,430 | $ | 141,148 | ||||||
|
|
|
|
|
|
|
|||||||
| Other comprehensive income (loss), net of tax |
||||||||||||
| Defined benefit pension plans (Notes 5 and 10): |
||||||||||||
| Net actuarial gain (loss) |
(14,118 | ) | (18,922 | ) | (107,661 | ) | ||||||
| Amortization of prior service cost |
828 | 828 | 220 | |||||||||
| Amortization of net actuarial loss |
16,781 | 21,316 | 14,667 | |||||||||
| Prior service cost |
— | — | (4,130 | ) | ||||||||
| Regulatory adjustment |
(3,462 | ) | (3,500 | ) | 86,991 | |||||||
|
|
|
|
|
|
|
|||||||
| Net defined benefit pension plans |
29 | (278 | ) | (9,913 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Forward-starting interest rate swaps: |
||||||||||||
| Amounts reclassified into net income (Notes 5 and 13) |
2,075 | 2,073 | 2,073 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net forward-starting interest rate swaps |
2,075 | 2,073 | 2,073 | |||||||||
|
|
|
|
|
|
|
|||||||
| Foreign currency translation adjustments |
161 | (1,954 | ) | (659 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Total other comprehensive income (loss), net of tax |
2,265 | (159 | ) | (8,499 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income |
155,320 | 139,271 | 132,649 | |||||||||
| Comprehensive income (loss) attributable to noncontrolling interests |
1,019 | 1,047 | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income attributable to Southwest Gas Corporation |
$ | 154,301 | $ | 138,224 | $ | 132,649 | ||||||
|
|
|
|
|
|
|
|||||||
The accompanying notes are an integral part of these statements.
| Southwest Gas Corporation |
41 |
SOUTHWEST GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| CASH FLOW FROM OPERATING ACTIVITIES: |
||||||||||||
| Net Income |
$ | 153,055 | $ | 139,430 | $ | 141,148 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
289,132 | 270,111 | 253,027 | |||||||||
| Deferred income taxes |
68,732 | 48,785 | 64,309 | |||||||||
| Changes in current assets and liabilities: |
||||||||||||
| Accounts receivable, net of allowances |
30,096 | (39,850 | ) | (3,683 | ) | |||||||
| Accrued utility revenue |
(1,500 | ) | (800 | ) | (1,200 | ) | ||||||
| Deferred purchased gas costs |
45,858 | 129,566 | (69,339 | ) | ||||||||
| Accounts payable |
21,695 | (3,491 | ) | (41,499 | ) | |||||||
| Accrued taxes |
26,340 | (8,405 | ) | (13,573 | ) | |||||||
| Other current assets and liabilities |
(29,551 | ) | 18,300 | 23,379 | ||||||||
| Gains on sale |
(7,148 | ) | (3,102 | ) | (6,171 | ) | ||||||
| Changes in undistributed stock compensation |
5,456 | 2,914 | 7,973 | |||||||||
| AFUDC |
(2,289 | ) | (3,008 | ) | (1,995 | ) | ||||||
| Changes in other assets and deferred charges |
16,960 | (14,166 | ) | (21,732 | ) | |||||||
| Changes in other liabilities and deferred credits |
(18,447 | ) | 10,863 | 15,779 | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by operating activities |
598,389 | 547,147 | 346,423 | |||||||||
|
|
|
|
|
|
|
|||||||
| Southwest Gas Corporation |
42 |
CONSOLIDATED STATEMENTS OF CASH FLOWS – Continued
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| CASH FLOW FROM INVESTING ACTIVITIES: |
||||||||||||
| Construction expenditures and property additions |
(529,531 | ) | (488,000 | ) | (396,898 | ) | ||||||
| Acquisition of businesses, net of cash acquired |
(17,000 | ) | (9,261 | ) | (190,497 | ) | ||||||
| Restricted cash |
— | 785 | 1,233 | |||||||||
| Changes in customer advances |
7,900 | 18,300 | 20,363 | |||||||||
| Miscellaneous inflows |
13,039 | 8,354 | 11,611 | |||||||||
| Miscellaneous outflows |
— | — | (1,400 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash used in investing activities |
(525,592 | ) | (469,822 | ) | (555,588 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| CASH FLOW FROM FINANCING ACTIVITIES: |
||||||||||||
| Issuance of common stock, net |
472 | 35,396 | 405 | |||||||||
| Dividends paid |
(83,317 | ) | (74,248 | ) | (66,275 | ) | ||||||
| Centuri distribution to redeemable noncontrolling interest |
(439 | ) | (99 | ) | — | |||||||
| Issuance of long-term debt, net |
423,946 | 135,816 | 269,228 | |||||||||
| Retirement of long-term debt |
(255,273 | ) | (187,973 | ) | (139,155 | ) | ||||||
| Change in credit facility and commercial paper |
(145,000 | ) | — | 140,000 | ||||||||
| Change in short-term debt |
(18,000 | ) | 13,000 | 5,000 | ||||||||
| Principal payments on capital lease obligations |
(1,354 | ) | (1,420 | ) | (434 | ) | ||||||
| Other |
(1,569 | ) | 41 | (1,257 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by (used in) financing activities |
(80,534 | ) | (79,487 | ) | 207,512 | |||||||
|
|
|
|
|
|
|
|||||||
| Effects of currency translation on cash and cash equivalents |
(194 | ) | (1,407 | ) | 142 | |||||||
|
|
|
|
|
|
|
|||||||
| Change in cash and cash equivalents |
(7,931 | ) | (3,569 | ) | (1,511 | ) | ||||||
| Cash and cash equivalents at beginning of period |
35,997 | 39,566 | 41,077 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash and cash equivalents at end of period |
$ | 28,066 | $ | 35,997 | $ | 39,566 | ||||||
|
|
|
|
|
|
|
|||||||
| Supplemental information: |
||||||||||||
| Interest paid, net of amounts capitalized |
$ | 67,440 | $ | 66,623 | $ | 65,552 | ||||||
|
|
|
|
|
|
|
|||||||
| Income taxes paid (received) |
$ | (19,032 | ) | $ | 43,225 | $ | 24,247 | |||||
|
|
|
|
|
|
|
|||||||
The accompanying notes are an integral part of these statements.
| Southwest Gas Corporation |
43 |
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 |
||||||||||||||||||||||||||
| Shares | Amount | |||||||||||||||||||||||||||||||
| 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 | ) | ||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| Southwest Gas Corporation |
44 |
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 |
||||||||||||||||||||||||||
| Shares | Amount | |||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||
| Common stock issuances |
105 | 105 | 6,675 | 6,780 | ||||||||||||||||||||||||||||
| Net income (loss) |
152,041 | (134 | ) | 151,907 | 1,148 | |||||||||||||||||||||||||||
| Redemption value adjustments (Note 16) |
(5,768 | ) | (5,768 | ) | 5,768 | |||||||||||||||||||||||||||
| Foreign currency exchange translation adj. |
156 | 156 | 5 | |||||||||||||||||||||||||||||
| Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10) |
29 | 29 | ||||||||||||||||||||||||||||||
| Amounts reclassified to net income, net of tax (Notes 5 and 13) |
2,075 | 2,075 | ||||||||||||||||||||||||||||||
| Centuri distribution to redeemable noncontrolling interest |
(439 | ) | ||||||||||||||||||||||||||||||
| Dividends declared |
||||||||||||||||||||||||||||||||
| Common: $1.80 per share |
(86,231 | ) | (86,231 | ) | ||||||||||||||||||||||||||||
| DECEMBER 31, 2016 |
47,482 | * | $ | 49,112 | $ | 903,123 | $ | (48,008 | ) | $ | 759,263 | $ | (2,217 | ) | $ | 1,661,273 | $ | 22,590 | ||||||||||||||
|
|
||||||||||||||||||||||||||||||||
| * | There are 3.8 million common shares registered and available for issuance under provisions of the various stock issuance plans. |
The accompanying notes are an integral part of these statements.
| Southwest Gas Corporation |
45 |
Notes to Consolidated Financial Statements
Note 1—Summary of Significant Accounting Policies
Holding Company Reorganization. In 2015, the Board of Directors (“Board”) of the Southwest Gas Corporation (“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. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company (Southwest Gas Holdings, Inc.); whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of such reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The Board approved the reorganization in December 2016 which became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016. Specific disclosures and references to Southwest Gas Holdings, Inc. (the “holding company”) give effect to events and conditions of the equity registrant/consolidated entity and its officers or directors after December 31, 2016.
Nature of Operations. The Company consists of two segments: natural gas operations (“Southwest”) and construction services (Centuri). 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, a 96.6% owned subsidiary, is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operations occur in 20 major markets in the U.S. and within the Canadian provinces of British Columbia and Ontario, and are generally conducted under the business names of NPL Construction Co. (“NPL”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd.), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). In May 2016, Centuri completed the acquisition of two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”). ETTI is operated as part of Brigadier. See Acquisition of Construction Services Businesses below for more information. In January 2017, W.S. Nicholls began conducting business as WSN Fabrication, a division of NPL Canada Ltd.
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 rate-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
| Southwest Gas Corporation |
46 |
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 as of December 31, 2016 (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 investment in Western totaled $10.8 million at December 31, 2015 and 2016. Both periods include the impacts of foreign currency exchange translation adjustments. Dividends of $500,000 were received from Western during 2016 with no impact on earnings. No dividends were received from Western in 2015. A management fee was paid by Western to its partners, including W.S. Nicholls, in accordance with underlying agreements. 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 $35.8 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 were deemed to be worthless. Centuri recorded earnings of $69,000 from this investment in 2016, which is included in Other Income (deductions) in the Consolidated Statements of Income.
In addition, Centuri, through its subsidiaries, has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture, which are also equity method investments.
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 (thousands of dollars):
| 2016 | 2015 | |||||||
| Centuri property, equipment, and intangibles |
$ | 451,114 | $ | 423,369 | ||||
| Centuri accumulated provision for depreciation and amortization |
(228,374 | ) | (221,028 | ) | ||||
| Net cash surrender value of COLI policies |
106,744 | 99,276 | ||||||
| Other property |
12,859 | 11,914 | ||||||
|
|
|
|
|
|||||
| Total |
$ | 342,343 | $ | 313,531 | ||||
|
|
|
|
|
|||||
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
| Southwest Gas Corporation |
47 |
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 $30 million in 2016 and $24 million in 2015 (carried at weighted average cost). Also included is natural gas stored underground and liquefied natural gas (both carried at weighted average cost), in addition to prepaid assets.
Income Taxes. The asset and liability method of accounting is utilized for the recognition of 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, 2016, the Company had cumulative earnings of approximately $5 million in its foreign jurisdiction. However, management intends to permanently reinvest any foreign earnings in Canada. See Note 12 – Income Taxes for further information.
Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents also includes money market fund investments totaling approximately $5.3 million and $250,000 at December 31, 2016 and 2015, respectively, 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 $6.5 million, $3.1 million, and $8.1 million during 2016, 2015, and 2014, 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. This outflow activity was recorded in investing activities in 2015 as Acquisition of businesses, net of cash acquired.
Goodwill. Goodwill is assessed for impairment annually, 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 is conducted in the 4th quarter each year and 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 our reporting units are less than their carrying amounts in either 2015 or 2016. Thus, no impairment was recorded in either year. One of the businesses associated with the ETTI acquisition in 2016 (further discussion below) was acquired via asset purchase. As a result, goodwill associated with ETTI is expected to be deductible for tax purposes.
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48 |
| Natural Gas Operations |
Construction Services |
Consolidated | ||||||||||
| (In thousands of dollars) | ||||||||||||
| December 31, 2015 |
$ | 10,095 | $ | 116,050 | $ | 126,145 | ||||||
| Additional goodwill from ETTI acquisition |
— | 10,726 | 10,726 | |||||||||
| Foreign currency translation adjustment |
— | 3,112 | 3,112 | |||||||||
|
|
|
|
|
|
|
|||||||
| December 31, 2016 |
$ | 10,095 | $ | 129,888 | $ | 139,983 | ||||||
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|
|
|
|
|
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Goodwill from the ETTI acquisition consists of the excess of purchase price over the fair value of the acquired net assets and represents the value of the assembled workforce and the estimated economic value attributable to future opportunities that will arise based on the strong financial performance of the combined entities.
Acquisition of Construction Services Businesses. In May 2016, Centuri completed the acquisition of ETTI, which is based in Lisbon Falls, Maine, and has a primary focus on underground utility installation using horizontal directional drilling technology. The acquisition of ETTI will provide complementary operational support to, and be operated as part of, Brigadier, expanding operations into Maine. Neither the acquisition itself nor the impacts to assets and operations were material to the construction services segment or the Company at December 31, 2016.
Assets acquired in the transaction were recorded at their acquisition date fair values. The final purchase accounting is complete. The final estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):
| Acquisition Date |
||||
| Property, plant and equipment |
$ | 4.3 | ||
| Intangible assets |
2.9 | |||
| Goodwill |
10.7 | |||
|
|
|
|||
| Total assets acquired |
$ | 17.9 | ||
|
|
|
|||
The purchase price consisted of $17 million in cash on the acquisition date with the remaining amount being deferred over four years.
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49 |
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 construction services businesses acquired in 2014 and have finite lives. Centuri has $37.7 million and $36.8 million of intangible assets (varies due to foreign currency translation) at December 31, 2016 and 2015, respectively, as detailed in the following table (thousands of dollars):
| December 31, 2016 | Gross Carrying Amount |
Accumulated Amortization |
Net Carrying Amount |
|||||||||
| Customer relationships |
$ | 34,033 | $ | (3,906 | ) | $ | 30,127 | |||||
| Trade names and trademarks |
9,349 | (2,565 | ) | 6,784 | ||||||||
| Customer contracts backlog |
1,656 | (1,656 | ) | — | ||||||||
| Noncompete agreement |
1,029 | (271 | ) | 758 | ||||||||
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|
|
|
|
|
|
|||||||
| Total |
$ | 46,067 | $ | (8,398 | ) | $ | 37,669 | |||||
|
|
|
|
|
|
|
|||||||
| December 31, 2015 |
||||||||||||
| 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 | |||||
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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):
| 2017 |
$ | 3,339 | ||
| 2018 |
3,126 | |||
| 2019 |
2,463 | |||
| 2020 |
2,395 | |||
| 2021 |
2,269 |
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
| Southwest Gas Corporation |
50 |
recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of unusual weather variability and conservation on margin.
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. Management 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, office and equipment rental costs, subcontractor expenses, training, job-related materials, gains and losses on equipment sales, and professional fees of Centuri.
Net Cost of Gas Sold. Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of natural gas derivative instruments. Also included are the net impacts of PGA deferrals and recoveries, which by their inclusion, result in net cost of gas sold overall that is comparable to amounts included in billed gas operating revenues. Differences between amounts incurred with suppliers, transmission pipelines, etc. and those already included in customer rates, are temporarily deferred in purchased gas adjustment accounts pending inclusion in customer rates.
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. During the third quarter of 2016, Centuri evaluated the estimated useful lives of its depreciable assets, and in so doing determined that certain equipment lives should be extended. This change in estimate
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reduced 2016 depreciation by approximately $4 million. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense. 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.
| 2016 | 2015 | 2014 | ||||||||||
| (In thousands) |
||||||||||||
| AFUDC: |
||||||||||||
| Debt portion |
$ | 1,175 | $ | 1,666 | $ | 1,228 | ||||||
| Equity portion |
2,289 | 3,008 | 1,995 | |||||||||
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|
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|
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| AFUDC capitalized as part of utility plant |
$ | 3,464 | $ | 4,674 | $ | 3,223 | ||||||
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| AFUDC rate |
7.35 | % | 7.32 | % | 7.73 | % | ||||||
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):
| 2016 | 2015 | 2014 | ||||||||||
| Change in COLI policies |
$ | 7,400 | $ | (500 | ) | $ | 5,300 | |||||
| Interest income |
1,849 | 2,173 | 2,602 | |||||||||
| Equity AFUDC |
2,289 | 3,008 | 1,995 | |||||||||
| Foreign currency transaction gain (loss) |
(22 | ) | (824 | ) | (178 | ) | ||||||
| Equity in earnings of unconsolidated investment - Western |
69 | 310 | 107 | |||||||||
| Miscellaneous income and (expense) |
(2,116 | ) | (1,288 | ) | (2,719 | ) | ||||||
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| Total other income (deductions) |
$ | 9,469 | $ | 2,879 | $ | 7,107 | ||||||
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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 the Company 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
| Southwest Gas Corporation |
52 |
from intercompany foreign currency transactions that are of a long-term investment nature are reported in other comprehensive income, if applicable.
Earnings Per Share. Basic earnings per share (“EPS”) in each period of this report were calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during those periods. 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.
| 2016 | 2015 | 2014 | ||||||||||
| (In thousands) |
||||||||||||
| Average basic shares |
47,469 | 46,992 | 46,494 | |||||||||
| Effect of dilutive securities: |
||||||||||||
| Stock options |
1 | 8 | 17 | |||||||||
| Performance shares |
124 | 171 | 215 | |||||||||
| Restricted stock units |
220 | 212 | 218 | |||||||||
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| Average diluted shares |
47,814 | 47,383 | 46,944 | |||||||||
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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 the 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 July 2015, the FASB approved a one-year deferral of the effective date (annual periods beginning after December 15, 2017). In March, April, May, and December of 2016, the FASB issued updates to Topic 606 related to “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, “Identifying Performance Obligations and Licensing”, “Narrow-Scope Improvements and Practical Expedients”, and certain “Technical Corrections and Improvements”. The amendments in the first two updates, respectively, provide guidance when another party, along with the entity, is involved in providing a good or service to a customer, and provide clarification with regard to identifying performance obligations and of the licensing implementation guidance in Topic 606. The third update includes improvements to the guidance on collectability, noncash consideration, and completed contracts at transition. In addition, a practical expedient is provided for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The fourth update affects narrow aspects of the guidance as issued to date. The combined amendments do not change the core principles of the guidance in Topic 606. Management plans to adopt all of these updates at the required adoption date, which is for interim and annual reporting periods commencing January 2018.
Management has substantially completed the evaluation of the sources of revenue and are currently assessing the effect of the new guidance on the financial position, results of operations and cash flows. The assessment is contingent, in part, upon the completion of deliberations currently in progress by the utility industry, notably in
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connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants (“AICPA”). In association with this undertaking, the AICPA formed a number of industry task forces, including a Power & Utilities (“P&U”) Task Force, on which Company personnel actively participate via formal membership. Industry representatives and organizations, the largest auditing firms, the AICPA’s Revenue Recognition Working Group and its Financial Reporting Executive Committee have undertaken, and continue to undertake, consideration of several items relevant to the utility industry. Where applicable or necessary, the FASB’s Transition Resource Group (TRG) is also participating. Currently, the industry is working to address several items including the evaluation of collectability from customers if a utility has regulatory mechanisms to help assure recovery of uncollected accounts from ratepayers and the accounting for funds received from third parties to partially or fully reimburse the cost of construction of an asset. Currently, a timeline for the resolution of these deliberations has not been established. Southwest is actively working with its peers in the rate-regulated natural gas industry and with the public accounting profession to conclude on the accounting treatment for several other issues that are not expected to be addressed by the P&U Task Force.
As of December 31, 2016, the construction services segment has substantially completed the evaluation of sources of revenue and is currently assessing the effect of the new guidance on financial position, results of operations and cash flows. The principals of the new revenue recognition guidance are very similar to existing guidance for construction contractors. Similar to the P&U Task Force noted above, the AICPA formed the Engineering and Construction Contractors Task Force to assist the construction industry with implementing the new guidance. The accounting guide the AICPA intends to release is expected to provide implementation guidance related to several issues including 1) combining contracts and separating performance obligations; 2) estimating change orders, incentives, penalties, liquidated damages and other variable consideration items and 3) acceptable measures of progress when recognizing revenue over time.
Given the uncertainty with respect to the conclusions that might arise from the deliberations on issues associated with both the natural gas and construction services segments, the Company is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, business processes, or the transition method it will utilize to adopt the new guidance.
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 entity 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 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. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.
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In February 2016, the FASB issued the update “Leases (Topic 842)”. Under the update, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:
| • | A lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and |
| • | A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. |
Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Though companies have historically been required to make disclosures regarding leases and of contractual obligations, leases (with terms longer than a year) will no longer exist off-balance sheet. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. Early application is permitted. Management currently plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2019. Existing leases have been documented by both segments and management is in the process of determining if special software will be necessary to implement the standard. In addition, management is evaluating the potential impacts of various natural gas industry-related issues in light of the leasing standard. Given the uncertainty with respect to the conclusions that might arise from these deliberations, management is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, or business processes.
In March 2016, the FASB issued the update “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The update requires the recording of all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then recorded in the income statement. While the simplification will reduce some of the administrative complexities by eliminating the need to track a “windfall pool,” it will increase the volatility of income tax expense. The update also allows entities to withhold shares for the employee tax burden up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in a liability classification of the award (currently such withholding is limited to the employer’s minimum statutory withholding). The update clarifies that all cash payments made to taxing authorities on the employees’ behalf for withheld shares should be presented as financing activities on the statement of cash flows. Also, the update requires all tax-related cash flows resulting from share-based payments be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Management issues share-based payment awards to its employees. The update was adopted by management in January 2017.
In June 2016, the FASB issued the update “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. The update amends guidance on reporting credit losses for financial
| Southwest Gas Corporation |
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assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, the update eliminates the “probable” threshold for initial recognition of credit losses in current U.S. GAAP and, instead, requires an entity to reflect its current estimate of all expected credit losses. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset to present the net amount expected to be collected. For available for sale debt securities, credit losses should be measured in a manner similar to current U.S. GAAP, however the update will require that credit losses be presented as an allowance rather than as a write-down. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The update affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. All entities may adopt the amendments in this update earlier as of fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.
In August 2016, the FASB issued the update “Classification of Certain Cash Receipts and Cash Payments”. This update addresses the following specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance (“COLI”) policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows, including identification of the predominant nature in cases where cash receipts and payments have aspects of more than one class of cash flows. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Management is evaluating the impacts this update might have on its consolidated cash flow statements and disclosures.
In October 2016, the FASB issued the update “Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory.” This update eliminates the current U.S. GAAP exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted; however, the guidance can only be adopted in the first interim period of a fiscal year. The modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Management is evaluating the impacts this update might have on its consolidated financial statements.
In October 2016, the FASB issued the update “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” The amendments affect reporting entities that are required to evaluate whether they should consolidate a variable interest entity in certain situations involving entities under common control. The update is effective for fiscal and interim periods beginning after December 15, 2016. Management has determined that this update is not impactful to its consolidated financial statements.
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In January 2017, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The update eliminates Step 2 from the goodwill impairment test. The annual, or interim, goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. In addition, income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit should be considered when measuring the goodwill impairment loss, if applicable. The update also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative test, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The amendments should be applied on a prospective basis. The update is effective for fiscal and interim periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Management has determined that this update would have had no impact on the consolidated financial statements for the periods presented if it had been effective during those periods.
Subsequent Events. Management 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, 2016 and 2015 was as follows (thousands of dollars):
| December 31, | 2016 | 2015 | ||||||
| Gas plant: |
||||||||
| Storage |
$ | 24,614 | $ | 22,944 | ||||
| Transmission |
349,981 | 312,996 | ||||||
| Distribution |
5,198,531 | 4,935,730 | ||||||
| General |
382,084 | 365,865 | ||||||
| Software and software-related intangibles |
224,260 | 203,323 | ||||||
| Other |
14,094 | 14,059 | ||||||
|
|
|
|
|
|||||
| 6,193,564 | 5,854,917 | |||||||
| Less: accumulated depreciation |
(2,172,966 | ) | (2,084,007 | ) | ||||
| Acquisition adjustments, net |
196 | 370 | ||||||
| Construction work in progress |
111,177 | 119,805 | ||||||
|
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|
|
|
|||||
| Net utility plant |
$ | 4,131,971 | $ | 3,891,085 | ||||
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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 2016, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2015 and 2014 also approximated 3.6%. Transmission and Distribution plant (combined), associated with our core natural gas delivery
| Southwest Gas Corporation |
57 |
infrastructure, constitute the majority of gas plant. Annual depreciation expense averaged approximately 3.3% of original cost of depreciable transmission and distribution plant during the period 2014 through 2016.
Depreciation and amortization expense on gas plant, including intangibles, was as follows (thousands of dollars):
| 2016 | 2015 | 2014 | ||||||||||
| Depreciation and amortization expense |
$ | 214,037 | $ | 201,233 | $ | 194,360 | ||||||
Included in the figures above is amortization of intangibles of $14.8 million in 2016, $12.7 million in 2015, and $11.7 million in 2014.
Operating Leases and Rentals. Certain office and construction equipment is leased. 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):
| 2016 | 2015 | 2014 | ||||||||||
| Southwest Gas |
$ | 4,357 | $ | 4,186 | $ | 5,330 | ||||||
| Centuri |
53,956 | 45,849 | 30,012 | |||||||||
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| Consolidated rental payments/lease expense |
$ | 58,313 | $ | 50,035 | $ | 35,342 | ||||||
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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, 2016 (thousands of dollars):
| Year Ending December 31, |
||||
| 2017 |
$ | 6,929 | ||
| 2018 |
4,837 | |||
| 2019 |
3,449 | |||
| 2020 |
2,411 | |||
| 2021 |
1,098 | |||
| Thereafter |
2,730 | |||
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| Total minimum lease payments |
$ | 21,454 | ||
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Capital Leases. Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2016 and 2015 are as follows (thousands of dollars):
| December 31, | 2016 | 2015 | ||||||
| Capital leased assets, gross |
$ | 3,189 | $ | 4,584 | ||||
| Less: accumulated amortization |
(1,172 | ) | (1,043 | ) | ||||
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| Capital leased assets, net |
$ | 2,017 | $ | 3,541 | ||||
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| Southwest Gas Corporation |
58 |
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, 2016 (thousands of dollars):
| Year Ending December 31, | ||||
| 2017 |
$ | 931 | ||
| 2018 |
546 | |||
| 2019 |
84 | |||
| 2020 |
— | |||
| 2021 |
— | |||
| Thereafter |
— | |||
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| 1,561 | ||||
| Less: amount representing interest |
(101 | ) | ||
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| Total minimum lease payments |
$ | 1,460 | ||
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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, 2016 and 2015, and the percentage of customers in each of the three states.
| December 31, 2016 |
December 31, 2015 |
|||||||
| Gas utility customer accounts receivable balance (in thousands) |
$ | 111,320 | $ | 151,775 | ||||
| December 31, 2016 |
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| Percent of customers by state |
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| Arizona |
53 | % | ||
| Nevada |
37 | % | ||
| California |
10 | % | ||
| Southwest Gas Corporation |
59 |
Although Southwest 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, 2013 |
$ | 1,725 | ||
| Additions charged to expense |
4,146 | |||
| Accounts written off, less recoveries |
(3,616 | ) | ||
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| Balance, December 31, 2014 |
2,255 | |||
| Additions charged to expense |
4,113 | |||
| Accounts written off, less recoveries |
(4,098 | ) | ||
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| Balance, December 31, 2015 |
2,270 | |||
| Additions charged to expense |
3,264 | |||
| Accounts written off, less recoveries |
(3,010 | ) | ||
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| Balance, December 31, 2016 |
$ | 2,524 | ||
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At December 31, 2016, the construction services segment (Centuri) had $173 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs related to Centuri customers have been insignificant and are not reflected in the table above.
Note 4 – Regulatory Assets and Liabilities
Southwest is 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.
| Southwest Gas Corporation |
60 |
The following table represents existing regulatory assets and liabilities (thousands of dollars):
| December 31, | 2016 | 2015 | ||||||
| Regulatory assets: |
||||||||
| Accrued pension and other postretirement benefit costs (1) |
$ | 379,063 | $ | 384,647 | ||||
| Unrealized net loss on non-trading derivatives (Swaps) (2) |
— | 5,486 | ||||||
| Deferred purchased gas costs (3) |
2,608 | 3,591 | ||||||
| Accrued purchased gas costs (4) |
37,100 | — | ||||||
| Unamortized premium on reacquired debt (5) |
21,975 | 21,511 | ||||||
| Accrued absence time (9) |
13,440 | 13,240 | ||||||
| Other (6) |
23,557 | 59,782 | ||||||
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| 477,743 | 488,257 | |||||||
| Regulatory liabilities: |
||||||||
| Deferred purchased gas costs (3) |
(90,476 | ) | (45,601 | ) | ||||
| Accumulated removal costs |
(308,000 | ) | (303,000 | ) | ||||
| Accrued purchased gas costs (4) |
— | (10,400 | ) | |||||
| Unrealized net gain on non-trading derivatives (Swaps) (2) |
(4,377 | ) | — | |||||
| Unamortized gain on reacquired debt (7) |
(9,789 | ) | (10,325 | ) | ||||
| Other (8) |
(24,659 | ) | (36,631 | ) | ||||
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| Net regulatory assets |
$ | 40,442 | $ | 82,300 | ||||
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| (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 Southwest’s purchased gas adjustment (“PGA”) mechanisms. (See Note 13). |
| Instrument | Balance Sheet Location | 2016 | 2015 | |||||||
| Swaps |
Deferred charges and other assets | $ | — | $ | 1,219 | |||||
| Swaps |
Prepaids and other current assets | — | 4,267 | |||||||
| Swaps |
Other current liabilities | (3,532 | ) | — | ||||||
| Swaps |
Other deferred credits | (845 | ) | — | ||||||
| (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. |
| Southwest Gas Corporation |
61 |
| (6) | The following table details the components of Other regulatory assets which are included in either Prepaids and other current assets or Deferred charges and other assets on the Consolidated Balance Sheets (as indicated). Recovery periods vary. Margin tracking/decoupling mechanisms are alternative revenue programs and revenue associated with under-collections (for the difference between authorized margin levels and amounts billed to customers through rates currently) are recognized as revenue so long as recovery is expected to take place within 24 months. |
| Other Regulatory Assets | 2016 | 2015 | ||||||
| State mandated public purpose programs (including low income and conservation programs) (a) (f) |
$ | 7,096 | $ | 18,101 | ||||
| Margin and interest-tracking accounts (b) (f) |
3,517 | 30,339 | ||||||
| Infrastructure replacement programs and similar (c) (f) |
6,976 | 6,947 | ||||||
| Environmental compliance programs (d) (f) |
4,329 | 2,300 | ||||||
| Other (e) |
1,639 | 2,095 | ||||||
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| $ | 23,557 | $ | 59,782 | |||||
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| a) | 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets; 2015 included in Deferred charges and other assets on the Consolidated Balance Sheets. |
| b) | 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets; 2015 included in Prepaids and other current assets on the Consolidated Balance Sheets ($11 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($19.3 million). |
| c) | Included in Deferred charges and other assets on the Consolidated Balance Sheets with the exception of $6,000 in 2016 that is included in Prepaids and other current assets on the Consolidated Balance Sheets. |
| d) | 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets ($3.8 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($500,000); 2015 included in Prepaids and other current assets on the Consolidated Balance Sheets ($1.8 million) and Deferred charges and other assets on the Consolidated Balance Sheets ($484,000). |
| e) | 2016 included in Prepaids and other current assets on the Consolidated Balance Sheets ($622,000) and Deferred charges and other assets on the Consolidated Balance Sheets ($1 million); 2015 included in Deferred charges and other assets on the Consolidated Balance Sheets. |
| f) | Balance recovered or refunded on an ongoing basis, generally with interest. |
| (7) | Included in Other deferred credits on the Consolidated Balance Sheets. Amortized over life of debt instruments. |
| (8) | The following table details the components of Other regulatory liabilities which are included in either Other current liabilities or Deferred credits and other liabilities on the Consolidated Balance Sheets (as indicated). |
| Other Regulatory Liabilities | 2016 | 2015 | ||||||
| State mandated public purpose programs (including low income and conservation programs) (a) (d) |
$ | (7,101 | ) | $ | (4,888 | ) | ||
| Margin and interest-tracking accounts (a) (d) |
(3,668 | ) | (20,191 | ) | ||||
| Environmental compliance programs (b) (d) |
(4,469 | ) | (2,252 | ) | ||||
| Regulatory offsets to deferred tax balances (c) |
(3,390 | ) | (4,866 | ) | ||||
| Regulatory accounts for differences related to pension funding (c) |
(2,284 | ) | (1,363 | ) | ||||
| Income tax and gross-up (c) |
(3,203 | ) | (3,067 | ) | ||||
| Other (d) (e) |
(544 | ) | (4 | ) | ||||
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| $ | (24,659 | ) | $ | (36,631 | ) | |||
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| Southwest Gas Corporation |
62 |
| a) | 2016 included in Other current liabilities on the Consolidated Balance Sheets; 2015 included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets. |
| b) | Included in Other current liabilities on the Consolidated Balance Sheets. |
| c) | Included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets. |
| d) | Balance recovered or refunded on an ongoing basis, generally with interest. |
| e) | 2016 included in Other current liabilities on the Consolidated Balance Sheets ($536,000) and in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets ($8,000); 2015 included in Other deferred credits and other long-term liabilities on the Consolidated Balance Sheets. |
| (9) | Regulatory recovery occurs on a one-year lag basis through the labor loading process. |
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) | 2016 | 2015 | 2014 | |||||||||||||||||||||||||||||||||
| Before- Tax Amount |
Tax (Expense) or |
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: |
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| Net actuarial gain/(loss) |
$ | (22,770 | ) | $ | 8,652 | $ | (14,118 | ) | $ | (30,519 | ) | $ | 11,597 | $ | (18,922 | ) | $ | (173,646 | ) | $ | 65,985 | $ | (107,661 | ) | ||||||||||||
| Amortization of prior service cost |
1,335 | (507 | ) | 828 | 1,335 | (507 | ) | 828 | 355 | (135 | ) | 220 | ||||||||||||||||||||||||
| Amortization of net actuarial (gain)/loss |
27,066 | (10,285 | ) | 16,781 | 34,381 | (13,065 | ) | 21,316 | 23,656 | (8,989 | ) | 14,667 | ||||||||||||||||||||||||
| Prior service cost |
— | — | — | — | — | — | (6,661 | ) | 2,531 | (4,130 | ) | |||||||||||||||||||||||||
| Regulatory adjustment |
(5,584 | ) | 2,122 | (3,462 | ) | (5,646 | ) | 2,146 | (3,500 | ) | 140,308 | (53,317 | ) | 86,991 | ||||||||||||||||||||||
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| Pension plans other comprehensive income (loss) |
47 | (18 | ) | 29 | (449 | ) | 171 | (278 | ) | (15,988 | ) | 6,075 | (9,913 | ) | ||||||||||||||||||||||
| Forward-starting interest rate swaps (“FSIRS”) (designated hedging activities): |
||||||||||||||||||||||||||||||||||||
| Amounts reclassified into net income |
3,345 | (1,270 | ) | 2,075 | 3,344 | (1,271 | ) | 2,073 | 3,345 | (1,272 | ) | 2,073 | ||||||||||||||||||||||||
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| FSIRS other comprehensive income (loss) |
3,345 | (1,270 | ) | 2,075 | 3,344 | (1,271 | ) | 2,073 | 3,345 | (1,272 | ) | 2,073 | ||||||||||||||||||||||||
| Foreign currency translation adjustments: |
||||||||||||||||||||||||||||||||||||
| Translation adjustments |
161 | — | 161 | (1,954 | ) | — | (1,954 | ) | (659 | ) | — | (659 | ) | |||||||||||||||||||||||
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| Foreign currency other comprehensive income (loss) |
161 | — | 161 | (1,954 | ) | — | (1,954 | ) | (659 | ) | — | (659 | ) | |||||||||||||||||||||||
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| Total other comprehensive income (loss) |
$ | 3,553 | $ | (1,288 | ) | $ | 2,265 | $ | 941 | $ | (1,100 | ) | $ | (159 | ) | $ | (13,302 | ) | $ | 4,803 | $ | (8,499 | ) | |||||||||||||
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| (1) | Tax amounts are calculated using a 38% rate. Management 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, management 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. |
| Southwest Gas Corporation |
63 |
The estimated amounts that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year are summarized below (in thousands):
| Retirement plan net actuarial loss |
$ | 24,000 | ||
| SERP net actuarial loss |
1,500 | |||
| PBOP prior service cost |
1,300 |
Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, included in AOCI at December 31, 2016, 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 (4) |
After- Tax |
Before- Tax |
Tax (Expense) Benefit (4) |
After- Tax |
Before- Tax |
Tax (Expense) Benefit |
After- Tax |
AOCI | |||||||||||||||||||||||||||||||
| Beginning Balance AOCI December 31, 2015 |
$ | (57,660 | ) | $ | 21,911 | $ | (35,749 | ) | $ | (19,344 | ) | $ | 7,350 | $ | (11,994 | ) | $ | (2,525 | ) | $ | — | $ | (2,525 | ) | $ | (50,268 | ) | |||||||||||||
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| Net actuarial gain/(loss) |
(22,770 | ) | 8,652 | (14,118 | ) | — | — | — | — | — | — | (14,118 | ) | |||||||||||||||||||||||||||
| Translation adjustments |
— | — | — | — | — | — | 161 | — | 161 | 161 | ||||||||||||||||||||||||||||||
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| Other comprehensive income before reclassifications |
(22,770 | ) | 8,652 | (14,118 | ) | — | — | — | 161 | — | 161 | (13,957 | ) | |||||||||||||||||||||||||||
| FSIRS amounts reclassified from AOCI (1) |
— | — | — | 3,345 | (1,270 | ) | 2,075 | — | — | — | 2,075 | |||||||||||||||||||||||||||||
| Amortization of prior service cost (2) |
1,335 | (507 | ) | 828 | — | — | — | — | — | — | 828 | |||||||||||||||||||||||||||||
| Amortization of net actuarial loss (2) |
27,066 | (10,285 | ) | 16,781 | — | — | — | — | — | — | 16,781 | |||||||||||||||||||||||||||||
| Regulatory adjustment (3) |
(5,584 | ) | 2,122 | (3,462 | ) | — | — | — | — | — | — | (3,462 | ) | |||||||||||||||||||||||||||
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| Net current period other comprehensive income (loss) |
47 | (18 | ) | 29 | 3,345 | (1,270 | ) | 2,075 | 161 | — | 161 | 2,265 | ||||||||||||||||||||||||||||
| Less: Translation adjustment attributable to redeemable noncontrolling interest |
— | — | — | — | — | — | 5 | — | 5 | 5 | ||||||||||||||||||||||||||||||
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| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation |
47 | (18 | ) | 29 | 3,345 | (1,270 | ) | 2,075 | 156 | — | 156 | 2,260 | ||||||||||||||||||||||||||||
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| Ending Balance AOCI December 31, 2016 |
$ | (57,613 | ) | $ | 21,893 | $ | (35,720 | ) | $ | (15,999 | ) | $ | 6,080 | $ | (9,919 | ) | $ | (2,369 | ) | $ | — | $ | (2,369 | ) | $ | (48,008 | ) | |||||||||||||
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| (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). |
| (4) | Tax amounts are calculated using a 38% rate. |
| Southwest Gas Corporation |
64 |
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, 2016 and 2015:
Amounts Recognized in AOCI (Before Tax)
(Thousands of dollars)
| 2016 | 2015 | |||||||
| Net actuarial (loss) gain |
$ | (430,973 | ) | $ | (435,269 | ) | ||
| Prior service cost |
(5,703 | ) | (7,038 | ) | ||||
| Less: amount recognized in regulatory assets |
379,063 | 384,647 | ||||||
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| Recognized in AOCI |
$ | (57,613 | ) | $ | (57,660 | ) | ||
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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 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 the twelve months ended December 31, 2016, the Company sold no shares through the continuous equity offering program. Since the start of the program in March 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds of $35,167,584, net of $355,228 in agent commissions. Effective January 2017, no further shares will be issued under this registration statement.
During 2016, the Company issued approximately 105,000 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, 2016 and December 31, 2015 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
| Southwest Gas Corporation |
65 |
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, | 2016 | 2015 | ||||||||||||||
| Carrying Amount |
Market Value |
Carrying Amount |
Market Value |
|||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Debentures: |
||||||||||||||||
| Notes, 4.45%, due 2020 |
$ | 125,000 | $ | 129,703 | $ | 125,000 | $ | 130,273 | ||||||||
| Notes, 6.1%, due 2041 |
125,000 | 149,734 | 125,000 | 141,581 | ||||||||||||
| Notes, 3.875%, due 2022 |
250,000 | 254,900 | 250,000 | 253,600 | ||||||||||||
| Notes, 4.875%, due 2043 |
250,000 | 266,793 | 250,000 | 251,483 | ||||||||||||
| Notes, 3.8%, due 2046 |
300,000 | 283,029 | — | — | ||||||||||||
| 8% Series, due 2026 |
75,000 | 94,691 | 75,000 | 97,035 | ||||||||||||
| Medium-term notes, 7.59% series, due 2017 |
25,000 | 25,040 | 25,000 | 26,253 | ||||||||||||
| Medium-term notes, 7.78% series, due 2022 |
25,000 | 29,290 | 25,000 | 29,855 | ||||||||||||
| Medium-term notes, 7.92% series, due 2027 |
25,000 | 31,905 | 25,000 | 31,890 | ||||||||||||
| Medium-term notes, 6.76% series, due 2027 |
7,500 | 8,769 | 7,500 | 8,684 | ||||||||||||
| Unamortized discount and debt issuance costs |
(9,931 | ) | (6,137 | ) | ||||||||||||
|
|
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|
|||||||||||||
| 1,197,569 | 901,363 | |||||||||||||||
|
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|
|
|||||||||||||
| Revolving credit facility and commercial paper |
5,000 | 5,000 | 150,000 | 150,000 | ||||||||||||
|
|
|
|
|
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| Industrial development revenue bonds: |
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| 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: |
||||||||||||||||
| 4.85% 2005 Series A, due 2035 |
— | — | 100,000 | 100,452 | ||||||||||||
| 4.75% 2006 Series A, due 2036 |
— | — | 24,855 | 25,130 | ||||||||||||
| Unamortized discount and debt issuance costs |
(2,489 | ) | (3,946 | ) | ||||||||||||
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|||||||||||||
| 197,511 | 320,909 | |||||||||||||||
|
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|
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| Centuri term loan facility |
106,700 | 106,819 | 112,571 | 112,665 | ||||||||||||
| Unamortized debt issuance costs |
(516 | ) | (692 | ) | ||||||||||||
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| 106,184 | 111,879 | |||||||||||||||
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| Centuri secured revolving credit facility |
41,185 | 41,292 | 60,627 | 60,724 | ||||||||||||
| Centuri other debt obligations |
52,635 | 52,840 | 25,901 | 26,059 | ||||||||||||
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| 1,600,084 | 1,570,679 | |||||||||||||||
| Less: current maturities |
(50,101 | ) | (19,475 | ) | ||||||||||||
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| Long-term debt, less current maturities |
$ | 1,549,983 | $ | 1,551,204 | ||||||||||||
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| Southwest Gas Corporation |
66 |
In March 2016, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020, but was extended to March 2021. 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, 2016, 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, 2016, $5 million was outstanding on the long-term portion of the credit facility, none of which was in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 5.21% at December 31, 2016. Borrowings under the credit facility ranged from none at various times throughout 2016 to a high of $230 million during the third quarter of 2016. With regard to the short-term portion of the credit facility, there were no borrowings outstanding at December 31, 2016 and $18 million outstanding at December 31, 2015. (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, 2016, and as noted above, no borrowings were outstanding under the commercial paper program.
Southwest redeemed its $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) at par with accrued interest in July 2016. In September 2016, Southwest redeemed its $24.9 million 2006 Series A 4.75% fixed-rate IDRBs (originally due in 2036) at par with accrued interest. In January 2017, subsequent to the most recent balance sheet date, the $25 million 7.59% medium-term notes were repaid at maturity, using available cash on hand.
In September 2016, Southwest issued $300 million in 3.8% Senior Notes at a discount of 0.302%. The notes will mature in September 2046. A portion of the net proceeds were used to temporarily pay down amounts then outstanding under the credit facility. The remaining net proceeds were used for general corporate purposes.
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. 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, 2016 totaled $445 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 their consolidated leverage ratio. The commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the revolving credit facility ranged from
| Southwest Gas Corporation |
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a low of $36.2 million during February 2016 to a high of $83.2 million during July 2016. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.63% at December 31, 2016.
The effective interest rates on Southwest’s variable-rate IDRBs are included in the table below:
| December 31, 2016 |
December 31, 2015 |
|||||||
| 2003 Series A |
1.47 | % | 0.87 | % | ||||
| 2008 Series A |
1.53 | % | 0.87 | % | ||||
| 2009 Series A |
1.43 | % | 0.75 | % | ||||
| Tax-exempt Series A |
1.51 | % | 0.81 | % | ||||
In Nevada, interest fluctuations due to changing interest rates on Southwest’s 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.
None of Southwest’s debt instruments have credit triggers or other clauses that result in default if bond ratings are lowered by rating agencies. Certain 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, 2016, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, at December 31, 2016, approximately $2.3 billion in additional debt could be issued while still meeting the leverage ratio requirement. Relating to the minimum net worth requirement, as of December 31, 2016, there is at least $1.1 billion of cushion in equity.
Certain Centuri debt instruments also have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $145 million in additional debt and meet the leverage ratio requirement. Centuri has at least $21 million of cushion relating to the minimum fixed charge ratio coverage requirement.
Estimated maturities of long-term debt for the next five years are (in thousands):
| 2017 | $ | 50,101 | ||
| 2018 | 24,082 | |||
| 2019 | 134,534 | |||
| 2020 | 134,452 | |||
| 2021 | 7,815 |
Note 8 – Short-Term Debt
As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2021, of which $150 million has been designated by management for working capital purposes. Southwest had no short-term borrowings outstanding at December 31, 2016 and $18 million in short-term borrowings outstanding 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
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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, results of operations, or cash flows.
Southwest maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, Southwest 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 2016 to July 2017, 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, Southwest 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, Southwest will make an accrual, as necessary.
Note 10 – Pension and Other Postretirement Benefits
An Employees’ Investment Plan is offered to eligible employees of Southwest through deduction of a percentage of base compensation, subject to IRS limitations. The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock. One-half of amounts deferred by employees are matched, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. The cost of the plan is disclosed below (in thousands):
| 2016 | 2015 | 2014 | ||||||||||
| Employee Investment Plan cost |
$ | 4,976 | $ | 5,072 | $ | 4,816 | ||||||
Centuri has a separate plan, the cost and liability of which are not significant.
A deferred compensation plan is offered to 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. One-half of amounts deferred by officers are matched, 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.
A noncontributory qualified retirement plan with defined benefits covering substantially all Southwest employees is available in addition to a separate unfunded supplemental executive retirement plan (“SERP”) which is limited to officers. Postretirement benefits other than pensions (“PBOP”) are provided to qualified retirees for health care, dental, and life insurance benefits.
The overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, are recognized in the 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.
A regulatory asset has been established 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.
| Southwest Gas Corporation |
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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, manage funded status risk 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, 2016, the percentage ranges of the target portfolio are:
| Type of Investment | Percentage Range | |||
| Equity securities |
63 to 67 | |||
| Debt securities |
33 to 37 | |||
| Other |
up to 1 | |||
The qualified retirement plan invests the majority of its plan assets in common collective trusts which includes a well-diversified portfolio of domestic and international equity securities and fixed income securities, which are managed by a professional investment manager appointed by the Company. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the specific guidelines prescribed by the Company through the plan’s investment policy statement. In 2016, the Company adopted a liability driven investment (“LDI”) strategy for part of the portfolio, a form of investing designed to better match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the pension plan liability. The implementation of the LDI strategy will be phased in over time by using a glide path. The glide path is designed to increase the allocation of the plan’s assets to fixed income securities, as the funded status of the plan increases, in order to more closely match the duration of the plan assets to that of the plan liability.
During the third quarter of 2016, qualifying term-vested participants were offered a lump-sum present value payout of their pensions. The offer was primarily intended to reduce insurance and ongoing maintenance costs associated with qualifying participant balances. About one-half of the approximate 800 participants subject to the offer accepted the offer, resulting in an approximate $30 million payment from pension assets paid in the fourth quarter of 2016.
In August 2016, Russell Investments Trust Company (“Russell”), an outside professional investment manager as defined in Section 3(38) of ERISA, was engaged as a fiduciary of the pension plan. Russell has full discretionary authority to direct the investment of the pension plan’s assets within the guidelines prescribed by the pension plan’s investment policy statement. The change, related to managing pension plan assets, has no impact on retirement benefit calculations for pension plan participants, and was approved by the Board of Directors of the Company.
Pension plan assets are held in a Master Trust. Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of the obligations to the pension plan’s beneficiaries. To meet this objective, the pension plan assets are managed by an
| Southwest Gas Corporation |
70 |
outside adviser using a portfolio strategy that will provide liquidity to meet the plan’s benefit payment obligations. The pension plan funding policy is in compliance with the federal government’s funding requirements.
Pension costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan. In determining the discount rate, management 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.
There was no change in the discount rate between years. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase also remained the same (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, 2016 | December 31, 2015 | |||||||
| Discount rate |
4.50 | % | 4.50 | % | ||||
| Weighted-average rate of compensation increase |
3.25 | % | 3.25 | % | ||||
| Asset return assumption |
7.00 | % | 7.25 | % | ||||
Pension expense for 2017 is estimated to be similar to that experienced in 2016. 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.
| 2016 | 2015 | |||||||||||||||||||||||
| 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) |
$ | 1,044,817 | $ | 42,720 | $ | 72,632 | $ | 1,060,240 | $ | 41,176 | $ | 72,202 | ||||||||||||
| Service cost |
22,833 | 331 | 1,499 | 25,123 | 320 | 1,641 | ||||||||||||||||||
| Interest cost |
46,027 | 1,859 | 3,180 | 44,229 | 1,695 | 2,999 | ||||||||||||||||||
| Actuarial loss (gain) |
8,550 | 1,347 | (2,060 | ) | (44,553 | ) | 2,322 | (3,251 | ) | |||||||||||||||
| Benefits paid |
(73,874 | ) | (2,946 | ) | (1,386 | ) | (40,222 | ) | (2,793 | ) | (959 | ) | ||||||||||||
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| Benefit obligation at end of year (PBO/PBO/APBO) |
1,048,353 | 43,311 | 73,865 | 1,044,817 | 42,720 | 72,632 | ||||||||||||||||||
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| Change in plan assets |
||||||||||||||||||||||||
| Market value of plan assets at beginning of year |
736,880 | — | 43,584 | 754,796 | — | 44,892 | ||||||||||||||||||
| Actual return on plan assets |
39,956 | — | 4,818 | (13,694 | ) | — | (1,034 | ) | ||||||||||||||||
| Employer contributions |
36,000 | 2,946 | — | 36,000 | 2,793 | — | ||||||||||||||||||
| Benefits paid |
(73,874 | ) | (2,946 | ) | (289 | ) | (40,222 | ) | (2,793 | ) | (274 | ) | ||||||||||||
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| Market value of plan assets at end of year |
738,962 | — | 48,113 | 736,880 | — | 43,584 | ||||||||||||||||||
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| Funded status at year end |
$ | (309,391 | ) | $ | (43,311 | ) | $ | (25,752 | ) | $ | (307,937 | ) | $ | (42,720 | ) | $ | (29,048 | ) | ||||||
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| Weighted-average assumptions (benefit obligation) |
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| Discount rate |
4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | 4.50 | % | ||||||||||||
| Weighted-average rate of compensation increase |
3.25 | % | 3.25 | % | N/A | 3.25 | % | 3.25 | % | N/A | ||||||||||||||
Estimated funding for the plans above during calendar year 2017 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, 2016 | December 31, 2015 | |||||||
| Retirement plan |
$ | 939,002 | $ | 922,992 | ||||
| SERP |
40,852 | 39,270 | ||||||
| Southwest Gas Corporation |
72 |
Benefits expected to be paid for pension, SERP, and PBOP over the next 10 years are as follows (in millions):
| 2017 | 2018 | 2019 | 2020 | 2021 | 2022-2026 | |||||||||||||||||||
| Pension |
$ | 48.6 | $ | 50.1 | $ | 51.5 | $ | 53.2 | $ | 55.1 | $ | 294.2 | ||||||||||||
| SERP |
2.9 | 2.9 | 2.9 | 2.9 | 2.9 | 14.4 | ||||||||||||||||||
| PBOP |
4.1 | 4.3 | 4.4 | 4.5 | 4.5 | 20.6 | ||||||||||||||||||
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% declining to 4.5%. Fixed contributions are made for health care benefits of employees who retire after 1988, but Southwest 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 | ||||||||||||||||||||||||||||||||||
| 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | ||||||||||||||||||||||||||||
| (Thousands of dollars) | ||||||||||||||||||||||||||||||||||||
| Service cost |
$ | 22,833 | $ | 25,123 | $ | 21,360 | $ | 331 | $ | 320 | $ | 292 | $ | 1,499 | $ | 1,641 | $ | 1,101 | ||||||||||||||||||
| Interest cost |
46,027 | 44,229 | 43,440 | 1,859 | 1,695 | 1,745 | 3,180 | 2,999 | 2,829 | |||||||||||||||||||||||||||
| Expected return on plan assets |
(56,558 | ) | (57,808 | ) | (53,342 | ) | — | — | — | (3,149 | ) | (3,464 | ) | (3,264 | ) | |||||||||||||||||||||
| Amortization of prior service cost |
— | — | — | — | — | — | 1,335 | 1,335 | 355 | |||||||||||||||||||||||||||
| Amortization of net actuarial loss |
25,266 | 32,743 | 22,873 | 1,383 | 1,293 | 783 | 417 | 345 | — | |||||||||||||||||||||||||||
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| Net periodic benefit cost |
$ | 37,568 | $ | 44,287 | $ | 34,331 | $ | 3,573 | $ | 3,308 | $ | 2,820 | $ | 3,282 | $ | 2,856 | $ | 1,021 | ||||||||||||||||||
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| Weighted-average assumptions (net benefit cost) |
||||||||||||||||||||||||||||||||||||
| Discount rate |
4.50 | % | 4.25 | % | 5.00 | % | 4.50 | % | 4.25 | % | 5.00 | % | 4.50 | % | 4.25 | % | 5.00 | % | ||||||||||||||||||
| Expected return on plan assets |
7.25 | % | 7.75 | % | 7.75 | % | N/A | N/A | N/A | 7.25 | % | 7.75 | % | 7.75 | % | |||||||||||||||||||||
| Weighted-average rate of compensation increase |
3.25 | % | 2.75 | % | 3.25 | % | 3.25 | % | 2.75 | % | 3.25 | % | N/A | N/A | N/A | |||||||||||||||||||||
| Southwest Gas Corporation |
73 |
Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
| 2016 | 2015 | 2014 | ||||||||||||||||||||||||||||||||||||||||||||||
| 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) |
$ | 22,770 | $ | 25,153 | $ | 1,347 | $ | (3,730 | ) | $ | 30,519 | $ | 26,949 | $ | 2,322 | $ | 1,248 | $ | 173,646 | $ | 163,215 | $ | 5,460 | $ | 4,971 | |||||||||||||||||||||||
| Amortization of prior service cost (b) |
(1,335 | ) | — | — | (1,335 | ) | (1,335 | ) | — | — | (1,335 | ) | (355 | ) | — | — | (355 | ) | ||||||||||||||||||||||||||||||
| Amortization of net actuarial loss (b) |
(27,066 | ) | (25,266 | ) | (1,383 | ) | (417 | ) | (34,381 | ) | (32,743 | ) | (1,293 | ) | (345 | ) | (23,656 | ) | (22,872 | ) | (784 | ) | — | |||||||||||||||||||||||||
| Prior service cost |
— | — | — | — | — | — | — | — | 6,661 | — | — | 6,661 | ||||||||||||||||||||||||||||||||||||
| Regulatory adjustment |
5,584 | 102 | — | 5,482 | 5,646 | 5,214 | — | 432 | (140,308 | ) | (129,031 | ) | — | (11,277 | ) | |||||||||||||||||||||||||||||||||
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|
|||||||||||||||||||||||||
| Recognized in other comprehensive (income) loss |
(47 | ) | (11 | ) | (36 | ) | — | 449 | (580 | ) | 1,029 | — | 15,988 | 11,312 | 4,676 | — | ||||||||||||||||||||||||||||||||
| Net periodic benefit costs recognized in net income |
44,423 | 37,568 | 3,573 | 3,282 | 50,451 | 44,287 | 3,308 | 2,856 | 38,172 | 34,331 | 2,820 | 1,021 | ||||||||||||||||||||||||||||||||||||
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|||||||||||||||||||||||||
| Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss |
$ | 44,376 | $ | 37,557 | $ | 3,537 | $ | 3,282 | $ | 50,900 | $ | 43,707 | $ | 4,337 | $ | 2,856 | $ | 54,160 | $ | 45,643 | $ | 7,496 | $ | 1,021 | ||||||||||||||||||||||||
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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.
| Southwest Gas Corporation |
74 |
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, 2016 and December 31, 2015. The change in the types of pension investment holdings between years is due to the engagement of Russell and the subsequent transition of pension investments to Russell funds. The transition efforts consolidated the majority of the pension plan investments into private commingled equity and fixed income funds. The SERP has no assets.
| December 31, 2016 | December 31, 2015 | |||||||||||||||||||||||
| 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 | ||||||||||||
| Capital equipment |
— | — | — | 533 | 16 | 549 | ||||||||||||||||||
| Chemicals/materials |
— | — | — | 3,304 | 98 | 3,402 | ||||||||||||||||||
| Consumer goods |
— | — | — | 41,035 | 1,221 | 42,256 | ||||||||||||||||||
| Energy and mining |
— | — | — | 11,066 | 329 | 11,395 | ||||||||||||||||||
| Finance/insurance |
— | — | — | 29,957 | 892 | 30,849 | ||||||||||||||||||
| Healthcare |
— | — | — | 37,930 | 1,129 | 39,059 | ||||||||||||||||||
| Information technology |
— | — | — | 29,229 | 870 | 30,099 | ||||||||||||||||||
| Services |
— | — | — | 12,341 | 367 | 12,708 | ||||||||||||||||||
| Telecommunications/internet/media |
— | — | — | 25,883 | 770 | 26,653 | ||||||||||||||||||
| Other |
— | — | — | 9,043 | 269 | 9,312 | ||||||||||||||||||
| Real estate investment trusts |
— | — | — | 5,010 | 149 | 5,159 | ||||||||||||||||||
| Mutual funds |
— | 24,922 | 24,922 | 87,483 | 23,985 | 111,468 | ||||||||||||||||||
| Government fixed income securities |
— | — | — | 33,482 | 996 | 34,478 | ||||||||||||||||||
| Futures contracts |
— | — | — | (7 | ) | — | (7 | ) | ||||||||||||||||
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| Total Level 1 Assets (1) |
$ | — | $ | 24,922 | $ | 24,922 | $ | 333,310 | $ | 31,300 | $ | 364,610 | ||||||||||||
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| Level 2 – Significant other observable inputs |
||||||||||||||||||||||||
| Private commingled equity funds (2) |
||||||||||||||||||||||||
| International |
$ | 290,668 | $ | 9,140 | $ | 299,808 | $ | — | $ | — | $ | — | ||||||||||||
| Large and medium capitalization |
121,434 | 3,819 | 125,253 | — | — | — | ||||||||||||||||||
| Small capitalization |
25,947 | 816 | 26,763 | — | — | — | ||||||||||||||||||
| Emerging markets |
45,309 | 1,424 | 46,733 | — | — | — | ||||||||||||||||||
| Private commingled fixed income funds (3) |
||||||||||||||||||||||||
| U.S. corporate bonds |
161,086 | 5,066 | 166,152 | — | — | — | ||||||||||||||||||
| U.S. debt market long duration |
77,349 | 2,432 | 79,781 | — | — | — | ||||||||||||||||||
| U.S. Treasury securities |
8,665 | 272 | 8,937 | — | — | — | ||||||||||||||||||
| Pooled funds and mutual funds |
4,889 | 216 | 5,105 | 14,808 | 796 | 15,604 | ||||||||||||||||||
| Government fixed income and mortgage backed securities |
167 | 5 | 172 | 49,571 | 1,475 | 51,046 | ||||||||||||||||||
| Corporate fixed income securities |
||||||||||||||||||||||||
| Asset-backed and mortgage-backed |
— | — | — | 23,542 | 701 | 24,243 | ||||||||||||||||||
| Banking |
— | — | — | 20,857 | 621 | 21,478 | ||||||||||||||||||
| Insurance |
— | — | — | 4,896 | 146 | 5,042 | ||||||||||||||||||
| Utilities |
— | — | — | 3,826 | 114 | 3,940 | ||||||||||||||||||
| Other |
— | — | — | 30,995 | 922 | 31,917 | ||||||||||||||||||
| Real estate investment trusts |
— | — | — | 1,949 | 58 | 2,007 | ||||||||||||||||||
| State and local obligations |
— | — | — | 950 | 28 | 978 | ||||||||||||||||||
| Preferred securities |
— | — | — | 554 | 17 | 571 | ||||||||||||||||||
| Convertible securities |
— | — | — | 196 | 6 | 202 | ||||||||||||||||||
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|
|||||||||||||
| Total Level 2 assets (4) |
$ | 735,514 | $ | 23,190 | $ | 758,704 | $ | 152,144 | $ | 4,884 | $ | 157,028 | ||||||||||||
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| Total Plan assets at fair value |
$ | 735,514 | $ | 48,112 | $ | 783,626 | $ | 485,454 | $ | 36,184 | $ | 521,638 | ||||||||||||
| Commingled equity funds (5) |
— | — | — | 250,511 | 7,455 | 257,966 | ||||||||||||||||||
| Insurance company general account contracts (6) |
3,448 | — | 3,448 | 3,719 | — | 3,719 | ||||||||||||||||||
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|
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| Total Plan assets (7) |
$ | 738,962 | $ | 48,112 | $ | 787,074 | $ | 739,684 | $ | 43,639 | $ | 783,323 | ||||||||||||
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| Southwest Gas Corporation |
75 |
| (1) | 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 fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income. Currently, this balanced fund is the only mutual fund in which the Plan invests. |
In the prior year, Level 1 also included Common stock, Real Estate Investment Trusts, Mutual funds, and U.S. Government securities listed or regularly traded on a national securities exchange and were valued at quoted market prices as of the last business day of the calendar year.
| (2) | The private commingled equity funds include common collective trusts that invest in a diversified portfolio of domestic and international securities regularly traded on securities exchanges. These funds are shown in the above table at net asset value (“NAV”), which is the value of securities in the fund less the amount of any liabilities outstanding. Investment strategies employed by the funds include: |
| • | Domestic equities |
| • | International developed countries equities |
| • | Emerging markets equities |
Shares in the private equity commingled funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item.
Two funds are classified as international funds. One invests in international financial markets, primarily those of developed economies in Europe and the Pacific Basin. The fund invests primarily in equity securities issued by foreign corporations, but may invest in other securities perceived as offering attractive investment return opportunities. The other provides diversified exposure to global equity markets. The fund seeks to provide long-term capital growth by investing primarily in securities listed on the major developed equity markets of the United States, Europe, and Asia, as well as within those listed on emerging country equity markets on a tactical basis.
The large and medium capitalization fund is designed to track the performance of the large and medium capitalization companies contained in the index, which represents approximately 90% of the market capitalization of the United States stock market.
The small capitalization fund is designed to provide maximum long-term appreciation through investments that are well diversified by industry.
The emerging markets fund was developed to invest in emerging market equities worldwide. The purposes of the fund’s operations, “emerging market countries” include every country in the world except the developed markets of the United States, Canada, Japan, Australia, New Zealand, Hong Kong and Singapore, and most
| Southwest Gas Corporation |
76 |
countries located in Western Europe. Fund investments are made directly in each country or, where direct investment is inefficient or prohibited, through appropriate financial instruments or participation in commingled funds.
| (3) | The private commingled fixed income funds include domestic fixed income securities. These funds are shown in the above table at NAV. Shares in the private commingled fixed equity funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item. |
The U.S. corporate bond fund seeks to provide high quality, mostly corporate bond-based exposure to fixed income securities which closely match those found in discount curves used to value United States pension liabilities.
The United States debt market long duration fund provides participation in the full spectrum of investment opportunities in primarily United States debt markets with longer maturities. The fund seeks to offer effective diversification against equities, take advantage of market trading opportunities, and provide a competitive rate of return on assets. The fund’s current duration is close to 14 years.
The United States Treasuries securities funds seeks to replicate the risk and return characteristics of the Barclays Treasury U.S. Separate Trading of Registered Interest and Principal of Securities (“STRIPS”) 28-29 Years Index with minimum tracking error.
| (4) | With the exception of items (2) and (3), which are discussed in detail above, the current year Level 2 assets consist mainly of pooled funds and mutual funds. These funds are collective short-term funds that invest in Treasury bills and money market funds and are used as a temporary cash repository. |
In the prior year, the fair value of the Level 2 investments in debt securities with remaining maturities of one year or more was 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.
| (5) | In the prior year, the commingled equity funds included 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 included: |
| • | 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 were redeemed varied among the funds; the notice required ranged from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds required the payment of a minimal impact fee to be applied to redemptions and
| Southwest Gas Corporation |
77 |
subscriptions of $5 million or greater; the relative fee diminished the greater the transaction. Other such funds imposed fees to recover direct costs incurred by the fund at redemption, but were indeterminable prior to redemption.
| (6) | 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. |
| (7) | In the prior year, the assets in the above table exceeded 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), 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, 2016, two stock-based compensation plans existed: a performance share stock plan which includes a cash award, and a restricted stock/unit plan. All previous grants under the stock option plan expired in 2016. 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):
| 2016 | 2015 | 2014 | ||||||||||
| Stock-based compensation plan expense, net of related tax benefits |
$ | 7,185 | $ | 7,278 | $ | 8,130 | ||||||
| Stock-based compensation plan related tax benefits |
4,404 | 4,461 | 4,983 | |||||||||
Under the option plan, options to purchase shares of common stock at a stated exercise price were previously granted 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 the Company’s common stock on the date of grant and a maximum term of ten years. The final options were exercised in 2016.
The following tables summarize the stock option plan activity and related information (thousands of options):
| 2016 | 2015 | 2014 | ||||||||||||||||||||||
| 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 |
17 | $ | 31.64 | 36 | $ | 28.97 | 52 | $ | 27.57 | |||||||||||||||
| Exercised during the year |
(17 | ) | 31.64 | (19 | ) | 26.69 | (16 | ) | 24.31 | |||||||||||||||
| Forfeited or expired during the year |
— | — | — | — | — | — | ||||||||||||||||||
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|
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| Outstanding and exercisable at year end |
— | N/A | 17 | $ | 31.64 | 36 | $ | 28.97 | ||||||||||||||||
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| Southwest Gas Corporation |
78 |
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):
| 2016 | 2015 | 2014 | ||||||||||
| Outstanding and exercisable |
$ | — | $ | 394 | $ | 1,194 | ||||||
| Exercised |
554 | 590 | 451 | |||||||||
| December 31, 2016 | December 31, 2015 | December 31, 2014 | ||||||||||
| Market value of Company stock |
$ | 76.62 | $ | 55.16 | $ | 61.81 | ||||||
During 2016, $735,000 in cash was received from the exercise of options with a corresponding tax benefit of $205,000, which was recorded in additional paid-in capital.
Under the performance share stock plan, performance shares may be issued to encourage key employees to remain as employees 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.
Restricted stock/units under the restricted stock/unit plan are issued to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance. 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 currently 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, 2016 (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 |
197 | $ | 50.63 | 228 | $ | 44.36 | ||||||||||
| Granted |
44 | 59.05 | 73 | 60.39 | ||||||||||||
| Dividends |
5 | 6 | ||||||||||||||
| Forfeited or expired |
— | — | — | — | ||||||||||||
| Vested and issued* |
(78 | ) | 41.82 | (45 | ) | 51.98 | ||||||||||
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|
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| Nonvested/unissued at December 31, 2016 |
168 | $ | 55.62 | 262 | $ | 46.41 | ||||||||||
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|
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| * | Includes shares for retiree payouts and those converted for taxes. |
The weighted average grant date fair value of performance shares and restricted stock/units granted in 2015 and 2014 was $63.09 and $53.73, respectively.
As of December 31, 2016, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million.
| Southwest Gas Corporation |
79 |
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, | 2016 | 2015 | 2014 | |||||||||
| U.S. |
$ | 218,810 | $ | 221,660 | $ | 221,471 | ||||||
| Foreign |
12,713 | (2,328 | ) | (1,950 | ) | |||||||
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|
|
|
|||||||
| Total income before income taxes |
$ | 231,523 | $ | 219,332 | $ | 219,521 | ||||||
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Income tax expense (benefit) consists of the following (thousands of dollars):
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Current: |
||||||||||||
| Federal |
$ | 541 | $ | 21,321 | $ | 1,739 | ||||||
| State |
5,748 | 9,899 | 5,073 | |||||||||
| Foreign |
4,298 | 650 | 2,193 | |||||||||
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|
|
|||||||
| 10,587 | 31,870 | 9,005 | ||||||||||
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|
|||||||
| Deferred: |
||||||||||||
| Federal |
68,270 | 51,132 | 71,439 | |||||||||
| State |
140 | (2,574 | ) | 614 | ||||||||
| Foreign |
(529 | ) | (526 | ) | (2,685 | ) | ||||||
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|
|
|||||||
| 67,881 | 48,032 | 69,368 | ||||||||||
|
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|
|||||||
| Total income tax expense |
$ | 78,468 | $ | 79,902 | $ | 78,373 | ||||||
|
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|
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Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| Deferred federal and state: |
||||||||||||
| Property-related items |
$ | 76,217 | $ | 65,931 | $ | 52,814 | ||||||
| Purchased gas cost adjustments |
361 | (32,993 | ) | 15,049 | ||||||||
| Employee benefits |
(1,327 | ) | 623 | 109 | ||||||||
| All other deferred |
(6,532 | ) | 15,332 | 2,257 | ||||||||
|
|
|
|
|
|
|
|||||||
| Total deferred federal and state |
68,719 | 48,893 | 70,229 | |||||||||
| Deferred ITC, net |
(838 | ) | (861 | ) | (861 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total deferred income tax expense |
$ | 67,881 | $ | 48,032 | $ | 69,368 | ||||||
|
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| Southwest Gas Corporation |
80 |
A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2014, 2015, and 2016 (and the sources of these differences and the effect of each) are summarized as follows:
| Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||
| U.S. federal statutory income tax rate |
35.0 | % | 35.0 | % | 35.0 | % | ||||||
| Net state taxes |
1.4 | 1.8 | 1.9 | |||||||||
| Property-related items |
— | 0.1 | 0.1 | |||||||||
| Tax credits |
(0.4 | ) | (0.4 | ) | (0.5 | ) | ||||||
| Company owned life insurance |
(1.2 | ) | 0.1 | (1.0 | ) | |||||||
| All other differences |
(0.9 | ) | (0.2 | ) | 0.2 | |||||||
|
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|
|
|||||||
| Consolidated effective income tax rate |
33.9 | % | 36.4 | % | 35.7 | % | ||||||
|
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|
|
|
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Deferred tax assets and liabilities consist of the following (thousands of dollars):
| December 31, | 2016 | 2015 | ||||||
| Deferred tax assets: |
||||||||
| Deferred income taxes for future amortization of ITC |
$ | 1,094 | $ | 1,614 | ||||
| Employee benefits |
38,231 | 36,923 | ||||||
| Alternative minimum tax credit |
4,827 | 4,809 | ||||||
| Net operating losses and credits |
1,204 | 868 | ||||||
| Interest rate swap |
6,080 | 7,351 | ||||||
| Other |
18,415 | 24,636 | ||||||
| Valuation allowance |
(495 | ) | (499 | ) | ||||
|
|
|
|
|
|||||
| 69,356 | 75,702 | |||||||
|
|
|
|
|
|||||
| Deferred tax liabilities: |
||||||||
| Property-related items, including accelerated depreciation |
872,136 | 794,850 | ||||||
| Regulatory balancing accounts |
1,104 | 743 | ||||||
| Unamortized ITC |
1,710 | 2,549 | ||||||
| Debt-related costs |
5,712 | 5,497 | ||||||
| Intangibles |
8,803 | 9,547 | ||||||
| Other |
19,256 | 31,533 | ||||||
|
|
|
|
|
|||||
| 908,721 | 844,719 | |||||||
|
|
|
|
|
|||||
| Net noncurrent deferred tax liabilities |
$ | 839,365 | $ | 769,017 | ||||
|
|
|
|
|
|||||
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 2012.
At December 31, 2016, the Company has U.S. federal net capital loss carryforwards of $278,000, which begin to expire in 2017. At December 31, 2016, the Company has an income tax net operating loss carryforward related to Canadian operations of $4.5 million which begins to expire in 2032.
As of December 31, 2016, the Company has approximately $5 million of undistributed foreign earnings. However, management intends to permanently reinvest any future foreign earnings in Canada.
| Southwest Gas Corporation |
81 |
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (thousands of dollars):
| 2016 | 2015 | |||||||
| Unrecognized tax benefits at beginning of year |
$ | 296 | $ | 305 | ||||
| Gross increases – tax positions in prior period |
897 | — | ||||||
| Gross decreases – tax positions in prior period |
— | (9 | ) | |||||
| Gross increases – current period tax positions |
38 | — | ||||||
| Gross decreases – current period tax positions |
— | — | ||||||
| Settlements |
— | — | ||||||
| Lapse in statute of limitations |
— | — | ||||||
|
|
|
|
|
|||||
| Unrecognized tax benefits at end of year |
$ | 1,231 | $ | 296 | ||||
|
|
|
|
|
|||||
In assessing whether uncertain tax positions should be recognized in its financial statements, management 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, management 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, management 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. Unrecognized tax benefits are recognized 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. Measurement of 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 $935,000 at December 31, 2016. 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 2016, 2015, and 2014.
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. Management expects the IRS to issue natural gas industry guidance that 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, management expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.
| Southwest Gas Corporation |
82 |
Note 13 – Derivatives and Fair Value Measurements
Derivatives. In managing its natural gas supply portfolios, Southwest has historically entered into fixed- and variable-price contracts, which qualify as derivatives. Additionally, Southwest utilizes fixed-for-floating swap contracts (“Swaps”) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business, and are exempt from fair value reporting. The variable-price contracts have no significant market value. The Swaps are recorded at fair value.
The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (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 2017 through March 2019. 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, 2016 | December 31, 2015 | |||||||
| Contract notional amounts |
10,543 | 7,407 | ||||||
|
|
|
|
|
|||||
Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.
The following table sets forth the gains and (losses) recognized on Southwest’s Swaps (derivatives) for the years ended December 31, 2016, 2015, and 2014 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 |
2016 | 2015 | 2014 | ||||||||||||||||
| Swaps |
Net cost of gas sold | $ | 5,006 | $ | (7,598 | ) | $ | (2,363 | ) | |||||||||||
| Swaps |
Net cost of gas sold | (5,006 | )* | 7,598 | * | 2,363 | * | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| 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, and the second, in March 2012. Losses on both FSIRS are being amortized over ten-year periods from Accumulated other comprehensive income (loss) into interest expense.
| Southwest Gas Corporation |
83 |
The following table sets forth the fair values of the Swaps and their location in the Consolidated Balance Sheets (thousands of dollars):
Fair values of derivatives not designated as hedging instruments:
| December 31, 2016 Instrument |
Balance Sheet Location | Asset Derivatives |
Liability Derivatives |
Net Total |
||||||||||||||||
| Swaps |
Deferred charges and other assets | $ | 899 | $ | (54 | ) | $ | 845 | ||||||||||||
| Swaps |
Prepaids and other current assets | 3,551 | (19 | ) | 3,532 | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| Total |
$ | 4,450 | $ | (73 | ) | $ | 4,377 | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| 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 | ) | ||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
The estimated fair values of the natural gas derivatives were determined using future natural gas index prices (as more fully described below). Master netting arrangements exist with each counterparty that provide for the net settlement (in the settlement month) of all contracts through a single payment. As applicable, management has elected to reflect the net amounts in its balance sheets. No outstanding collateral associated with the Swaps existed during any period presented in the above table.
Pursuant to regulatory deferral accounting treatment for rate-regulated entities, unrealized gains and losses in fair value of the Swaps are recorded as a regulatory asset and/or liability. When the Swaps mature, any prior positions held are reversed and the settled position is recorded 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 presents the amounts paid to and received from counterparties for settlements of matured Swaps.
| Year ended December 31, 2016 |
Year ended December 31, 2015 |
Year ended December 31, 2014 |
||||||||||
| (Thousands of dollars) | ||||||||||||
| Paid to counterparties |
$ | 5,583 | $ | 7,537 | $ | 829 | ||||||
|
|
|
|
|
|
|
|||||||
| Received from counterparties |
$ | 726 | $ | — | $ | 4,713 | ||||||
|
|
|
|
|
|
|
|||||||
| Southwest Gas Corporation |
84 |
The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the Consolidated Balance Sheets (thousands of dollars).
| December 31, 2016 Instrument |
Balance Sheet Location | Net Total | ||||
| Swaps |
Other deferred credits | $ | (845 | ) | ||
| Swaps |
Other current liabilities | (3,532 | ) | |||
| 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 | ||||
Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at December 31, 2016 and December 31, 2015 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.
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, 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, 2016 | December 31, 2015 | |||||||
| (Thousands of dollars) | ||||||||
| Assets at fair value: |
||||||||
| Prepaids and other current assets – Swaps |
$ | 3,532 | $ | — | ||||
| Deferred charges and other assets – Swaps |
845 | — | ||||||
| Liabilities at fair value: |
||||||||
| Other current liabilities – Swaps |
— | (4,267 | ) | |||||
| Other deferred credits – Swaps |
— | (1,219 | ) | |||||
|
|
|
|
|
|||||
| Net Assets (Liabilities) |
$ | 4,377 | $ | (5,486 | ) | |||
|
|
|
|
|
|||||
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.
With regard to the fair values of assets associated with pension and postretirement benefit plans, refer to Note 10 – Pension and Other Post Retirement Benefits.
| Southwest Gas Corporation |
85 |
Note 14 – Segment Information
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 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, 2016 | December 31, 2015 | |||||||
| Accounts receivable for Centuri services |
$ | 10,585 | $ | 10,006 | ||||
|
|
|
|
|
|||||
The following table presents the amount of revenues for both segments by geographic area (thousands of dollars):
| December 31, 2016 |
December 31, 2015 |
December 31, 2014 |
||||||||||
| Revenues (a) |
||||||||||||
| United States |
$ | 2,256,600 | $ | 2,289,133 | $ | 2,069,513 | ||||||
| Canada |
203,890 | 174,492 | 52,194 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | 2,460,490 | $ | 2,463,625 | $ | 2,121,707 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Revenues are attributed to countries based on the location of customers. |
| Southwest Gas Corporation |
86 |
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, 2016 is as follows (thousands of dollars):
| 2016 | Gas Operations |
Construction Services |
Adjustments | Total | ||||||||||||
| Revenues from unaffiliated customers |
$ | 1,321,412 | $ | 1,040,957 | $ | 2,362,369 | ||||||||||
| Intersegment sales |
— | 98,121 | 98,121 | |||||||||||||
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 1,321,412 | $ | 1,139,078 | $ | 2,460,490 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Interest revenue |
$ | 1,848 | $ | 1 | $ | 1,849 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Interest expense |
$ | 66,997 | $ | 6,663 | $ | 73,660 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Depreciation and amortization |
$ | 233,463 | $ | 55,669 | $ | 289,132 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Income tax expense |
$ | 58,584 | $ | 19,884 | $ | 78,468 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Segment net income |
$ | 119,423 | $ | 32,618 | $ | 152,041 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Segment assets |
$ | 5,001,756 | $ | 579,370 | $ | 5,581,126 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Capital expenditures |
$ | 457,120 | $ | 72,411 | $ | 529,531 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| 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 | ||||||||||
|
|
|
|
|
|
|
|||||||||||
| Southwest Gas Corporation |
87 |
| (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. |
Note 15 – Quarterly Financial Data (Unaudited)
| Quarter Ended | ||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
| (Thousands of dollars, except per share amounts) | ||||||||||||||||
| 2016 |
||||||||||||||||
| Operating revenues |
$ | 731,248 | $ | 547,748 | $ | 539,969 | $ | 641,525 | ||||||||
| Operating income |
134,096 | 28,116 | 15,539 | 117,963 | ||||||||||||
| Net income |
75,355 | 9,099 | 2,907 | 65,694 | ||||||||||||
| Net income attributable to Southwest Gas Corporation |
75,446 | 8,943 | 2,472 | 65,180 | ||||||||||||
| Basic earnings per common share* |
1.59 | 0.19 | 0.05 | 1.37 | ||||||||||||
| Diluted earnings per common share* |
1.58 | 0.19 | 0.05 | 1.36 | ||||||||||||
| 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 | ||||||||||||
| * | 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 operations. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.
| Southwest Gas Corporation |
88 |
Note 16 – Construction Services Noncontrolling Interests
Associated with the agreement reached in conjunction with the acquisition of the Canadian construction businesses in October 2014, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses, and 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 are currently eligible to exit their investment retained by requiring the purchase of a portion of their interest and in incremental amounts annually. 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 ability of the noncontrolling parties to redeem their interest in Centuri for cash, their collective interest is presented on the Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance.
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 exercised during the third quarter of 2015, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized at that time, 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. Future adjustments to the redemption value are not permitted below a floor established subject to such conditions, and upward adjustments since the exchange date have had an offsetting impact to Retained earnings on the Balance Sheets. 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, 2015 |
$ | 16,108 | ||
| Net Income (loss) attributable to redeemable noncontrolling interest |
1,148 | |||
| Foreign currency exchange translation adjustment |
5 | |||
| Centuri distribution to redeemable noncontrolling interest |
(439 | ) | ||
| Adjustment to redemption value |
5,768 | |||
|
|
|
|||
| Balance, December 31, 2016 |
$ | 22,590 | ||
|
|
|
|||
| Southwest Gas Corporation |
89 |
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 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. 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 adjustment to the redemption value in the table above reflects the sum of such 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.
| Southwest Gas Corporation |
90 |
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
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 management, including the principal executive officer and principal financial officer, an evaluation was conducted 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 management’s evaluation under such framework, management concluded that the internal control over financial reporting was effective as of December 31, 2016. The effectiveness of internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.
February 28, 2017
| Southwest Gas Corporation |
91 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Southwest Gas Holdings, Inc.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interest , and cash flows present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 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, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Las Vegas, Nevada
February 28, 2017
| Southwest Gas Corporation |
92 |
EXHIBIT 21.01
SOUTHWEST GAS CORPORATION
LIST OF SUBSIDIARIES OF THE REGISTRANT
AT DECEMBER 31, 2016
| SUBSIDIARY NAME |
STATE OF INCORPORATION OR ORGANIZATION TYPE | |
| Carson Water Company | Nevada | |
| Centuri Construction Group, Inc. | Nevada | |
| Vistus Construction Group, Inc. | Nevada | |
| NPL Construction Co. | Nevada | |
| Brigadier Pipelines Inc. | Delaware | |
| Canyon Pipeline Construction Inc. | Nevada | |
| Lynxus Construction Group Inc. | Ontario, Canada | |
| NPL Canada Ltd. | Ontario, Canada | |
| 2018429 Ontario Ltd. | Ontario, Canada | |
| W.S. Nicholls Construction Inc. | Ontario, Canada | |
| W.S. Nicholls Industries Inc. | Ontario, Canada | |
| Paiute Pipeline Company | Nevada | |
| Southwest Gas Transmission Company | Limited partnership between Southwest Gas Corporation and Utility Financial Corp. | |
| Southwest Gas Capital III, IV | Delaware | |
| Utility Financial Corp. | Nevada | |
| The Southwest Companies | Nevada | |
| Southwest Gas Holdings, Inc. | California | |
| Southwest Gas Utility Group, Inc. | California | |
Exhibit 23.01
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (333-208609) and Form S-8 (Nos. 333-215145, 333-155581, 333-200835, 333-168731, 333-215150, 333-185354) of Southwest Gas Corporation of our report dated February 28, 2017 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders, which is incorporated in this Annual Report on Form 10-K.
/s/ PricewaterhouseCoopers LLP
Las Vegas, Nevada
February 28, 2017
Exhibit 31.02
Certification of Southwest Gas Corporation
I, John P. Hester, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Southwest Gas Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
| (c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: February 28, 2017
| /s/ JOHN P. HESTER |
| John P. Hester President and Chief Executive Officer |
| Southwest Gas Corporation |
Certification of Southwest Gas Corporation
I, Roy R. Centrella, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Southwest Gas Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
| (c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: February 28, 2017
| /s/ ROY R. CENTRELLA |
| Roy R. Centrella |
| Senior Vice President/Chief Financial Officer |
| Southwest Gas Corporation |
Exhibit 32.01
SOUTHWEST GAS CORPORATION
CERTIFICATION
In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2016 as filed with the Securities and Exchange Commission (the “Report”), I, John P. Hester, the President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:
| (1) | the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and |
| (2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. |
This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.
Dated: February 28, 2017
| /s/ John P. Hester |
| John P. Hester |
| President and Chief Executive Officer |
SOUTHWEST GAS CORPORATION
CERTIFICATION
In connection with the periodic report of Southwest Gas Corporation (the “Company”) on Form 10-K for the period ended December 31, 2016 as filed with the Securities and Exchange Commission (the “Report”), I, Roy R. Centrella, Senior Vice President/Chief Financial Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:
| (1) | the Report fully complies with the requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and |
| (2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. |
This Certification has not been, and shall not be deemed, “filed” with the Securities and Exchange Commission.
Dated: February 28, 2017
| /s/ Roy R. Centrella |
| Roy R. Centrella |
| Senior Vice President/Chief Financial Officer |
Document and Entity Information - USD ($) |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Feb. 15, 2017 |
Jun. 30, 2016 |
|
| Document And Entity Information [Abstract] | |||
| Document Type | 10-K | ||
| Amendment Flag | false | ||
| Document Period End Date | Dec. 31, 2016 | ||
| Document Fiscal Year Focus | 2016 | ||
| Document Fiscal Period Focus | FY | ||
| Trading Symbol | SWX | ||
| Entity Registrant Name | SOUTHWEST GAS CORP | ||
| Entity Central Index Key | 0000092416 | ||
| Current Fiscal Year End Date | --12-31 | ||
| Entity Well-known Seasoned Issuer | Yes | ||
| Entity Current Reporting Status | Yes | ||
| Entity Voluntary Filers | No | ||
| Entity Filer Category | Large Accelerated Filer | ||
| Entity Common Stock, Shares Outstanding | 47,546,825 | ||
| Entity Public Float | $ 3,736,883,501 |
Consolidated Balance Sheets (Parenthetical) - $ / shares |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Statement of Financial Position [Abstract] | ||
| Common stock, par | $ 1 | $ 1 |
| Common stock, authorized | 60,000,000 | 60,000,000 |
| Common stock, issued | 47,482,068 | 47,377,575 |
| Common stock, outstanding | 47,482,068 | 47,377,575 |
Consolidated Statements of Equity and Redeemable Noncontrolling Interest (Parenthetical) - $ / shares |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Statement of Stockholders' Equity [Abstract] | |||
| Dividends declared Common, per share | $ 1.80 | $ 1.62 | $ 1.46 |
| Shares registered and available for issuance | 3,800,000 | ||
Summary of Significant Accounting Policies |
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| Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Summary of Significant Accounting Policies | Note 1—Summary of Significant Accounting Policies Holding Company Reorganization. In 2015, the Board of Directors (“Board”) of the Southwest Gas Corporation (“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. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company (Southwest Gas Holdings, Inc.); whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of such reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The Board approved the reorganization in December 2016 which became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016. Specific disclosures and references to Southwest Gas Holdings, Inc. (the “holding company”) give effect to events and conditions of the equity registrant/consolidated entity and its officers or directors after December 31, 2016. Nature of Operations. The Company consists of two segments: natural gas operations (“Southwest”) and construction services (Centuri). 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, a 96.6% owned subsidiary, is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operations occur in 20 major markets in the U.S. and within the Canadian provinces of British Columbia and Ontario, and are generally conducted under the business names of NPL Construction Co. (“NPL”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd.), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). In May 2016, Centuri completed the acquisition of two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”). ETTI is operated as part of Brigadier. See Acquisition of Construction Services Businesses below for more information. In January 2017, W.S. Nicholls began conducting business as WSN Fabrication, a division of NPL Canada Ltd. 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 rate-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 as of December 31, 2016 (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 investment in Western totaled $10.8 million at December 31, 2015 and 2016. Both periods include the impacts of foreign currency exchange translation adjustments. Dividends of $500,000 were received from Western during 2016 with no impact on earnings. No dividends were received from Western in 2015. A management fee was paid by Western to its partners, including W.S. Nicholls, in accordance with underlying agreements. 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 $35.8 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 were deemed to be worthless. Centuri recorded earnings of $69,000 from this investment in 2016, which is included in Other Income (deductions) in the Consolidated Statements of Income. In addition, Centuri, through its subsidiaries, has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture, which are also equity method investments. 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 (thousands of dollars):
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 $30 million in 2016 and $24 million in 2015 (carried at weighted average cost). Also included is natural gas stored underground and liquefied natural gas (both carried at weighted average cost), in addition to prepaid assets. Income Taxes. The asset and liability method of accounting is utilized for the recognition of 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, 2016, the Company had cumulative earnings of approximately $5 million in its foreign jurisdiction. However, management intends to permanently reinvest any foreign earnings in Canada. See Note 12 – Income Taxes for further information. Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents also includes money market fund investments totaling approximately $5.3 million and $250,000 at December 31, 2016 and 2015, respectively, 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 $6.5 million, $3.1 million, and $8.1 million during 2016, 2015, and 2014, 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-cashinvesting 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. This outflow activity was recorded in investing activities in 2015 as Acquisition of businesses, net of cash acquired. Goodwill. Goodwill is assessed for impairment annually, 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 is conducted in the 4th quarter each year and 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 our reporting units are less than their carrying amounts in either 2015 or 2016. Thus, no impairment was recorded in either year. One of the businesses associated with the ETTI acquisition in 2016 (further discussion below) was acquired via asset purchase. As a result, goodwill associated with ETTI is expected to be deductible for tax purposes.
Goodwill from the ETTI acquisition consists of the excess of purchase price over the fair value of the acquired net assets and represents the value of the assembled workforce and the estimated economic value attributable to future opportunities that will arise based on the strong financial performance of the combined entities. Acquisition of Construction Services Businesses. In May 2016, Centuri completed the acquisition of ETTI, which is based in Lisbon Falls, Maine, and has a primary focus on underground utility installation using horizontal directional drilling technology. The acquisition of ETTI will provide complementary operational support to, and be operated as part of, Brigadier, expanding operations into Maine. Neither the acquisition itself nor the impacts to assets and operations were material to the construction services segment or the Company at December 31, 2016. Assets acquired in the transaction were recorded at their acquisition date fair values. The final purchase accounting is complete. The final estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):
The purchase price consisted of $17 million in cash on the acquisition date with the remaining amount being deferred over four years.
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 construction services businesses acquired in 2014 and have finite lives. Centuri has $37.7 million and $36.8 million of intangible assets (varies due to foreign currency translation) at December 31, 2016 and 2015, respectively, as detailed in the following table (thousands of dollars):
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):
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. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of unusual weather variability and conservation on margin. 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. Management 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, office and equipment rental costs, subcontractor expenses, training, job-related materials, gains and losses on equipment sales, and professional fees of Centuri. Net Cost of Gas Sold. Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of natural gas derivative instruments. Also included are the net impacts of PGA deferrals and recoveries, which by their inclusion, result in net cost of gas sold overall that is comparable to amounts included in billed gas operating revenues. Differences between amounts incurred with suppliers, transmission pipelines, etc. and those already included in customer rates, are temporarily deferred in purchased gas adjustment accounts pending inclusion in customer rates. 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. During the third quarter of 2016, Centuri evaluated the estimated useful lives of its depreciable assets, and in so doing determined that certain equipment lives should be extended. This change in estimate reduced 2016 depreciation by approximately $4 million. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense. 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.
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):
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 the Company 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. Earnings Per Share. Basic earnings per share (“EPS”) in each period of this report were calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during those periods. 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.
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 the 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 July 2015, the FASB approved a one-year deferral of the effective date (annual periods beginning after December 15, 2017). In March, April, May, and December of 2016, the FASB issued updates to Topic 606 related to “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, “Identifying Performance Obligations and Licensing”, “Narrow-Scope Improvements and Practical Expedients”, and certain “Technical Corrections and Improvements”. The amendments in the first two updates, respectively, provide guidance when another party, along with the entity, is involved in providing a good or service to a customer, and provide clarification with regard to identifying performance obligations and of the licensing implementation guidance in Topic 606. The third update includes improvements to the guidance on collectability, noncash consideration, and completed contracts at transition. In addition, a practical expedient is provided for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The fourth update affects narrow aspects of the guidance as issued to date. The combined amendments do not change the core principles of the guidance in Topic 606. Management plans to adopt all of these updates at the required adoption date, which is for interim and annual reporting periods commencing January 2018. Management has substantially completed the evaluation of the sources of revenue and are currently assessing the effect of the new guidance on the financial position, results of operations and cash flows. The assessment is contingent, in part, upon the completion of deliberations currently in progress by the utility industry, notably in connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants (“AICPA”). In association with this undertaking, the AICPA formed a number of industry task forces, including a Power & Utilities (“P&U”) Task Force, on which Company personnel actively participate via formal membership. Industry representatives and organizations, the largest auditing firms, the AICPA’s Revenue Recognition Working Group and its Financial Reporting Executive Committee have undertaken, and continue to undertake, consideration of several items relevant to the utility industry. Where applicable or necessary, the FASB’s Transition Resource Group (TRG) is also participating. Currently, the industry is working to address several items including the evaluation of collectability from customers if a utility has regulatory mechanisms to help assure recovery of uncollected accounts from ratepayers and the accounting for funds received from third parties to partially or fully reimburse the cost of construction of an asset. Currently, a timeline for the resolution of these deliberations has not been established. Southwest is actively working with its peers in the rate-regulated natural gas industry and with the public accounting profession to conclude on the accounting treatment for several other issues that are not expected to be addressed by the P&U Task Force. As of December 31, 2016, the construction services segment has substantially completed the evaluation of sources of revenue and is currently assessing the effect of the new guidance on financial position, results of operations and cash flows. The principals of the new revenue recognition guidance are very similar to existing guidance for construction contractors. Similar to the P&U Task Force noted above, the AICPA formed the Engineering and Construction Contractors Task Force to assist the construction industry with implementing the new guidance. The accounting guide the AICPA intends to release is expected to provide implementation guidance related to several issues including 1) combining contracts and separating performance obligations; 2) estimating change orders, incentives, penalties, liquidated damages and other variable consideration items and 3) acceptable measures of progress when recognizing revenue over time. Given the uncertainty with respect to the conclusions that might arise from the deliberations on issues associated with both the natural gas and construction services segments, the Company is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, business processes, or the transition method it will utilize to adopt the new guidance. 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 entity 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 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. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.
In February 2016, the FASB issued the update “Leases (Topic 842)”. Under the update, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:
Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Though companies have historically been required to make disclosures regarding leases and of contractual obligations, leases (with terms longer than a year) will no longer exist off-balance sheet. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. Early application is permitted. Management currently plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2019. Existing leases have been documented by both segments and management is in the process of determining if special software will be necessary to implement the standard. In addition, management is evaluating the potential impacts of various natural gas industry-related issues in light of the leasing standard. Given the uncertainty with respect to the conclusions that might arise from these deliberations, management is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, or business processes. In March 2016, the FASB issued the update “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The update requires the recording of all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then recorded in the income statement. While the simplification will reduce some of the administrative complexities by eliminating the need to track a “windfall pool,” it will increase the volatility of income tax expense. The update also allows entities to withhold shares for the employee tax burden up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in a liability classification of the award (currently such withholding is limited to the employer’s minimum statutory withholding). The update clarifies that all cash payments made to taxing authorities on the employees’ behalf for withheld shares should be presented as financing activities on the statement of cash flows. Also, the update requires all tax-related cash flows resulting from share-based payments be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Management issues share-based payment awards to its employees. The update was adopted by management in January 2017. In June 2016, the FASB issued the update “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. The update amends guidance on reporting credit losses for financial assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, the update eliminates the “probable” threshold for initial recognition of credit losses in current U.S. GAAP and, instead, requires an entity to reflect its current estimate of all expected credit losses. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset to present the net amount expected to be collected. For available for sale debt securities, credit losses should be measured in a manner similar to current U.S. GAAP, however the update will require that credit losses be presented as an allowance rather than as a write-down. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The update affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. All entities may adopt the amendments in this update earlier as of fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures. In August 2016, the FASB issued the update “Classification of Certain Cash Receipts and Cash Payments”. This update addresses the following specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance (“COLI”) policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows, including identification of the predominant nature in cases where cash receipts and payments have aspects of more than one class of cash flows. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Management is evaluating the impacts this update might have on its consolidated cash flow statements and disclosures. In October 2016, the FASB issued the update “Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory.” This update eliminates the current U.S. GAAP exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted; however, the guidance can only be adopted in the first interim period of a fiscal year. The modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Management is evaluating the impacts this update might have on its consolidated financial statements. In October 2016, the FASB issued the update “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” The amendments affect reporting entities that are required to evaluate whether they should consolidate a variable interest entity in certain situations involving entities under common control. The update is effective for fiscal and interim periods beginning after December 15, 2016. Management has determined that this update is not impactful to its consolidated financial statements.
In January 2017, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The update eliminates Step 2 from the goodwill impairment test. The annual, or interim, goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. In addition, income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit should be considered when measuring the goodwill impairment loss, if applicable. The update also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative test, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The amendments should be applied on a prospective basis. The update is effective for fiscal and interim periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Management has determined that this update would have had no impact on the consolidated financial statements for the periods presented if it had been effective during those periods. Subsequent Events. Management 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. |
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Utility Plant and Leases |
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| Utility Plant and Leases | Note 2 – Utility Plant and Leases Net utility plant as of December 31, 2016 and 2015 was as follows (thousands of dollars):
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 2016, annual depreciation and amortization expense averaged 3.6% of the original cost of depreciable and amortizable property. Average rates in 2015 and 2014 also approximated 3.6%. Transmission and Distribution plant (combined), associated with our core natural gas delivery infrastructure, constitute the majority of gas plant. Annual depreciation expense averaged approximately 3.3% of original cost of depreciable transmission and distribution plant during the period 2014 through 2016. Depreciation and amortization expense on gas plant, including intangibles, was as follows (thousands of dollars):
Included in the figures above is amortization of intangibles of $14.8 million in 2016, $12.7 million in 2015, and $11.7 million in 2014. Operating Leases and Rentals. Certain office and construction equipment is leased. 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):
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, 2016 (thousands of dollars):
Capital Leases. Centuri leases certain construction equipment under capital leases arrangements. The amounts associated with capital leases of equipment as of December 31, 2016 and 2015 are as follows (thousands of dollars):
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, 2016 (thousands of dollars):
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Receivables and Related Allowances |
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| Receivables [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables and Related Allowances | 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, 2016 and 2015, and the percentage of customers in each of the three states.
Although Southwest 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):
At December 31, 2016, the construction services segment (Centuri) had $173 million in customer accounts receivable. Both the allowance for uncollectibles and write-offs related to Centuri customers have been insignificant and are not reflected in the table above. |
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Regulatory Assets and Liabilities |
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| Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulatory Assets and Liabilities | Note 4 – Regulatory Assets and Liabilities Southwest is subject to the regulation of the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”). Accounting policies of Southwest conform to U.S. GAAP applicable to rate-regulated entities and reflect the effects of the ratemaking process. Accounting treatment for rate-regulated entities allows for deferral as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.
The following table represents existing regulatory assets and liabilities (thousands of dollars):
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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") |
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| Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") | 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)
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):
Approximately $2.1 million of realized losses (net of tax) related to the FSIRS, included in AOCI at December 31, 2016, 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)
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, 2016 and 2015: Amounts Recognized in AOCI (Before Tax) (Thousands of dollars)
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. |
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Common Stock |
12 Months Ended |
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| Text Block [Abstract] | |
| Common Stock | 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 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 the twelve months ended December 31, 2016, the Company sold no shares through the continuous equity offering program. Since the start of the program in March 2015, the Company sold an aggregate of 645,225 shares of common stock under this program resulting in proceeds of $35,167,584, net of $355,228 in agent commissions. Effective January 2017, no further shares will be issued under this registration statement. During 2016, the Company issued approximately 105,000 shares of common stock through the Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan. |
Long-Term Debt |
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| Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-Term Debt | Note 7 – Long-Term Debt Carrying amounts of the Company’s long-term debt and their related estimated fair values as of December 31, 2016 and December 31, 2015 are disclosed in the following table. The fair values of the revolving credit facility (including commercial paper) and the variable-rate Industrial Development Revenue Bonds (“IDRBs”) approximate their carrying values, as they are repaid quickly (in the case of credit facility borrowings) and have interest rates that reset frequently. They are categorized as Level 1 (quoted prices for identical financial instruments) within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, due to the Company’s ability to access similar debt arrangements at measurement dates with comparable terms, including variable rates. The fair values of debentures, senior notes, and fixed-rate IDRBs were determined utilizing a market-based valuation approach, where fair market values are determined based on evaluated pricing data, such as broker quotes and yields for similar securities adjusted for observable differences. Significant inputs used in the valuation generally include benchmark yield curves, credit ratings and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. The market values of debentures and fixed-rate IDRBs are categorized as Level 2 (observable market inputs based on market prices of similar securities). The Centuri secured revolving credit and term loan facility and Centuri other debt obligations (not actively traded) are categorized as Level 3, based on significant unobservable inputs to their fair values. Since Centuri’s debt is not publicly traded, fair values for the secured revolving credit and term loan facility and other debt obligations were based on a conventional discounted cash flow methodology and 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.
In March 2016, the Company amended its $300 million credit and commercial paper facility. The facility was previously scheduled to expire in March 2020, but was extended to March 2021. 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, 2016, 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, 2016, $5 million was outstanding on the long-term portion of the credit facility, none of which was in commercial paper (see commercial paper program discussion below). The effective interest rate on the long-term portion of the credit facility was 5.21% at December 31, 2016. Borrowings under the credit facility ranged from none at various times throughout 2016 to a high of $230 million during the third quarter of 2016. With regard to the short-term portion of the credit facility, there were no borrowings outstanding at December 31, 2016 and $18 million outstanding at December 31, 2015. (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, 2016, and as noted above, no borrowings were outstanding under the commercial paper program. Southwest redeemed its $100 million 2005 4.85% Series A fixed-rate IDRBs (originally due in 2035) at par with accrued interest in July 2016. In September 2016, Southwest redeemed its $24.9 million 2006 Series A 4.75% fixed-rate IDRBs (originally due in 2036) at par with accrued interest. In January 2017, subsequent to the most recent balance sheet date, the $25 million 7.59% medium-term notes were repaid at maturity, using available cash on hand. In September 2016, Southwest issued $300 million in 3.8% Senior Notes at a discount of 0.302%. The notes will mature in September 2046. A portion of the net proceeds were used to temporarily pay down amounts then outstanding under the credit facility. The remaining net proceeds were used for general corporate purposes. 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. 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, 2016 totaled $445 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 their consolidated leverage ratio. The commitment fee ranges from 0.15% to 0.40% per annum. Borrowings under the revolving credit facility ranged from a low of $36.2 million during February 2016 to a high of $83.2 million during July 2016. All amounts outstanding are considered long-term borrowings. The effective interest rate on the secured revolving credit and term loan facility was 2.63% at December 31, 2016. The effective interest rates on Southwest’s variable-rate IDRBs are included in the table below:
In Nevada, interest fluctuations due to changing interest rates on Southwest’s 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account. None of Southwest’s debt instruments have credit triggers or other clauses that result in default if bond ratings are lowered by rating agencies. Certain 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, 2016, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, at December 31, 2016, approximately $2.3 billion in additional debt could be issued while still meeting the leverage ratio requirement. Relating to the minimum net worth requirement, as of December 31, 2016, there is at least $1.1 billion of cushion in equity. Certain Centuri debt instruments also have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. Under the most restrictive of the covenants, Centuri could issue approximately $145 million in additional debt and meet the leverage ratio requirement. Centuri has at least $21 million of cushion relating to the minimum fixed charge ratio coverage requirement. Estimated maturities of long-term debt for the next five years are (in thousands):
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Short-Term Debt |
12 Months Ended |
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Dec. 31, 2016 | |
| Debt Disclosure [Abstract] | |
| Short-Term Debt | Note 8 – Short-Term Debt As discussed in Note 7, Southwest has a $300 million credit facility that is scheduled to expire in March 2021, of which $150 million has been designated by management for working capital purposes. Southwest had no short-term borrowings outstanding at December 31, 2016 and $18 million in short-term borrowings outstanding at December 31, 2015. |
Commitments and Contingencies |
12 Months Ended |
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Dec. 31, 2016 | |
| Commitments and Contingencies Disclosure [Abstract] | |
| Commitments and Contingencies | 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, results of operations, or cash flows. Southwest maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, Southwest 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 2016 to July 2017, 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, Southwest 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, Southwest will make an accrual, as necessary. |
Pension and Other Postretirement Benefits |
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| Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Pension and Other Postretirement Benefits | Note 10 – Pension and Other Postretirement Benefits An Employees’ Investment Plan is offered to eligible employees of Southwest through deduction of a percentage of base compensation, subject to IRS limitations. The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock. One-half of amounts deferred by employees are matched, up to a maximum matching contribution of 3.5% of an employee’s annual compensation. The cost of the plan is disclosed below (in thousands):
Centuri has a separate plan, the cost and liability of which are not significant. A deferred compensation plan is offered to 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. One-half of amounts deferred by officers are matched, 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. A noncontributory qualified retirement plan with defined benefits covering substantially all Southwest employees is available in addition to a separate unfunded supplemental executive retirement plan (“SERP”) which is limited to officers. Postretirement benefits other than pensions (“PBOP”) are provided to qualified retirees for health care, dental, and life insurance benefits. The overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, are recognized in the 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. A regulatory asset has been established 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, manage funded status risk 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, 2016, the percentage ranges of the target portfolio are:
The qualified retirement plan invests the majority of its plan assets in common collective trusts which includes a well-diversified portfolio of domestic and international equity securities and fixed income securities, which are managed by a professional investment manager appointed by the Company. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the specific guidelines prescribed by the Company through the plan’s investment policy statement. In 2016, the Company adopted a liability driven investment (“LDI”) strategy for part of the portfolio, a form of investing designed to better match the movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the pension plan liability. The implementation of the LDI strategy will be phased in over time by using a glide path. The glide path is designed to increase the allocation of the plan’s assets to fixed income securities, as the funded status of the plan increases, in order to more closely match the duration of the plan assets to that of the plan liability. During the third quarter of 2016, qualifying term-vested participants were offered a lump-sum present value payout of their pensions. The offer was primarily intended to reduce insurance and ongoing maintenance costs associated with qualifying participant balances. About one-half of the approximate 800 participants subject to the offer accepted the offer, resulting in an approximate $30 million payment from pension assets paid in the fourth quarter of 2016. In August 2016, Russell Investments Trust Company (“Russell”), an outside professional investment manager as defined in Section 3(38) of ERISA, was engaged as a fiduciary of the pension plan. Russell has full discretionary authority to direct the investment of the pension plan’s assets within the guidelines prescribed by the pension plan’s investment policy statement. The change, related to managing pension plan assets, has no impact on retirement benefit calculations for pension plan participants, and was approved by the Board of Directors of the Company. Pension plan assets are held in a Master Trust. Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of the obligations to the pension plan’s beneficiaries. To meet this objective, the pension plan assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the plan’s benefit payment obligations. The pension plan funding policy is in compliance with the federal government’s funding requirements. Pension costs for these plans are affected by the amount and timing of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan. In determining the discount rate, management 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. There was no change in the discount rate between years. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase also remained the same (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:
Pension expense for 2017 is estimated to be similar to that experienced in 2016. Future years’ expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.
The following table sets forth the retirement plan, SERP, and PBOP funded statuses and amounts recognized on the Consolidated Balance Sheets and Consolidated Statements of Income.
Estimated funding for the plans above during calendar year 2017 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):
Benefits expected to be paid for pension, SERP, and PBOP over the next 10 years are as follows (in millions):
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% declining to 4.5%. Fixed contributions are made for health care benefits of employees who retire after 1988, but Southwest 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
Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
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, 2016 and December 31, 2015. The change in the types of pension investment holdings between years is due to the engagement of Russell and the subsequent transition of pension investments to Russell funds. The transition efforts consolidated the majority of the pension plan investments into private commingled equity and fixed income funds. The SERP has no assets.
In the prior year, Level 1 also included Common stock, Real Estate Investment Trusts, Mutual funds, and U.S. Government securities listed or regularly traded on a national securities exchange and were valued at quoted market prices as of the last business day of the calendar year.
Shares in the private equity commingled funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item. Two funds are classified as international funds. One invests in international financial markets, primarily those of developed economies in Europe and the Pacific Basin. The fund invests primarily in equity securities issued by foreign corporations, but may invest in other securities perceived as offering attractive investment return opportunities. The other provides diversified exposure to global equity markets. The fund seeks to provide long-term capital growth by investing primarily in securities listed on the major developed equity markets of the United States, Europe, and Asia, as well as within those listed on emerging country equity markets on a tactical basis. The large and medium capitalization fund is designed to track the performance of the large and medium capitalization companies contained in the index, which represents approximately 90% of the market capitalization of the United States stock market. The small capitalization fund is designed to provide maximum long-term appreciation through investments that are well diversified by industry. The emerging markets fund was developed to invest in emerging market equities worldwide. The purposes of the fund’s operations, “emerging market countries” include every country in the world except the developed markets of the United States, Canada, Japan, Australia, New Zealand, Hong Kong and Singapore, and most countries located in Western Europe. Fund investments are made directly in each country or, where direct investment is inefficient or prohibited, through appropriate financial instruments or participation in commingled funds.
The U.S. corporate bond fund seeks to provide high quality, mostly corporate bond-based exposure to fixed income securities which closely match those found in discount curves used to value United States pension liabilities. The United States debt market long duration fund provides participation in the full spectrum of investment opportunities in primarily United States debt markets with longer maturities. The fund seeks to offer effective diversification against equities, take advantage of market trading opportunities, and provide a competitive rate of return on assets. The fund’s current duration is close to 14 years. The United States Treasuries securities funds seeks to replicate the risk and return characteristics of the Barclays Treasury U.S. Separate Trading of Registered Interest and Principal of Securities (“STRIPS”) 28-29 Years Index with minimum tracking error.
In the prior year, the fair value of the Level 2 investments in debt securities with remaining maturities of one year or more was 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 terms and conditions under which shares in the commingled equity funds were redeemed varied among the funds; the notice required ranged from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds required the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminished the greater the transaction. Other such funds imposed fees to recover direct costs incurred by the fund at redemption, but were indeterminable prior to redemption.
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Stock-Based Compensation |
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| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-Based Compensation | Note 11 – Stock-Based Compensation At December 31, 2016, two stock-based compensation plans existed: a performance share stock plan which includes a cash award, and a restricted stock/unit plan. All previous grants under the stock option plan expired in 2016. 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):
Under the option plan, options to purchase shares of common stock at a stated exercise price were previously granted 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 the Company’s common stock on the date of grant and a maximum term of ten years. The final options were exercised in 2016. The following tables summarize the stock option plan activity and related information (thousands of options):
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):
During 2016, $735,000 in cash was received from the exercise of options with a corresponding tax benefit of $205,000, which was recorded in additional paid-in capital. Under the performance share stock plan, performance shares may be issued to encourage key employees to remain as employees 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. Restricted stock/units under the restricted stock/unit plan are issued to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance. 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 currently 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, 2016 (thousands of shares):
The weighted average grant date fair value of performance shares and restricted stock/units granted in 2015 and 2014 was $63.09 and $53.73, respectively. As of December 31, 2016, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.3 million. |
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Income Taxes |
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| Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income Taxes | Note 12 – Income Taxes The following is a summary of income before taxes and noncontrolling interest for domestic and foreign operations (thousands of dollars):
Income tax expense (benefit) consists of the following (thousands of dollars):
Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2014, 2015, and 2016 (and the sources of these differences and the effect of each) are summarized as follows:
Deferred tax assets and liabilities consist of the following (thousands of dollars):
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 2012. At December 31, 2016, the Company has U.S. federal net capital loss carryforwards of $278,000, which begin to expire in 2017. At December 31, 2016, the Company has an income tax net operating loss carryforward related to Canadian operations of $4.5 million which begins to expire in 2032. As of December 31, 2016, the Company has approximately $5 million of undistributed foreign earnings. However, management 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):
In assessing whether uncertain tax positions should be recognized in its financial statements, management 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, management 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, management 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. Unrecognized tax benefits are recognized 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. Measurement of 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 $935,000 at December 31, 2016. 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 2016, 2015, and 2014. 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. Management expects the IRS to issue natural gas industry guidance that 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, management expects the regulations could result in a modest acceleration of tax deductibility and the deferral of tax payments.
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Derivatives and Fair Value Measurements |
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| Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives and Fair Value Measurements | Note 13 – Derivatives and Fair Value Measurements Derivatives. In managing its natural gas supply portfolios, Southwest has historically entered into fixed- and variable-price contracts, which qualify as derivatives. Additionally, Southwest utilizes fixed-for-floating swap contracts (“Swaps”) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business, and are exempt from fair value reporting. The variable-price contracts have no significant market value. The Swaps are recorded at fair value. The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (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 2017 through March 2019. 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):
Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations. The following table sets forth the gains and (losses) recognized on Southwest’s Swaps (derivatives) for the years ended December 31, 2016, 2015, and 2014 and their location in the Consolidated Statements of Income: Gains (losses) recognized in income for derivatives not designated as hedging instruments: (Thousands of dollars)
* 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, and the second, 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 Swaps and their location in the Consolidated Balance Sheets (thousands of dollars): Fair values of derivatives not designated as hedging instruments:
The estimated fair values of the natural gas derivatives were determined using future natural gas index prices (as more fully described below). Master netting arrangements exist with each counterparty that provide for the net settlement (in the settlement month) of all contracts through a single payment. As applicable, management has elected to reflect the net amounts in its balance sheets. No outstanding collateral associated with the Swaps existed during any period presented in the above table. Pursuant to regulatory deferral accounting treatment for rate-regulated entities, unrealized gains and losses in fair value of the Swaps are recorded as a regulatory asset and/or liability. When the Swaps mature, any prior positions held are reversed and the settled position is recorded 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 presents the amounts paid to and received from counterparties for settlements of matured Swaps.
The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the Consolidated Balance Sheets (thousands of dollars).
Fair Value Measurements. The estimated fair values of Southwest’s Swaps were determined at December 31, 2016 and December 31, 2015 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. 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, 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
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. With regard to the fair values of assets associated with pension and postretirement benefit plans, refer to Note 10 – Pension and Other Post Retirement Benefits. |
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Segment Information |
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| Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Segment Information | Note 14 – Segment Information 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 prices at contract inception. Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).
The following table presents the amount of revenues for both segments by geographic area (thousands of dollars):
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, 2016 is as follows (thousands of dollars):
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Quarterly Financial Data |
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| Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Quarterly Financial Data | Note 15 – Quarterly Financial Data (Unaudited)
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 operations. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results. |
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Construction Services Noncontrolling Interests |
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| Noncontrolling Interest [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Construction Services Noncontrolling Interests | Note 16 – Construction Services Noncontrolling Interests Associated with the agreement reached in conjunction with the acquisition of the Canadian construction businesses in October 2014, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses, and 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 are currently eligible to exit their investment retained by requiring the purchase of a portion of their interest and in incremental amounts annually. 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 ability of the noncontrolling parties to redeem their interest in Centuri for cash, their collective interest is presented on the Consolidated Balance Sheets at December 31, 2016 and December 31, 2015 as a Redeemable noncontrolling interest, a category of mezzanine equity (temporary equity), in accordance with SEC guidance. 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 exercised during the third quarter of 2015, an updated valuation was conducted. A significant decrease in the value of the redeemable noncontrolling interest was recognized at that time, 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. Future adjustments to the redemption value are not permitted below a floor established subject to such conditions, and upward adjustments since the exchange date have had an offsetting impact to Retained earnings on the Balance Sheets. The following depicts impacts to the balance of the redeemable noncontrolling interest between the indicated periods.
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 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. 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 adjustment to the redemption value in the table above reflects the sum of such 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. |
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Summary of Significant Accounting Policies (Policies) |
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| Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Holding Company Reorganization | Holding Company Reorganization. In 2015, the Board of Directors (“Board”) of the Southwest Gas Corporation (“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. As part of the holding company reorganization, Centuri Construction Group, Inc. (“Centuri” or the “construction services” segment) and Southwest Gas Corporation would each be subsidiaries of the new publicly traded parent holding company (Southwest Gas Holdings, Inc.); whereas, historically, Centuri had been a direct subsidiary of Southwest Gas Corporation. All of Southwest Gas Corporation’s outstanding debt securities (not associated with Centuri) at the time of the reorganization would remain at the Southwest Gas utility entity. Regulatory applications for preapproval of such reorganization were filed with the ACC, the CPUC, and the PUCN in October 2015. Approvals were received from the CPUC, the PUCN, and the ACC in January, March, and May, respectively, of 2016. The Board approved the reorganization in December 2016 which became effective in January 2017. Each outstanding share of Southwest Gas Corporation common stock automatically converted into a share of stock in Southwest Gas Holdings, Inc., on a one-for-one basis, and the ticker symbol of the stock, “SWX,” remains unchanged. Throughout this report, the “Company” refers to Southwest Gas Corporation and subsidiaries for periods prior to January 1, 2017 and to Southwest Gas Holdings, Inc. and subsidiaries for periods subsequent to December 31, 2016. Specific disclosures and references to Southwest Gas Holdings, Inc. (the “holding company”) give effect to events and conditions of the equity registrant/consolidated entity and its officers or directors after December 31, 2016. |
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| Nature of Operations | Nature of Operations. The Company consists of two segments: natural gas operations (“Southwest”) and construction services (Centuri). 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, a 96.6% owned subsidiary, is a comprehensive construction services enterprise dedicated to meeting the growing demands of North American utilities, energy and industrial markets. Centuri derives revenue from installation, replacement, repair, and maintenance of energy distribution systems, and developing industrial construction solutions primarily for energy services utilities. Centuri operations occur in 20 major markets in the U.S. and within the Canadian provinces of British Columbia and Ontario, and are generally conducted under the business names of NPL Construction Co. (“NPL”), NPL Canada Ltd. (“NPL Canada”, formerly Link-Line Contractors Ltd.), W.S. Nicholls Construction, Inc. and related companies (“W.S. Nicholls”), and Brigadier Pipelines Inc. (“Brigadier”). In May 2016, Centuri completed the acquisition of two privately held, affiliated construction businesses: Enterprise Trenchless Technologies, Inc. and ETTI Holdings (collectively, “ETTI”). ETTI is operated as part of Brigadier. See Acquisition of Construction Services Businesses below for more information. In January 2017, W.S. Nicholls began conducting business as WSN Fabrication, a division of NPL Canada Ltd. |
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| Basis of Presentation | 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 rate-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. |
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| Consolidation | Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries as of December 31, 2016 (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 investment in Western totaled $10.8 million at December 31, 2015 and 2016. Both periods include the impacts of foreign currency exchange translation adjustments. Dividends of $500,000 were received from Western during 2016 with no impact on earnings. No dividends were received from Western in 2015. A management fee was paid by Western to its partners, including W.S. Nicholls, in accordance with underlying agreements. 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 $35.8 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 were deemed to be worthless. Centuri recorded earnings of $69,000 from this investment in 2016, which is included in Other Income (deductions) in the Consolidated Statements of Income. In addition, Centuri, through its subsidiaries, has a 25% interest in CCI-TBN Toronto, Inc. and a 50% interest in Matheson-Nicholls Joint Venture, which are also equity method investments. |
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| Net Utility Plant | 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. |
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| Other Property and Investments | Other Property and Investments. Other property and investments includes (thousands of dollars):
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| Deferred Purchased Gas Costs | 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. |
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| Prepaids and Other Current Assets | Prepaids and other current assets. Prepaids and other current assets includes gas pipe materials and operating supplies of $30 million in 2016 and $24 million in 2015 (carried at weighted average cost). Also included is natural gas stored underground and liquefied natural gas (both carried at weighted average cost), in addition to prepaid assets. |
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| Income Taxes | Income Taxes. The asset and liability method of accounting is utilized for the recognition of 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, 2016, the Company had cumulative earnings of approximately $5 million in its foreign jurisdiction. However, management intends to permanently reinvest any foreign earnings in Canada. See Note 12 – Income Taxes for further information. |
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| Cash and Cash Equivalents | Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. In general, cash and cash equivalents fall within Level 1 (quoted prices for identical financial instruments) of the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability. However, cash and cash equivalents also includes money market fund investments totaling approximately $5.3 million and $250,000 at December 31, 2016 and 2015, respectively, 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 $6.5 million, $3.1 million, and $8.1 million during 2016, 2015, and 2014, 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. This outflow activity was recorded in investing activities in 2015 as Acquisition of businesses, net of cash acquired. |
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| Goodwill | Goodwill. Goodwill is assessed for impairment annually, 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 is conducted in the 4th quarter each year and 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 our reporting units are less than their carrying amounts in either 2015 or 2016. Thus, no impairment was recorded in either year. One of the businesses associated with the ETTI acquisition in 2016 (further discussion below) was acquired via asset purchase. As a result, goodwill associated with ETTI is expected to be deductible for tax purposes.
Goodwill from the ETTI acquisition consists of the excess of purchase price over the fair value of the acquired net assets and represents the value of the assembled workforce and the estimated economic value attributable to future opportunities that will arise based on the strong financial performance of the combined entities. |
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| Acquisition of Construction Services Businesses | Acquisition of Construction Services Businesses. In May 2016, Centuri completed the acquisition of ETTI, which is based in Lisbon Falls, Maine, and has a primary focus on underground utility installation using horizontal directional drilling technology. The acquisition of ETTI will provide complementary operational support to, and be operated as part of, Brigadier, expanding operations into Maine. Neither the acquisition itself nor the impacts to assets and operations were material to the construction services segment or the Company at December 31, 2016. Assets acquired in the transaction were recorded at their acquisition date fair values. The final purchase accounting is complete. The final estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):
The purchase price consisted of $17 million in cash on the acquisition date with the remaining amount being deferred over four years.
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| Intangible Assets | 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 construction services businesses acquired in 2014 and have finite lives. Centuri has $37.7 million and $36.8 million of intangible assets (varies due to foreign currency translation) at December 31, 2016 and 2015, respectively, as detailed in the following table (thousands of dollars):
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):
See Note 2 – Utility Plant and Leases for additional information regarding natural gas operations intangible assets. |
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| Accumulated Removal Costs | 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. |
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| Gas Operating Revenues | 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. All of Southwest’s service territories have decoupled rate structures (alternative revenue programs), which are designed to eliminate the direct link between volumetric sales and revenue, thereby mitigating the impacts of unusual weather variability and conservation on margin. 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. Management uses the net classification method to report taxes collected from customers to be remitted to governmental authorities. |
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| Construction Revenues | 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. |
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| Construction Expenses | Construction Expenses. The construction expenses classification in the income statement includes payroll expenses, office and equipment rental costs, subcontractor expenses, training, job-related materials, gains and losses on equipment sales, and professional fees of Centuri. |
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| Net Cost of Gas Sold | 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, which by their inclusion, result in net cost of gas sold overall that is comparable to amounts included in billed gas operating revenues. Differences between amounts incurred with suppliers, transmission pipelines, etc. and those already included in customer rates, are temporarily deferred in purchased gas adjustment accounts pending inclusion in customer rates. |
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| Operations and Maintenance Expense | 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). |
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| Depreciation and Amortization | 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. During the third quarter of 2016, Centuri evaluated the estimated useful lives of its depreciable assets, and in so doing determined that certain equipment lives should be extended. This change in estimate reduced 2016 depreciation by approximately $4 million. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense. See also discussion regarding Accumulated Removal Costs above. |
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| Allowance for Funds Used During Construction ("AFUDC") | 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.
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| Other Income (Deductions) | 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):
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 the Company 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. |
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| Foreign Currency Translation | 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 | Earnings Per Share. Basic earnings per share (“EPS”) in each period of this report were calculated by dividing net income attributable to Southwest Gas Corporation by the weighted-average number of shares outstanding during those periods. 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.
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| Recently Issued Accounting Standards Updates | 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 the 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 July 2015, the FASB approved a one-year deferral of the effective date (annual periods beginning after December 15, 2017). In March, April, May, and December of 2016, the FASB issued updates to Topic 606 related to “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”, “Identifying Performance Obligations and Licensing”, “Narrow-Scope Improvements and Practical Expedients”, and certain “Technical Corrections and Improvements”. The amendments in the first two updates, respectively, provide guidance when another party, along with the entity, is involved in providing a good or service to a customer, and provide clarification with regard to identifying performance obligations and of the licensing implementation guidance in Topic 606. The third update includes improvements to the guidance on collectability, noncash consideration, and completed contracts at transition. In addition, a practical expedient is provided for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The fourth update affects narrow aspects of the guidance as issued to date. The combined amendments do not change the core principles of the guidance in Topic 606. Management plans to adopt all of these updates at the required adoption date, which is for interim and annual reporting periods commencing January 2018. Management has substantially completed the evaluation of the sources of revenue and are currently assessing the effect of the new guidance on the financial position, results of operations and cash flows. The assessment is contingent, in part, upon the completion of deliberations currently in progress by the utility industry, notably in connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants (“AICPA”). In association with this undertaking, the AICPA formed a number of industry task forces, including a Power & Utilities (“P&U”) Task Force, on which Company personnel actively participate via formal membership. Industry representatives and organizations, the largest auditing firms, the AICPA’s Revenue Recognition Working Group and its Financial Reporting Executive Committee have undertaken, and continue to undertake, consideration of several items relevant to the utility industry. Where applicable or necessary, the FASB’s Transition Resource Group (TRG) is also participating. Currently, the industry is working to address several items including the evaluation of collectability from customers if a utility has regulatory mechanisms to help assure recovery of uncollected accounts from ratepayers and the accounting for funds received from third parties to partially or fully reimburse the cost of construction of an asset. Currently, a timeline for the resolution of these deliberations has not been established. Southwest is actively working with its peers in the rate-regulated natural gas industry and with the public accounting profession to conclude on the accounting treatment for several other issues that are not expected to be addressed by the P&U Task Force. As of December 31, 2016, the construction services segment has substantially completed the evaluation of sources of revenue and is currently assessing the effect of the new guidance on financial position, results of operations and cash flows. The principals of the new revenue recognition guidance are very similar to existing guidance for construction contractors. Similar to the P&U Task Force noted above, the AICPA formed the Engineering and Construction Contractors Task Force to assist the construction industry with implementing the new guidance. The accounting guide the AICPA intends to release is expected to provide implementation guidance related to several issues including 1) combining contracts and separating performance obligations; 2) estimating change orders, incentives, penalties, liquidated damages and other variable consideration items and 3) acceptable measures of progress when recognizing revenue over time. Given the uncertainty with respect to the conclusions that might arise from the deliberations on issues associated with both the natural gas and construction services segments, the Company is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, business processes, or the transition method it will utilize to adopt the new guidance. 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 entity 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 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. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures.
In February 2016, the FASB issued the update “Leases (Topic 842)”. Under the update, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:
Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Though companies have historically been required to make disclosures regarding leases and of contractual obligations, leases (with terms longer than a year) will no longer exist off-balance sheet. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. Early application is permitted. Management currently plans to adopt the update at the required adoption date, which is for interim and annual reporting periods commencing January 1, 2019. Existing leases have been documented by both segments and management is in the process of determining if special software will be necessary to implement the standard. In addition, management is evaluating the potential impacts of various natural gas industry-related issues in light of the leasing standard. Given the uncertainty with respect to the conclusions that might arise from these deliberations, management is currently unable to determine the effect the new guidance will have on its financial position, results of operations, cash flows, or business processes. In March 2016, the FASB issued the update “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendments are intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. The update requires the recording of all of the tax effects related to share-based payments at settlement (or expiration) through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then recorded in the income statement. While the simplification will reduce some of the administrative complexities by eliminating the need to track a “windfall pool,” it will increase the volatility of income tax expense. The update also allows entities to withhold shares for the employee tax burden up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in a liability classification of the award (currently such withholding is limited to the employer’s minimum statutory withholding). The update clarifies that all cash payments made to taxing authorities on the employees’ behalf for withheld shares should be presented as financing activities on the statement of cash flows. Also, the update requires all tax-related cash flows resulting from share-based payments be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Management issues share-based payment awards to its employees. The update was adopted by management in January 2017. In June 2016, the FASB issued the update “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. The update amends guidance on reporting credit losses for financial assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, the update eliminates the “probable” threshold for initial recognition of credit losses in current U.S. GAAP and, instead, requires an entity to reflect its current estimate of all expected credit losses. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset to present the net amount expected to be collected. For available for sale debt securities, credit losses should be measured in a manner similar to current U.S. GAAP, however the update will require that credit losses be presented as an allowance rather than as a write-down. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The update affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. All entities may adopt the amendments in this update earlier as of fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Management is evaluating what impact, if any, this update might have on its consolidated financial statements and disclosures. In August 2016, the FASB issued the update “Classification of Certain Cash Receipts and Cash Payments”. This update addresses the following specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance (“COLI”) policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows, including identification of the predominant nature in cases where cash receipts and payments have aspects of more than one class of cash flows. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Management is evaluating the impacts this update might have on its consolidated cash flow statements and disclosures. In October 2016, the FASB issued the update “Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory.” This update eliminates the current U.S. GAAP exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted; however, the guidance can only be adopted in the first interim period of a fiscal year. The modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. Management is evaluating the impacts this update might have on its consolidated financial statements. In October 2016, the FASB issued the update “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” The amendments affect reporting entities that are required to evaluate whether they should consolidate a variable interest entity in certain situations involving entities under common control. The update is effective for fiscal and interim periods beginning after December 15, 2016. Management has determined that this update is not impactful to its consolidated financial statements.
In January 2017, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The update eliminates Step 2 from the goodwill impairment test. The annual, or interim, goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. In addition, income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit should be considered when measuring the goodwill impairment loss, if applicable. The update also eliminates the requirements for any reporting unit with a zero or negative carrying amount to perform a qualitative assessment and, if it fails that qualitative test, to perform Step 2 of the goodwill impairment test. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The amendments should be applied on a prospective basis. The update is effective for fiscal and interim periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Management has determined that this update would have had no impact on the consolidated financial statements for the periods presented if it had been effective during those periods. |
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| Subsequent Events | Subsequent Events. Management 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. |
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Summary of Significant Accounting Policies (Tables) |
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| Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Other Property and Investments | Other Property and Investments. Other property and investments includes (thousands of dollars):
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| Schedule of Goodwill |
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| Estimated Fair Values of Assets Acquired as of Acquisition Date | The final estimated fair values of assets acquired as of May 6, 2016, the acquisition date, are as follows (in millions of dollars):
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| Summary of Intangible Assets | Centuri has $37.7 million and $36.8 million of intangible assets (varies due to foreign currency translation) at December 31, 2016 and 2015, respectively, as detailed in the following table (thousands of dollars):
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| Schedule of Estimated Future Amortization of Intangible Assets | 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):
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| Schedule of Capitalized and Debt Portion of AFUDC | 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.
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| 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):
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| Schedule of Earnings Per Share, Basic and Diluted | A reconciliation of the denominator used in the Basic and Diluted EPS calculations is shown in the following table.
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Utility Plant and Leases (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Net Utility Plant | Net utility plant as of December 31, 2016 and 2015 was as follows (thousands of dollars):
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| Schedule of Depreciation and Amortization Expense | Depreciation and amortization expense on gas plant, including intangibles, was as follows (thousands of dollars):
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| Schedule of Rental Payments for Operating Leases | The table below presents Southwest’s rental payments and Centuri’s lease payments that are included in operating expenses (in thousands):
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| Schedule of Future Minimum Lease Payments for Operating Leases | 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, 2016 (thousands of dollars):
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| Schedule of Capital Leases of Equipment | The amounts associated with capital leases of equipment as of December 31, 2016 and 2015 are as follows (thousands of dollars):
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| Schedule of Future Minimum Lease Payments for Capital Leases | 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, 2016 (thousands of dollars):
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Receivables and Related Allowances (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Accounts Receivable | The table below contains information about the gas utility customer accounts receivable balance (net of allowance) at December 31, 2016 and 2015, and the percentage of customers in each of the three states.
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| Schedule of Percent of Customers by State |
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| Schedule of Allowance for Uncollectibles | Activity in the allowance account for uncollectibles is summarized as follows (thousands of dollars):
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Regulatory Assets and Liabilities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulated Operations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Regulatory Assets and Liabilities | The following table represents existing regulatory assets and liabilities (thousands of dollars):
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| Schedule of Components of Other regulatory assets which are included in either Prepaids and other current assets or Deferred charges and other assets on the Consolidated Balance Sheets |
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| Schedule of Components of Other Regulatory Liabilities which are Included in either Other Current Liabilities or Deferred Credits and Other Liabilities on Consolidated Balance Sheets |
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Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) | Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss)
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| Schedule of Estimated Amounts Amortized from Accumulated Other Comprehensive Income or Regulatory Assets into Net Periodic Benefit Cost | 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):
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| Rollforward of Accumulated Other Comprehensive Income | 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)
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| Amount Recognized Before Income Tax in Accumulated Other Comprehensive Income | 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, 2016 and 2015: Amounts Recognized in AOCI (Before Tax) (Thousands of dollars)
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Long-Term Debt (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt | 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.
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| Summary of Effective Interest Rates on Variable-Rate IDRBs | The effective interest rates on Southwest’s variable-rate IDRBs are included in the table below:
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| Estimated Maturities of Long-Term Debt | Estimated maturities of long-term debt for the next five years are (in thousands):
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Pension and Other Postretirement Benefits (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cost of Retirement Plan | The cost of the plan is disclosed below (in thousands):
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| Schedule of Percentage Range of Target Portfolio | At December 31, 2016, the percentage ranges of the target portfolio are:
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| Schedule of Assumptions Used | The rates are presented in the table below:
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| Schedule of Amounts Recognized in Balance Sheet and Income Statement | 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.
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| Schedule of Accumulated Benefit Obligation | The accumulated benefit obligation for the retirement plan and the SERP is presented below (in thousands):
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| Schedule of Expected Benefit Payments | Benefits expected to be paid for pension, SERP, and PBOP over the next 10 years are as follows (in millions):
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| Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions | Components of net periodic benefit cost
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| Schedule of Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income | Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
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| Schedule of Fair Value of Plan Assets | 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, 2016 and December 31, 2015. The change in the types of pension investment holdings between years is due to the engagement of Russell and the subsequent transition of pension investments to Russell funds. The transition efforts consolidated the majority of the pension plan investments into private commingled equity and fixed income funds. The SERP has no assets.
In the prior year, Level 1 also included Common stock, Real Estate Investment Trusts, Mutual funds, and U.S. Government securities listed or regularly traded on a national securities exchange and were valued at quoted market prices as of the last business day of the calendar year.
Shares in the private equity commingled funds may be redeemed given one business day notice. While they are private equity funds and reported at NAV, due to the short redemption notice period, the lack of significant redemption fees, the fact that the underlying investments are exchange-traded, and that substantial liabilities do not exist subject to the NAV calculation, these investments are viewed as indirectly observable (level 2) and are also therefore, not excluded from the body of the fair value table as a reconciling item. Two funds are classified as international funds. One invests in international financial markets, primarily those of developed economies in Europe and the Pacific Basin. The fund invests primarily in equity securities issued by foreign corporations, but may invest in other securities perceived as offering attractive investment return opportunities. The other provides diversified exposure to global equity markets. The fund seeks to provide long-term capital growth by investing primarily in securities listed on the major developed equity markets of the United States, Europe, and Asia, as well as within those listed on emerging country equity markets on a tactical basis. The large and medium capitalization fund is designed to track the performance of the large and medium capitalization companies contained in the index, which represents approximately 90% of the market capitalization of the United States stock market. The small capitalization fund is designed to provide maximum long-term appreciation through investments that are well diversified by industry. The emerging markets fund was developed to invest in emerging market equities worldwide. The purposes of the fund’s operations, “emerging market countries” include every country in the world except the developed markets of the United States, Canada, Japan, Australia, New Zealand, Hong Kong and Singapore, and most countries located in Western Europe. Fund investments are made directly in each country or, where direct investment is inefficient or prohibited, through appropriate financial instruments or participation in commingled funds.
The U.S. corporate bond fund seeks to provide high quality, mostly corporate bond-based exposure to fixed income securities which closely match those found in discount curves used to value United States pension liabilities. The United States debt market long duration fund provides participation in the full spectrum of investment opportunities in primarily United States debt markets with longer maturities. The fund seeks to offer effective diversification against equities, take advantage of market trading opportunities, and provide a competitive rate of return on assets. The fund’s current duration is close to 14 years. The United States Treasuries securities funds seeks to replicate the risk and return characteristics of the Barclays Treasury U.S. Separate Trading of Registered Interest and Principal of Securities (“STRIPS”) 28-29 Years Index with minimum tracking error.
In the prior year, the fair value of the Level 2 investments in debt securities with remaining maturities of one year or more was 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 terms and conditions under which shares in the commingled equity funds were redeemed varied among the funds; the notice required ranged from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds required the payment of a minimal impact fee to be applied to redemptions and subscriptions of $5 million or greater; the relative fee diminished the greater the transaction. Other such funds imposed fees to recover direct costs incurred by the fund at redemption, but were indeterminable prior to redemption.
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Stock-Based Compensation (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Stock-Based Plan Compensation Expense, Including Cash Award | 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):
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| Schedule of Stock Options Activity | The following tables summarize the stock option plan activity and related information (thousands of options):
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| Schedule of Aggregate Intrinsic Value of Outstanding and Exercisable Options | The aggregate intrinsic value of outstanding and exercisable options, and options that were exercised, are presented in the table below (in thousands):
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| Summary of Market Prices of Common Stock |
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| Schedule of Nonvested Performance and Restricted Stock Unit Plans | The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2016 (thousands of shares):
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Income Taxes (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Summary of Income Before Taxes and Noncontrolling Interest for Domestic and Foreign Operations | The following is a summary of income before taxes and noncontrolling interest for domestic and foreign operations (thousands of dollars):
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| Summary of Income Tax Expense (Benefit) | Income tax expense (benefit) consists of the following (thousands of dollars):
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| Significant Components of Deferred Income Tax Expense (Benefit) | Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
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| Reconciliation of U.S Federal Statutory Rate to Consolidated Effective Tax Rate | A reconciliation of the U.S. federal statutory rate to the consolidated effective tax rate for 2014, 2015, and 2016 (and the sources of these differences and the effect of each) are summarized as follows:
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| Deferred Tax Assets and Liabilities | Deferred tax assets and liabilities consist of the following (thousands of dollars):
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| Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (thousands of dollars):
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Derivatives and Fair Value Measurements (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notional Amounts under Swaps Contracts | The differential is calculated based on the notional amounts under the contracts, which are detailed in the table below (thousands of dekatherms):
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| Amount of Gain or Losses Recognized in Income on Derivatives | The following table sets forth the gains and (losses) recognized on Southwest’s Swaps (derivatives) for the years ended December 31, 2016, 2015, and 2014 and their location in the Consolidated Statements of Income: Gains (losses) recognized in income for derivatives not designated as hedging instruments: (Thousands of dollars)
* Represents the impact of regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities. |
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| Fair Values of Swaps in Consolidated Balance Sheets | The following table sets forth the fair values of the Swaps and their location in the Consolidated Balance Sheets (thousands of dollars): Fair values of derivatives not designated as hedging instruments:
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| Paid to and Received from Counterparties for Settlements of Matured Swaps | The following table presents the amounts paid to and received from counterparties for settlements of matured Swaps.
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| Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Condensed Consolidated Balance Sheets | The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the Consolidated Balance Sheets (thousands of dollars).
|
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| Significant Other Observable Inputs | 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, 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
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Accounts Receivable for Services | Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).
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| Schedule of Revenues by Geographic Area | The following table presents the amount of revenues for both segments by geographic area (thousands of dollars):
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| Schedule of Segment Reporting Information | 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, 2016 is as follows (thousands of dollars):
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Quarterly Financial Data (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Quarterly Financial Information |
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Construction Services Noncontrolling Interests (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncontrolling Interest [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Summary of Redeemable Noncontrolling Interest | The following depicts impacts to the balance of the redeemable noncontrolling interest between the indicated periods.
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies - Additional Information (Detail) |
12 Months Ended | |||
|---|---|---|---|---|
|
May 06, 2016
USD ($)
|
Dec. 31, 2016
USD ($)
Segment
Markets
|
Dec. 31, 2015
USD ($)
|
Dec. 31, 2014
USD ($)
|
|
| Significant Accounting Policies [Line Items] | ||||
| Number of segments | Segment | 2 | |||
| Earnings from equity method investment | $ 69,000 | $ 310,000 | $ 107,000 | |
| Non-cash construction advances - non-cash investing item | 6,500,000 | 3,100,000 | 8,100,000 | |
| Non-cash investing outflow activity | 10,800,000 | |||
| Goodwill impairment charges | 0 | 0 | ||
| Purchase price paid in cash | $ 17,000,000 | |||
| Business acquisition deferred payment period | 4 years | |||
| Reduction in depreciation expense due to extension of estimates useful lives | $ 4,000,000 | |||
| Non-controlling Interest [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Non-cash investing outflow activity | $ 18,900,000 | |||
| IntelliChoice Energy, LLC [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Subsidiaries holding interest percentage | 65.00% | |||
| W.S. Nicholls Western Construction LTD. [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Investment amount | $ 10,800,000 | 10,800,000 | ||
| Dividends | 500,000 | |||
| Exposure to loss as a result of its investment | 35,800,000 | |||
| Earnings from equity method investment | $ 69,000 | |||
| Matheson-Nicholls Joint Venture [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Subsidiaries holding interest percentage | 50.00% | |||
| CCI-TBN Toronto, Inc [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Subsidiaries holding interest percentage | 25.00% | |||
| Centuri Construction Group Inc [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Ownership percentage in subsidiary | 96.60% | |||
| Intangible assets | $ 37,669,000 | 36,773,000 | ||
| Centuri Construction Group Inc [Member] | W.S. Nicholls Western Construction LTD. [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Subsidiaries holding interest percentage | 50.00% | |||
| Pooled Funds and Mutual Funds [Member] | Level 2 - Significant Other Observable Inputs [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Money market fund investments | $ 5,300,000 | 250,000 | ||
| United States [Member] | Centuri Construction Group Inc [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Number of major markets in the United States | Markets | 20 | |||
| Gas Pipe Materials and Supplies [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Gas pipe materials and operating supplies | $ 30,000,000 | $ 24,000,000 | ||
| Foreign Jurisdiction [Member] | ||||
| Significant Accounting Policies [Line Items] | ||||
| Cumulative earnings | $ 5,000,000 | |||
Summary of Significant Accounting Policies - Schedule of Other Property and Investments (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Investment [Line Items] | ||
| Net cash surrender value of COLI policies | $ 106,744,000 | $ 99,276,000 |
| Other property | 12,859,000 | 11,914,000 |
| Total | 342,343 | 313,531 |
| Centuri Construction Group Inc [Member] | ||
| Investment [Line Items] | ||
| Centuri property, equipment, and intangibles | 451,114,000 | 423,369,000 |
| Centuri accumulated provision for depreciation and amortization | $ (228,374,000) | $ (221,028,000) |
Summary of Significant Accounting Policies - Schedule of Goodwill (Detail) $ in Thousands |
12 Months Ended |
|---|---|
|
Dec. 31, 2016
USD ($)
| |
| Goodwill [Line Items] | |
| Goodwill, Beginning balance | $ 126,145 |
| Foreign currency translation adjustment | 3,112 |
| Goodwill, Ending balance | 139,983 |
| ETTI [Member] | |
| Goodwill [Line Items] | |
| Additional goodwill from ETTI acquisition | 10,726 |
| Natural Gas Operations [Member] | |
| Goodwill [Line Items] | |
| Goodwill, Beginning balance | 10,095 |
| Foreign currency translation adjustment | 0 |
| Goodwill, Ending balance | 10,095 |
| Natural Gas Operations [Member] | ETTI [Member] | |
| Goodwill [Line Items] | |
| Additional goodwill from ETTI acquisition | 0 |
| Construction Services [Member] | |
| Goodwill [Line Items] | |
| Goodwill, Beginning balance | 116,050 |
| Foreign currency translation adjustment | 3,112 |
| Goodwill, Ending balance | 129,888 |
| Construction Services [Member] | ETTI [Member] | |
| Goodwill [Line Items] | |
| Additional goodwill from ETTI acquisition | $ 10,726 |
Summary of Significant Accounting Policies - Estimated Fair Values of Assets Acquired as of Acquisition Date (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
May 06, 2016 |
Dec. 31, 2015 |
|---|---|---|---|
| Business Acquisition [Line Items] | |||
| Goodwill | $ 139,983 | $ 126,145 | |
| ETTI [Member] | |||
| Business Acquisition [Line Items] | |||
| Property, plant and equipment | $ 4,300 | ||
| Intangible assets | 2,900 | ||
| Goodwill | 10,700 | ||
| Total assets acquired | $ 17,900 |
Summary of Significant Accounting Policies - Summary of Intangible Assets (Detail) - Centuri Construction Group Inc [Member] - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Finite-Lived Intangible Assets [Line Items] | ||
| Gross Carrying Amount | $ 46,067 | $ 41,890 |
| Accumulated Amortization | (8,398) | (5,117) |
| Net Carrying Amount | 37,669 | 36,773 |
| Customer Relationships [Member] | ||
| Finite-Lived Intangible Assets [Line Items] | ||
| Gross Carrying Amount | 34,033 | 31,226 |
| Accumulated Amortization | (3,906) | (2,070) |
| Net Carrying Amount | 30,127 | 29,156 |
| Trade Names and Trademarks [Member] | ||
| Finite-Lived Intangible Assets [Line Items] | ||
| Gross Carrying Amount | 9,349 | 8,621 |
| Accumulated Amortization | (2,565) | (1,331) |
| Net Carrying Amount | 6,784 | 7,290 |
| Customer Contracts Backlog [Member] | ||
| Finite-Lived Intangible Assets [Line Items] | ||
| Gross Carrying Amount | 1,656 | 1,606 |
| Accumulated Amortization | (1,656) | (1,606) |
| Net Carrying Amount | 0 | 0 |
| Noncompete Agreement [Member] | ||
| Finite-Lived Intangible Assets [Line Items] | ||
| Gross Carrying Amount | 1,029 | 437 |
| Accumulated Amortization | (271) | (110) |
| Net Carrying Amount | $ 758 | $ 327 |
Summary of Significant Accounting Policies - Schedule of Estimated Future Amortization of Intangible Assets (Detail) $ in Thousands |
Dec. 31, 2016
USD ($)
|
|---|---|
| Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
| 2017 | $ 3,339 |
| 2018 | 3,126 |
| 2019 | 2,463 |
| 2020 | 2,395 |
| 2021 | $ 2,269 |
Summary of Significant Accounting Policies - Schedule of Capitalized and Debt Portion of AFUDC (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Public Utilities, Allowance for Funds Used During Construction, Net Increase [Abstract] | |||
| Debt portion | $ 1,175 | $ 1,666 | $ 1,228 |
| Equity portion | 2,289 | 3,008 | 1,995 |
| AFUDC capitalized as part of utility plant | $ 3,464 | $ 4,674 | $ 3,223 |
| AFUDC rate | 7.35% | 7.32% | 7.73% |
Summary of Significant Accounting Policies - Other Income (Deductions) (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Other Income and Expenses [Abstract] | |||
| Change in COLI policies | $ 7,400 | $ (500) | $ 5,300 |
| Interest income | 1,849 | 2,173 | 2,602 |
| Equity AFUDC | 2,289 | 3,008 | 1,995 |
| Foreign currency transaction gain (loss) | (22) | (824) | (178) |
| Equity in earnings of unconsolidated investment - Western | 69 | 310 | 107 |
| Miscellaneous income and (expense) | (2,116) | (1,288) | (2,719) |
| Total other income (deductions) | $ 9,469 | $ 2,879 | $ 7,107 |
Summary of Significant Accounting Policies - Schedule of Earnings Per Share, Basic and Diluted (Detail) - shares shares in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Weighted Average Number of Shares Outstanding, Diluted [Abstract] | |||
| Average basic shares | 47,469 | 46,992 | 46,494 |
| Stock options | 1 | 8 | 17 |
| Performance shares | 124 | 171 | 215 |
| Restricted stock units | 220 | 212 | 218 |
| Average diluted shares | 47,814 | 47,383 | 46,944 |
Utility Plant and Leases - Schedule of Net Utility Plant (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | $ 6,193,564 | $ 5,854,917 |
| Less: accumulated depreciation | (2,172,966) | (2,084,007) |
| Acquisition adjustments, net | 196 | 370 |
| Construction work in progress | 111,177 | 119,805 |
| Net utility plant | 4,131,971 | 3,891,085 |
| Software and Software-related Intangibles [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | 224,260 | 203,323 |
| Storage [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | 24,614 | 22,944 |
| Transmission [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | 349,981 | 312,996 |
| Distribution [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | 5,198,531 | 4,935,730 |
| General [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | 382,084 | 365,865 |
| Other [Member] | ||
| Public Utility, Property, Plant and Equipment [Line Items] | ||
| Gas plant | $ 14,094 | $ 14,059 |
Utility Plant and Leases - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Public Utility, Property, Plant and Equipment [Line Items] | |||
| Annual depreciation and amortization expense percentage | 3.60% | 3.60% | 3.60% |
| Gas, Transmission and Distribution Plant [Member] | |||
| Public Utility, Property, Plant and Equipment [Line Items] | |||
| Annual depreciation and amortization expense percentage | 3.30% | 3.30% | 3.30% |
| Gas plant [Member] | |||
| Public Utility, Property, Plant and Equipment [Line Items] | |||
| Amortization of intangibles | $ 14.8 | $ 12.7 | $ 11.7 |
Utility Plant and Leases - Schedule of Depreciation and Amortization Expense (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Public Utility, Property, Plant and Equipment [Line Items] | |||
| Depreciation and amortization expense | $ 289,132 | $ 270,111 | $ 253,027 |
| Gas plant [Member] | |||
| Public Utility, Property, Plant and Equipment [Line Items] | |||
| Depreciation and amortization expense | $ 214,037 | $ 201,233 | $ 194,360 |
Utility Plant and Leases - Schedule of Rental Payments for Operating Leases (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Rental Payments And Lease Payments Included In Operating Expenses [Line Items] | |||
| Consolidated rental payments/lease expense | $ 58,313 | $ 50,035 | $ 35,342 |
| Southwest Gas [Member] | |||
| Rental Payments And Lease Payments Included In Operating Expenses [Line Items] | |||
| Consolidated rental payments/lease expense | 4,357 | 4,186 | 5,330 |
| Centuri Construction Group Inc [Member] | |||
| Rental Payments And Lease Payments Included In Operating Expenses [Line Items] | |||
| Consolidated rental payments/lease expense | $ 53,956 | $ 45,849 | $ 30,012 |
Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Operating Leases (Detail) $ in Thousands |
Dec. 31, 2016
USD ($)
|
|---|---|
| Leases [Abstract] | |
| 2017 | $ 6,929 |
| 2018 | 4,837 |
| 2019 | 3,449 |
| 2020 | 2,411 |
| 2021 | 1,098 |
| Thereafter | 2,730 |
| Total minimum lease payments | $ 21,454 |
Utility Plant and Leases - Schedule of Capital Leases of Equipment (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Leases [Abstract] | ||
| Capital leased assets, gross | $ 3,189 | $ 4,584 |
| Less: accumulated amortization | (1,172) | (1,043) |
| Capital leased assets, net | $ 2,017 | $ 3,541 |
Utility Plant and Leases - Schedule of Future Minimum Lease Payments for Capital Leases (Detail) $ in Thousands |
Dec. 31, 2016
USD ($)
|
|---|---|
| Leases [Abstract] | |
| 2017 | $ 931 |
| 2018 | 546 |
| 2019 | 84 |
| 2020 | 0 |
| 2021 | 0 |
| Thereafter | 0 |
| Future minimum lease payments due | 1,561 |
| Less: amount representing interest | (101) |
| Total minimum lease payments | $ 1,460 |
Receivables and Related Allowances - Schedule of Accounts Receivable (Detail) - USD ($) $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Receivables [Abstract] | ||
| Gas utility customer accounts receivable balance | $ 111,320 | $ 151,775 |
Receivables and Related Allowances - Schedule of Percent of Customers by State (Detail) |
12 Months Ended |
|---|---|
Dec. 31, 2016 | |
| Arizona [Member] | |
| Receivables And Related Allowances [Line Items] | |
| Percent of customers by state | 53.00% |
| Nevada [Member] | |
| Receivables And Related Allowances [Line Items] | |
| Percent of customers by state | 37.00% |
| California [Member] | |
| Receivables And Related Allowances [Line Items] | |
| Percent of customers by state | 10.00% |
Receivables and Related Allowances - Schedule of Allowance for Uncollectibles (Detail) - Allowance for Uncollectibles [Member] - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Receivables And Related Allowances [Line Items] | |||
| Beginning Balance | $ 2,270 | $ 2,255 | $ 1,725 |
| Additions charged to expense | 3,264 | 4,113 | 4,146 |
| Accounts written off, less recoveries | (3,010) | (4,098) | (3,616) |
| Ending Balance | $ 2,524 | $ 2,270 | $ 2,255 |
Receivables and Related Allowances - Additional Information (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Receivables And Related Allowances [Line Items] | ||
| Customer accounts receivable | $ 285,145 | $ 314,512 |
| Centuri Construction Group Inc [Member] | ||
| Receivables And Related Allowances [Line Items] | ||
| Customer accounts receivable | $ 173,000 |
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | $ 477,743 | $ 488,257 |
| Net regulatory assets | 40,442 | 82,300 |
| Regulatory liabilities, total | (24,659) | (36,631) |
| Accrued Pension and Other Postretirement Benefit Costs [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 379,063 | 384,647 |
| Unrealized Net Loss on Non-trading Derivatives (Swaps) [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 0 | 5,486 |
| Regulatory liabilities, total | (4,377) | 0 |
| Deferred Purchased Gas Costs [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 2,608 | 3,591 |
| Regulatory liabilities, total | (90,476) | (45,601) |
| Accrued Purchased Gas Costs [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 37,100 | 0 |
| Regulatory liabilities, total | 0 | (10,400) |
| Unamortized Premium on Reacquired Debt [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 21,975 | 21,511 |
| Accrued Absence Time [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 13,440 | 13,240 |
| Other [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets, total | 23,557 | 59,782 |
| Accumulated Removal Costs [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory liabilities, total | (308,000) | (303,000) |
| Unamortized Gain on Reacquired Debt [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory liabilities, total | (9,789) | (10,325) |
| Other [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory liabilities, total | $ (24,659) | $ (36,631) |
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Parenthetical) (Detail) - Swaps [Member] - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Deferred Charges and Other Assets [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets and liabilities offsetting derivatives at fair value | $ 0 | $ 1,219 |
| Prepaids and Other Current Assets [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets and liabilities offsetting derivatives at fair value | 0 | 4,267 |
| Other Current Liabilities [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets and liabilities offsetting derivatives at fair value | (3,532) | 0 |
| Other Deferred Credits [Member] | ||
| Regulatory Assets And Liabilities [Line Items] | ||
| Regulatory assets and liabilities offsetting derivatives at fair value | $ (845) | $ 0 |
Regulatory Assets and Liabilities - Schedule of Components of Other Regulatory Assets are Included in either Prepaids and Other Current Assets or Deferred Credits and Other Assets on the Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Regulatory Assets [Line Items] | ||
| Regulatory assets | $ 477,743 | $ 488,257 |
| State Mandate Public Purpose Programs (Including Low Income and Conservation Programs) [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | 7,096 | 18,101 |
| Margin and Interest-Tracking Accounts [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | 3,517 | 30,339 |
| Infrastructure Replacement Programs and Similar [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | 6,976 | 6,947 |
| Environmental Compliance Programs [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | 4,329 | 2,300 |
| Other [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | 1,639 | 2,095 |
| Other Regulatory Assets [Member] | ||
| Regulatory Assets [Line Items] | ||
| Regulatory assets | $ 23,557 | $ 59,782 |
Regulatory Assets and Liabilities - Schedule of Components of Other Regulatory Assets are Included in Deferred Credits and Other Assets on the Consolidated Balance Sheets (Parenthetical) (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Regulatory Assets [Line Items] | ||
| Prepaid and other current assets | $ 136,833 | $ 95,199 |
| Deferred charges and other assets | 432,234 | 469,322 |
| Margin and Interest-Tracking Accounts [Member] | ||
| Regulatory Assets [Line Items] | ||
| Prepaid and other current assets | 11,000 | |
| Deferred charges and other assets | 19,300 | |
| Infrastructure Replacement Programs and Similar [Member] | ||
| Regulatory Assets [Line Items] | ||
| Prepaid and other current assets | 6,000 | |
| Environmental Compliance Programs [Member] | ||
| Regulatory Assets [Line Items] | ||
| Prepaid and other current assets | 3,800 | 1,800 |
| Deferred charges and other assets | 500,000 | $ 484,000 |
| Other Regulatory Assets [Member] | ||
| Regulatory Assets [Line Items] | ||
| Prepaid and other current assets | 622,000 | |
| Deferred charges and other assets | $ 1,000 |
Regulatory Assets and Liabilities - Schedule of Components of Other Regulatory Liabilities are Included in either Other Current Liabilities or Deferred Credits and Other Liabilities on Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | $ (24,659) | $ (36,631) |
| State Mandate Public Purpose Programs (Including Low Income and Conservation Programs) [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (7,101) | (4,888) |
| Margin and Interest-Tracking Accounts [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (3,668) | (20,191) |
| Environmental Compliance Programs [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (4,469) | (2,252) |
| Regulatory Offsets To Deferred Tax Balances [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (3,390) | (4,866) |
| Regulatory Accounts for Differences Related to Pension Funding [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (2,284) | (1,363) |
| Income Tax and Gross-Up [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | (3,203) | (3,067) |
| Other Regulatory Liabilities [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Regulatory liabilities | $ (544) | $ (4) |
Regulatory Assets and Liabilities - Schedule of Components of Other Regulatory Liabilities are Included in either Other Current Liabilities or Deferred Credits and Other Liabilities on Consolidated Balance Sheets (Parenthetical) (Detail) - USD ($) |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Regulatory Liabilities [Line Items] | ||
| Other current liabilities | $ 168,064,000 | $ 150,031,000 |
| Other deferred credits and other long-term liabilities | 570,252,000 | $ 591,558,000 |
| Other Regulatory Liabilities [Member] | ||
| Regulatory Liabilities [Line Items] | ||
| Other current liabilities | 536,000 | |
| Other deferred credits and other long-term liabilities | $ 8,000 |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Equity [Abstract] | |||
| Net actuarial gain/(loss), Before-Tax Amount | $ (22,770) | $ (30,519) | $ (173,646) |
| Amortization of prior service cost, Before-Tax Amount | 1,335 | 1,335 | 355 |
| Amortization of net actuarial (gain)/loss, Before-Tax Amount | 27,066 | 34,381 | 23,656 |
| Prior service cost, Before-Tax Amount | 0 | 0 | (6,661) |
| Regulatory adjustment, Before-Tax Amount | (5,584) | (5,646) | 140,308 |
| Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax | 47 | (449) | (15,988) |
| Amounts reclassified into net income, Before-Tax Amount | 3,345 | 3,344 | 3,345 |
| FSIRS other comprehensive income (loss), Before-Tax Amount | 3,345 | 3,344 | 3,345 |
| Translation adjustments, Before-Tax Amount | 161 | (1,954) | (659) |
| Foreign currency other comprehensive income (loss), Before-Tax Amount | 161 | (1,954) | (659) |
| Total other comprehensive income (loss), Before-Tax Amount | 3,553 | 941 | (13,302) |
| Net actuarial gain/(loss), Tax (Expense) or Benefit | 8,652 | 11,597 | 65,985 |
| Amortization of prior service cost, Tax (Expense) or Benefit | (507) | (507) | (135) |
| Amortization of net actuarial (gain)/loss, Tax (Expense) or Benefit | (10,285) | (13,065) | (8,989) |
| Prior service cost, Tax (Expense) or Benefit | 0 | 0 | 2,531 |
| Regulatory adjustment, Tax (Expense) or Benefit | 2,122 | 2,146 | (53,317) |
| Pension plans other comprehensive income (loss), Tax (Expense) or Benefit | (18) | 171 | 6,075 |
| Amounts reclassified into net income, Tax (Expense) or Benefit | (1,270) | (1,271) | (1,272) |
| FSIRS other comprehensive income (loss), Tax (Expense) or Benefit | (1,270) | (1,271) | (1,272) |
| Translation adjustments, Tax (Expense) or Benefit | 0 | 0 | 0 |
| Foreign currency other comprehensive income (loss), Tax (Expense) or Benefit | 0 | 0 | 0 |
| Total other comprehensive income (loss), Tax (Expense) or Benefit | (1,288) | (1,100) | 4,803 |
| Net actuarial gain/(loss), Net-of-Tax Amount | (14,118) | (18,922) | (107,661) |
| Amortization of prior service cost, Net-of-Tax Amount | 828 | 828 | 220 |
| Amortization of net actuarial (gain)/loss, Defined Benefit Plans After-Tax | 16,781 | 21,316 | 14,667 |
| Prior service cost, Net-of-Tax Amount | 0 | 0 | (4,130) |
| Regulatory adjustment, Net-of-Tax Amount | (3,462) | (3,500) | 86,991 |
| Pension plans other comprehensive income (loss), Net-of-Tax Amount | 29 | (278) | (9,913) |
| Amounts reclassified into net income (Notes 5 and 13) | 2,075 | 2,073 | 2,073 |
| FSIRS other comprehensive income (loss), Net-of-Tax Amount | 2,075 | 2,073 | 2,073 |
| Translation adjustments, Net-of-Tax Amount | 161 | (1,954) | (659) |
| Foreign currency other comprehensive income (loss), Net-of-Tax Amount | 161 | (1,954) | (659) |
| Total other comprehensive income (loss), net of tax | $ 2,265 | $ (159) | $ (8,499) |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss) (Parenthetical) (Detail) |
12 Months Ended |
|---|---|
|
Dec. 31, 2016
USD ($)
| |
| Equity [Abstract] | |
| Other comprehensive income loss, effective income tax rate | 38.00% |
| Tax expense or benefit for currency translation adjustment | $ 0 |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Schedule of Estimated Amounts Amortized from Accumulated Other Comprehensive Income or Regulatory Assets into Net Periodic Benefit Cost (Detail) $ in Thousands |
12 Months Ended |
|---|---|
|
Dec. 31, 2016
USD ($)
| |
| Qualified Retirement Plan [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| Retirement plan net actuarial loss | $ 24,000 |
| SERP [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| Retirement plan net actuarial loss | 1,500 |
| PBOP [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| PBOP prior service cost | $ 1,300 |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Additional Information (Detail) $ in Millions |
Dec. 31, 2016
USD ($)
|
|---|---|
| Equity [Abstract] | |
| Amount of FSIRS existing AOCI losses expected to reclassified income in next twelve months | $ 2.1 |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Rollforward of Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Equity [Abstract] | |||
| Beginning Balance AOCI December 31, 2015, Defined Benefit Plans Before-Tax | $ (57,660) | ||
| Net actuarial gain/(loss), Defined Benefit Plans Before-Tax | (22,770) | $ (30,519) | $ (173,646) |
| Translation adjustments, Defined Benefit Plans Before-Tax | 0 | ||
| Other comprehensive income before reclassifications, Defined Benefit Plans Before-Tax | (22,770) | ||
| Amortization of prior service cost, Defined Benefit Plans Before-Tax | 1,335 | 1,335 | 355 |
| Amortization of net actuarial loss, Defined Benefit Plans Before-Tax | 27,066 | 34,381 | 23,656 |
| Regulatory adjustment, Defined Benefit Plans Before-Tax | (5,584) | (5,646) | 140,308 |
| Net current period other comprehensive income (loss), Defined Benefit Plans Before-Tax | 47 | (449) | (15,988) |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans Before-Tax | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans Before-Tax | 47 | ||
| Ending Balance AOCI December 31, 2016, Defined Benefit Plans Before-Tax | (57,613) | (57,660) | |
| Beginning Balance AOCI December 31, 2015, Defined Benefit Plans Tax (Expense) Benefit | 21,911 | ||
| Net actuarial gain/(loss), Tax (Expense) or Benefit | 8,652 | 11,597 | 65,985 |
| Translation adjustments, Defined Benefit Plans Tax (Expense) Benefit | 0 | ||
| Other comprehensive income before reclassifications, Defined Benefit Plans Tax (Expense) Benefit | 8,652 | ||
| Amortization of prior service cost, Defined Benefit Plans Tax (Expense) Benefit | (507) | (507) | (135) |
| Amortization of net actuarial loss, Defined Benefit Plans Tax (Expense) Benefit | (10,285) | (13,065) | (8,989) |
| Regulatory adjustment, Defined Benefit Plans Tax (Expense) Benefit | 2,122 | 2,146 | (53,317) |
| Pension plans other comprehensive income (loss), Tax (Expense) or Benefit | (18) | 171 | 6,075 |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans Tax (Expense) Benefit | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans Tax (Expense) Benefit | (18) | ||
| Ending Balance AOCI December 31, 2016, Defined Benefit Plans Tax (Expense) Benefit | 21,893 | 21,911 | |
| Beginning Balance AOCI December 31, 2015, Defined Benefit Plans After-Tax | (35,749) | ||
| Net actuarial gain/(loss), Defined Benefit Plans After-Tax | (14,118) | (18,922) | (107,661) |
| Translation adjustments, Defined Benefit Plans After-Tax | 0 | ||
| Other comprehensive income before reclassifications, Defined Benefit Plans After-Tax | (14,118) | ||
| Amortization of prior service cost, Defined Benefit Plans After-Tax | 828 | 828 | 220 |
| Amortization of net actuarial (gain)/loss, Defined Benefit Plans After-Tax | 16,781 | 21,316 | 14,667 |
| Regulatory adjustment, Defined Benefit Plans After-Tax | (3,462) | ||
| Net defined benefit pension plans | 29 | (278) | (9,913) |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Defined Benefit Plans After-Tax | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Defined Benefit Plans After-Tax | 29 | ||
| Ending Balance AOCI December 31, 2016, Defined Benefit Plans After-Tax | (35,720) | (35,749) | |
| Beginning Balance AOCI December 31, 2015, FSIRS - Before-Tax | (19,344) | ||
| Translation adjustments, FSIRS - Before-Tax | 0 | ||
| Other comprehensive income before reclassifications, FSIRS - Before-Tax | 0 | ||
| FSIRS amounts reclassified from AOCI, FSIRS - Before-Tax | 3,345 | 3,344 | 3,345 |
| Net current period other comprehensive income (loss), FSIRS - Before-Tax | 3,345 | 3,344 | 3,345 |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, FSIRS - Before-Tax | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - Before-Tax | 3,345 | ||
| Ending Balance AOCI December 31, 2016, FSIRS - Before-Tax | (15,999) | (19,344) | |
| Beginning Balance AOCI December 31, 2015, FSIRS - Tax (Expense) Benefit | 7,350 | ||
| Translation adjustments, FSIRS - Tax (Expense) Benefit | 0 | ||
| Other comprehensive income before reclassifications, FSIRS - Tax (Expense) Benefit | 0 | ||
| FSIRS amounts reclassified from AOCI, FSIRS - Tax (Expense) Benefit | (1,270) | (1,271) | (1,272) |
| Net current period other comprehensive income (loss), FSIRS - Tax (Expense) Benefit | (1,270) | (1,271) | (1,272) |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, FSIRS - Tax (Expense) Benefit | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - Tax (Expense) Benefit | (1,270) | ||
| Ending Balance AOCI December 31, 2016, FSIRS - Tax (Expense) Benefit | 6,080 | 7,350 | |
| Beginning Balance AOCI December 31, 2015, FSIRS - After-Tax | (11,994) | ||
| Translation adjustments, FSIRS - After-Tax | 0 | ||
| Other comprehensive income before reclassifications | 0 | ||
| FSIRS amounts reclassified from AOCI, FSIRS - After-Tax | 2,075 | 2,073 | 2,073 |
| Net current period other comprehensive income (loss) | 2,075 | 2,073 | 2,073 |
| Less: Translation adjustment attributable to redeemable noncontrolling interest | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, FSIRS - After-Tax | 2,075 | ||
| Ending Balance AOCI December 31, 2016, FSIRS - After-Tax | (9,919) | (11,994) | |
| Beginning Balance AOCI December 31, 2015, Foreign Currency Items Before-Tax | (2,525) | ||
| Net actuarial gain/(loss) | 0 | ||
| Translation adjustments, Foreign Currency Items Before-Tax | 161 | (1,954) | (659) |
| Other comprehensive income before reclassifications | 161 | (1,954) | (659) |
| FSIRS amounts reclassified from AOCI, Foreign Currency Items Before-Tax | 0 | ||
| Amortization of prior service cost, Foreign Currency Items Before-Tax | 0 | ||
| Amortization of net actuarial loss, Foreign Currency Items Before-Tax | 0 | ||
| Regulatory adjustment, Foreign Currency Items Before-Tax | 0 | ||
| Net current period other comprehensive income (loss) | 161 | ||
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency Items Before-Tax | 5 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items Before-Tax | 156 | (1,888) | (637) |
| Ending Balance AOCI December 31, 2016 | (2,369) | (2,525) | |
| Beginning Balance AOCI December 31, 2015, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Net actuarial gain/(loss) | 0 | ||
| Translation adjustments, Foreign Currency items - Tax (Expense) Benefit | 0 | 0 | 0 |
| Other comprehensive income before reclassifications, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| FSIRS amounts reclassified from AOCI, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Amortization of prior service cost ,Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Amortization of net actuarial loss, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Regulatory adjustment, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Net current period other comprehensive income (loss), Foreign Currency items - Tax (Expense) Benefit | 0 | 0 | 0 |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency items - Tax (Expense) Benefit | 0 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency items - Tax (Expense) Benefit | 0 | 0 | 0 |
| Ending Balance AOCI December 31, 2016, Foreign Currency items - Tax (Expense) Benefit | 0 | 0 | |
| Beginning Balance AOCI December 31, 2015, Foreign Currency items - After-Tax | (2,525) | ||
| Net actuarial gain (loss) | 0 | ||
| Translation adjustments, Foreign Currency items - After-Tax | 161 | (1,954) | (659) |
| Other comprehensive income before reclassifications, Foreign Currency items - After-Tax | 161 | (1,954) | (659) |
| FSIRS amounts reclassified from AOCI, Foreign Currency items - After-Tax | 0 | ||
| Amortization of prior service cost, Foreign Currency items - After-Tax | 0 | ||
| Amortization of net actuarial loss, Foreign Currency items - After-Tax | 0 | ||
| Regulatory adjustment, Foreign Currency items - After-Tax | 0 | ||
| Net current period other comprehensive income (loss), Foreign Currency items - After-Tax | 161 | ||
| Less: Translation adjustment attributable to redeemable noncontrolling interest, Foreign Currency items - After-Tax | 5 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, Foreign Currency Items - After-Tax | 156 | ||
| Ending Balance AOCI December 31, 2016, Foreign Currency items - After-Tax | (2,369) | (2,525) | |
| Beginning Balance AOCI December 31, 2015, AOCI | (50,268) | ||
| Net actuarial gain (loss) | (14,118) | (18,922) | (107,661) |
| Translation adjustments, AOCI | 161 | ||
| Other comprehensive income before reclassifications, AOCI | (13,957) | ||
| Amounts reclassified into net income (Notes 5 and 13) | 2,075 | 2,073 | 2,073 |
| Amortization of prior service cost, AOCI | 828 | 828 | 220 |
| Amortization of net actuarial loss | 16,781 | 21,316 | 14,667 |
| Regulatory adjustment, AOCI | (3,462) | ||
| Total other comprehensive income (loss), net of tax | 2,265 | (159) | $ (8,499) |
| Less: Translation adjustment attributable to redeemable noncontrolling interest, AOCI | 5 | ||
| Net current period other comprehensive income (loss) attributable to Southwest Gas Corporation, AOCI | 2,260 | ||
| Ending Balance AOCI December 31, 2016, AOCI | $ (48,008) | $ (50,268) | |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Rollforward of Accumulated Other Comprehensive Income (Parenthetical) (Detail) |
12 Months Ended |
|---|---|
Dec. 31, 2016 | |
| Equity [Abstract] | |
| Other comprehensive income loss, effective income tax rate | 38.00% |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Amount Recognized Before Income Tax Associated with Defined Benefit Plans in Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
| Less: amount recognized in regulatory assets | $ 477,743 | $ 488,257 |
| Recognized in AOCI | (57,613) | (57,660) |
| Defined Benefit Plans [Member] | ||
| Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
| Net actuarial (loss) gain | (430,973) | (435,269) |
| Prior service cost | (5,703) | (7,038) |
| Less: amount recognized in regulatory assets | 379,063 | 384,647 |
| Recognized in AOCI | $ (57,613) | $ (57,660) |
Common Stock - Additional Information (Detail) - USD ($) |
12 Months Ended | 22 Months Ended | |||
|---|---|---|---|---|---|
Mar. 10, 2015 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2016 |
|
| Value of common stock | $ 100,000,000 | ||||
| Net proceeds to Company | $ 472,000 | $ 35,396,000 | $ 405,000 | ||
| Common stock issued through Stock Incentive Plan, Restricted Stock/Unit Plan, and Management Incentive Plan | 105,000 | ||||
| BNY Mellon Capital Markets, LLC [Member] | |||||
| Common stock sold through agent | 0 | 645,225 | |||
| Net proceeds to Company | $ 35,167,584 | ||||
| Agent commissions | $ 355,228 | ||||
Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Sep. 30, 2016 |
Dec. 31, 2015 |
|---|---|---|---|
| Long-term Debt, Current and Noncurrent Abstract | |||
| Less: current maturities | $ (50,101) | $ (19,475) | |
| Long-term debt, less current maturities | 1,549,983 | 1,551,204 | |
| Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | 50,000 | 50,000 | |
| Carrying Amount [Member] | |||
| Debt Instrument [Line Items] | |||
| Unamortized debt issuance costs | (516) | (692) | |
| Total long-term debt | 1,600,084 | 1,570,679 | |
| Long-term Debt, Current and Noncurrent Abstract | |||
| Less: current maturities | (50,101) | (19,475) | |
| Long-term debt, less current maturities | 1,549,983 | 1,551,204 | |
| Total long-term debt | 1,600,084 | 1,570,679 | |
| Carrying Amount [Member] | Centuri Secured Revolving Credit Facility [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri term loan/secured revolving credit facility | 41,185 | 60,627 | |
| Carrying Amount [Member] | IDRBs [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri term loan/secured revolving credit facility | 106,184 | 111,879 | |
| Unsecured debt | 197,511 | 320,909 | |
| Carrying Amount [Member] | Centuri Term Loan Facility [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri term loan/secured revolving credit facility | 106,700 | 112,571 | |
| Carrying Amount [Member] | Centuri Other Debt Obligations [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri other debt obligations | 52,635 | 25,901 | |
| Carrying Amount [Member] | Debentures [Member] | |||
| Debt Instrument [Line Items] | |||
| Unamortized discount and debt issuance costs | (9,931) | (6,137) | |
| Notes payable | 1,197,569 | 901,363 | |
| Carrying Amount [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 125,000 | 125,000 | |
| Carrying Amount [Member] | Debentures [Member] | Notes, 6.1%, due 2041 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 125,000 | 125,000 | |
| Carrying Amount [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 250,000 | 250,000 | |
| Carrying Amount [Member] | Debentures [Member] | Notes, 4.875%, due 2043 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 250,000 | 250,000 | |
| Carrying Amount [Member] | Debentures [Member] | Notes, 3.8%, due 2046 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 300,000 | $ 300,000 | 0 |
| Carrying Amount [Member] | Debentures [Member] | 8% Series, due 2026 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 75,000 | 75,000 | |
| Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 25,000 | 25,000 | |
| Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 25,000 | 25,000 | |
| Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 25,000 | 25,000 | |
| Carrying Amount [Member] | Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable | 7,500 | 7,500 | |
| Carrying Amount [Member] | Debentures [Member] | Revolving Credit Facility and Commercial Paper [Member] | |||
| Debt Instrument [Line Items] | |||
| Line of credit facility | 5,000 | 150,000 | |
| Carrying Amount [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 50,000 | 50,000 | |
| Carrying Amount [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 50,000 | 50,000 | |
| Carrying Amount [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 50,000 | 50,000 | |
| Carrying Amount [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 50,000 | 50,000 | |
| Carrying Amount [Member] | Fixed-Rate Bonds [Member] | |||
| Debt Instrument [Line Items] | |||
| Unamortized discount and debt issuance costs | (2,489) | (3,946) | |
| Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 0 | 100,000 | |
| Carrying Amount [Member] | Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt | 0 | 24,855 | |
| Market Value [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri term loan/secured revolving credit facility | 106,819 | 112,665 | |
| Centuri other debt obligations | 52,840 | 26,059 | |
| Market Value [Member] | Centuri Secured Revolving Credit Facility [Member] | |||
| Debt Instrument [Line Items] | |||
| Centuri term loan/secured revolving credit facility | 41,292 | 60,724 | |
| Market Value [Member] | Debentures [Member] | Notes, 4.45%, due 2020 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 129,703 | 130,273 | |
| Market Value [Member] | Debentures [Member] | Notes, 6.1%, due 2041 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 149,734 | 141,581 | |
| Market Value [Member] | Debentures [Member] | Notes, 3.875%, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 254,900 | 253,600 | |
| Market Value [Member] | Debentures [Member] | Notes, 4.875%, due 2043 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 266,793 | 251,483 | |
| Market Value [Member] | Debentures [Member] | Notes, 3.8%, due 2046 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 283,029 | 0 | |
| Market Value [Member] | Debentures [Member] | 8% Series, due 2026 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 94,691 | 97,035 | |
| Market Value [Member] | Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 25,040 | 26,253 | |
| Market Value [Member] | Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 29,290 | 29,855 | |
| Market Value [Member] | Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 31,905 | 31,890 | |
| Market Value [Member] | Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Notes payable, fair value disclosure | 8,769 | 8,684 | |
| Market Value [Member] | Debentures [Member] | Revolving Credit Facility and Commercial Paper [Member] | |||
| Debt Instrument [Line Items] | |||
| Line of credit facility, fair value | 5,000 | 150,000 | |
| Market Value [Member] | Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | 50,000 | 50,000 | |
| Market Value [Member] | Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | 50,000 | 50,000 | |
| Market Value [Member] | Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | 50,000 | 50,000 | |
| Market Value [Member] | Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | 0 | 100,452 | |
| Market Value [Member] | Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member] | |||
| Debt Instrument [Line Items] | |||
| Unsecured debt, fair value | $ 0 | $ 25,130 |
Long-Term Debt - Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt (Parenthetical) (Detail) |
1 Months Ended | 12 Months Ended | |
|---|---|---|---|
Sep. 30, 2016 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Debentures [Member] | Notes, 4.45%, due 2020 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 4.45% | 4.45% | |
| Debt instrument due date | Dec. 01, 2020 | Dec. 01, 2020 | |
| Debentures [Member] | Notes, 6.1%, due 2041 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 6.10% | 6.10% | |
| Debt instrument due date | Feb. 15, 2041 | Feb. 15, 2041 | |
| Debentures [Member] | Notes, 3.875%, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 3.875% | 3.875% | |
| Debt instrument due date | Apr. 01, 2022 | Apr. 01, 2022 | |
| Debentures [Member] | Notes, 4.875%, due 2043 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 4.875% | 4.875% | |
| Debt instrument due date | Oct. 01, 2043 | Oct. 01, 2043 | |
| Debentures [Member] | Notes, 3.8%, due 2046 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 3.80% | 3.80% | |
| Debt instrument due date | Sep. 30, 2046 | Sep. 30, 2046 | |
| Debentures [Member] | 8% Series, due 2026 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 8.00% | 8.00% | |
| Debt instrument due date | Aug. 01, 2026 | Aug. 01, 2026 | |
| Debentures [Member] | Medium-term notes, 7.59% series, due 2017 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 7.59% | 7.59% | |
| Debt instrument due date | Jan. 17, 2017 | Jan. 17, 2017 | |
| Debentures [Member] | Medium-term notes, 7.78% series, due 2022 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 7.78% | 7.78% | |
| Debt instrument due date | Feb. 03, 2022 | Feb. 03, 2022 | |
| Debentures [Member] | Medium-term notes, 7.92% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 7.92% | 7.92% | |
| Debt instrument due date | Jun. 24, 2027 | Jun. 24, 2027 | |
| Debentures [Member] | Medium-term notes, 6.76% series, due 2027 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 6.76% | 6.76% | |
| Debt instrument due date | Sep. 24, 2027 | Sep. 24, 2027 | |
| Variable-rate bonds [Member] | Tax-exempt Series A, due 2028 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument due date | Dec. 01, 2028 | Dec. 01, 2028 | |
| Variable-rate bonds [Member] | 2003 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument due date | Mar. 01, 2038 | Mar. 01, 2038 | |
| Variable-rate bonds [Member] | 2008 Series A, due 2038 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument due date | Mar. 01, 2038 | Mar. 01, 2038 | |
| Fixed-Rate Bonds [Member] | 4.85% 2005 Series A, due 2035 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 4.85% | ||
| Debt instrument due date | Oct. 01, 2035 | ||
| Fixed-Rate Bonds [Member] | 4.75% 2006 Series A, due 2036 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument interest rate | 4.75% | ||
| Debt instrument due date | Sep. 01, 2036 | ||
| Market Value [Member] | Variable-rate bonds [Member] | 2009 Series A, due 2039 [Member] | |||
| Debt Instrument [Line Items] | |||
| Debt instrument due date | Dec. 01, 2039 | Dec. 01, 2039 | |
Long-Term Debt - Additional Information (Detail) - USD ($) |
1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
|---|---|---|---|---|---|---|---|---|
Jan. 31, 2017 |
Sep. 30, 2016 |
Jul. 31, 2016 |
Feb. 29, 2016 |
Sep. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Debt Instrument [Line Items] | ||||||||
| Line of credit designated for working capital purposes | $ 150,000,000 | |||||||
| Minimum current borrowing usage | $ 0 | |||||||
| Maximum current borrowing usage | $ 230,000,000 | |||||||
| Debt instrument covenant description | Certain 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, 2016, the Company is in compliance with all of its covenants. | |||||||
| Issuance of additional debt | $ 2,300,000,000 | |||||||
| Minimum net worth | 1,100,000,000 | |||||||
| Short-Term Credit Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Borrowings outstanding under facility | $ 0 | $ 18,000,000 | ||||||
| Secured Revolving Credit and Term Loan Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Minimum current borrowing usage | $ 36,200,000 | |||||||
| Maximum current borrowing usage | $ 83,200,000 | |||||||
| Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Commitment fee | 0.15% | |||||||
| Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Commitment fee | 0.40% | |||||||
| Centuri Secured Revolving Credit Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Effective interest rate | 2.63% | |||||||
| Debentures [Member] | Carrying Amount [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Notes payable | $ 1,197,569,000 | $ 901,363,000 | ||||||
| Centuri Construction Group Inc [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument covenant description | Certain Centuri debt instruments also have leverage ratio caps and fixed charge ratio coverage requirements. At December 31, 2016, Centuri is in compliance with all of its covenants. | |||||||
| Issuance of additional debt | $ 145,000,000 | |||||||
| Equity cushion relating to minimum fixed charge ratio coverage requirement | 21,000,000 | |||||||
| Centuri Construction Group Inc [Member] | Secured Revolving Credit and Term Loan Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Credit facility maximum borrowing capacity | $ 300,000,000 | |||||||
| Credit facility expiration date | Oct. 31, 2019 | |||||||
| Debt secured by assets | $ 445,000,000 | |||||||
| Centuri Construction Group Inc [Member] | Centuri Secured Revolving Credit Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Credit facility maximum borrowing capacity | $ 150,000,000 | |||||||
| LIBOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 1.00% | |||||||
| LIBOR [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 2.25% | |||||||
| Canadian Dealer Offered Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 1.00% | |||||||
| Canadian Dealer Offered Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 2.25% | |||||||
| Alternate Base Rate or Canadian Base Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Minimum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 0.00% | |||||||
| Alternate Base Rate or Canadian Base Rate [Member] | Secured Revolving Credit and Term Loan Facility [Member] | Maximum [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 1.25% | |||||||
| 4.85% 2005 Series A, due 2035 [Member] | Fixed-Rate Bonds [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument interest rate | 4.85% | |||||||
| Debt instrument due date | Oct. 01, 2035 | |||||||
| 4.85% 2005 Series A, due 2035 [Member] | Fixed-Rate Bonds [Member] | Carrying Amount [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Unsecured debt | $ 0 | $ 100,000,000 | ||||||
| 4.85% 2005 Series A, due 2035 [Member] | Early Redemption of Debt [Member] | Fixed-Rate Bonds [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Unsecured debt | $ 100,000,000 | |||||||
| Debt instrument, original debt due date of debt year | 2035 | |||||||
| Debt instrument interest rate | 4.85% | |||||||
| 4.75% 2006 Series A, due 2036 [Member] | Fixed-Rate Bonds [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument interest rate | 4.75% | |||||||
| Debt instrument due date | Sep. 01, 2036 | |||||||
| 4.75% 2006 Series A, due 2036 [Member] | Fixed-Rate Bonds [Member] | Carrying Amount [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Unsecured debt | $ 0 | $ 24,855,000 | ||||||
| 4.75% 2006 Series A, due 2036 [Member] | Early Redemption of Debt [Member] | Fixed-Rate Bonds [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Unsecured debt | $ 24,900,000 | $ 24,900,000 | ||||||
| Debt instrument, original debt due date of debt year | 2036 | |||||||
| Debt instrument interest rate | 4.75% | 4.75% | ||||||
| Southwest Gas Credit Facility [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Credit facility maximum borrowing capacity | $ 300,000,000 | |||||||
| Line of credit designated as long term debt | 150,000,000 | |||||||
| Line of credit designated for working capital purposes | $ 150,000,000 | |||||||
| Credit facility expiration date | Mar. 01, 2021 | |||||||
| Effective interest rate | 5.21% | |||||||
| Southwest Gas Credit Facility [Member] | Long-term Debt [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Borrowings outstanding under facility | $ 5,000,000 | |||||||
| Southwest Gas Credit Facility [Member] | Before Amendment [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Previous credit facility expiration date | Mar. 01, 2020 | |||||||
| Southwest Gas Credit Facility [Member] | LIBOR [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 1.00% | |||||||
| Southwest Gas Credit Facility [Member] | Alternative Base Rate [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Applicable margin | 0.00% | |||||||
| Commercial Paper Program [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Credit facility maximum borrowing capacity | $ 50,000,000 | |||||||
| Borrowings outstanding under facility | $ 0 | |||||||
| Notes, 3.8%, due 2046 [Member] | Debentures [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument interest rate | 3.80% | 3.80% | 3.80% | |||||
| Debt instrument due date | Sep. 30, 2046 | Sep. 30, 2046 | ||||||
| Debt instrument discount percent at issuance | 0.302% | 0.302% | ||||||
| Notes, 3.8%, due 2046 [Member] | Debentures [Member] | Carrying Amount [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Notes payable | $ 300,000,000 | $ 300,000,000 | $ 300,000,000 | $ 0 | ||||
| Centuri Term Loan Facility [Member] | Centuri Construction Group Inc [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Credit facility, face amount | $ 150,000,000 | |||||||
| Medium-term notes, 7.59% series, due 2017 [Member] | Debentures [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument interest rate | 7.59% | 7.59% | ||||||
| Debt instrument due date | Jan. 17, 2017 | Jan. 17, 2017 | ||||||
| Medium-term notes, 7.59% series, due 2017 [Member] | Debentures [Member] | Carrying Amount [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Notes payable | $ 25,000,000 | $ 25,000,000 | ||||||
| Medium-term notes, 7.59% series, due 2017 [Member] | Subsequent Event [Member] | ||||||||
| Debt Instrument [Line Items] | ||||||||
| Debt instrument interest rate | 7.59% | |||||||
| Repayments of medium term notes | $ 25,000,000 | |||||||
Long-Term Debt - Summary of Effective Interest Rates on Variable-Rate IDRBs (Detail) |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| 2003 Series A, due 2038 [Member] | ||
| Debt Instrument [Line Items] | ||
| Effective interest rates | 1.47% | 0.87% |
| 2008 Series A, due 2038 [Member] | ||
| Debt Instrument [Line Items] | ||
| Effective interest rates | 1.53% | 0.87% |
| 2009 Series A, due 2039 [Member] | ||
| Debt Instrument [Line Items] | ||
| Effective interest rates | 1.43% | 0.75% |
| Tax-exempt Series A, due 2028 [Member] | ||
| Debt Instrument [Line Items] | ||
| Effective interest rates | 1.51% | 0.81% |
Long-Term Debt - Estimated Maturities of Long-Term Debt (Detail) $ in Thousands |
Dec. 31, 2016
USD ($)
|
|---|---|
| Debt Disclosure [Abstract] | |
| 2017 | $ 50,101 |
| 2018 | 24,082 |
| 2019 | 134,534 |
| 2020 | 134,452 |
| 2021 | $ 7,815 |
Short-Term Debt - Additional Information (Detail) - USD ($) |
12 Months Ended | |
|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Short-term Debt [Line Items] | ||
| Line of credit designated for working capital purposes | $ 150,000,000 | |
| Short-term borrowings outstanding on the credit facility | 0 | $ 18,000,000 |
| March 2021 [Member] | ||
| Short-term Debt [Line Items] | ||
| Credit facility maximum borrowing capacity | $ 300,000,000 | |
| Credit facility expiration date | Mar. 31, 2021 |
Commitments and Contingencies - Additional Information (Detail) $ in Millions |
Dec. 31, 2016
USD ($)
|
|---|---|
| Commitments and Contingencies Disclosure [Abstract] | |
| Self-insured retention amount associated with general liability claims | $ 1 |
| Additional self-insured retention amount of general liability | $ 4 |
Pension and Other Postretirement Benefits - Additional Information (Detail) $ in Millions |
3 Months Ended | 12 Months Ended | |
|---|---|---|---|
|
Dec. 31, 2016
USD ($)
|
Sep. 30, 2016
Participants
|
Dec. 31, 2016
USD ($)
|
|
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Maximum contribution of employer | 3.50% | ||
| Deferment of annual cash compensation | 100.00% | ||
| Matching contribution of employer | 3.50% | ||
| Deferred compensation payments on retirement | 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. | ||
| Additional Deferred Compensation Payment Options, period of payment, years | 5 years | ||
| Deferred compensation, percentage of multiple interest rate | 150.00% | ||
| Description of specific offer to select employees | About one-half of the approximate 800 participants subject to the offer accepted the offer, resulting in an approximate $30 million payment from pension assets paid in the fourth quarter of 2016. | ||
| Number of employees offered a lump-sum payout | Participants | 800 | ||
| Lump sum pension payment to be paid | $ 30 | ||
| Increments of changes to the discount rate, basis points | 0.25% | ||
| Future estimated funding amount | $ 39 | ||
| Maximum [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Per capita cost of covered health care benefits medical rate trend assumption | 7.00% | ||
| Minimum [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Per capita cost of covered health care benefits medical rate trend assumption | 4.50% | ||
| Qualified Retirement Plan [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Future estimated funding amount | $ 36 | ||
Pension and Other Postretirement Benefits - Cost of Retirement Plan (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |||
| Employee Investment Plan cost | $ 4,976 | $ 5,072 | $ 4,816 |
Pension and Other Postretirement Benefits - Schedule of Percentage Range of Target Portfolio (Detail) |
12 Months Ended |
|---|---|
Dec. 31, 2016 | |
| Minimum [Member] | Equity Securities [Member] | |
| Percentage of Investment in Retirement Plan [Line Items] | |
| Percentage range of investment | 63.00% |
| Minimum [Member] | Debt Securities [Member] | |
| Percentage of Investment in Retirement Plan [Line Items] | |
| Percentage range of investment | 33.00% |
| Maximum [Member] | Equity Securities [Member] | |
| Percentage of Investment in Retirement Plan [Line Items] | |
| Percentage range of investment | 67.00% |
| Maximum [Member] | Debt Securities [Member] | |
| Percentage of Investment in Retirement Plan [Line Items] | |
| Percentage range of investment | 37.00% |
| Maximum [Member] | Other Up To [Member] | |
| Percentage of Investment in Retirement Plan [Line Items] | |
| Percentage range of investment | 1.00% |
Pension and Other Postretirement Benefits - Schedule of Assumptions Used (Detail) |
12 Months Ended | |
|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | ||
| Discount rate | 4.50% | 4.50% |
| Weighted-average rate of compensation increase | 3.25% | 3.25% |
| Asset return assumption | 7.00% | 7.25% |
Pension and Other Postretirement Benefits - Schedule of Amounts Recognized in Balance Sheet and Income Statement (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Qualified Retirement Plan [Member] | |||
| Change in benefit obligations | |||
| Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO) | $ 1,044,817 | $ 1,060,240 | |
| Service cost | 22,833 | 25,123 | $ 21,360 |
| Interest cost | 46,027 | 44,229 | 43,440 |
| Actuarial loss (gain) | 8,550 | (44,553) | |
| Benefits paid | (73,874) | (40,222) | |
| Benefit obligation at end of year (PBO/PBO/APBO) | 1,048,353 | 1,044,817 | 1,060,240 |
| Change in plan assets | |||
| Market value of plan assets, beginning balance | 736,880 | 754,796 | |
| Actual return on plan assets | 39,956 | (13,694) | |
| Employer contributions | 36,000 | 36,000 | |
| Benefits paid | (73,874) | (40,222) | |
| Market value of plan assets, ending balance | 738,962 | 736,880 | 754,796 |
| Funded status at year end | $ (309,391) | $ (307,937) | |
| Weighted-average assumptions (benefit obligation) | |||
| Discount rate | 4.50% | 4.50% | |
| Weighted-average rate of compensation increase | 3.25% | 3.25% | |
| SERP [Member] | |||
| Change in benefit obligations | |||
| Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO) | $ 42,720 | $ 41,176 | |
| Service cost | 331 | 320 | 292 |
| Interest cost | 1,859 | 1,695 | 1,745 |
| Actuarial loss (gain) | 1,347 | 2,322 | |
| Benefits paid | (2,946) | (2,793) | |
| Benefit obligation at end of year (PBO/PBO/APBO) | 43,311 | 42,720 | 41,176 |
| Change in plan assets | |||
| Market value of plan assets, beginning balance | 0 | 0 | |
| Actual return on plan assets | 0 | 0 | |
| Employer contributions | 2,946 | 2,793 | |
| Benefits paid | (2,946) | (2,793) | |
| Market value of plan assets, ending balance | 0 | 0 | 0 |
| Funded status at year end | $ (43,311) | $ (42,720) | |
| Weighted-average assumptions (benefit obligation) | |||
| Discount rate | 4.50% | 4.50% | |
| Weighted-average rate of compensation increase | 3.25% | 3.25% | |
| PBOP [Member] | |||
| Change in benefit obligations | |||
| Change in benefit obligations Benefit obligation for service rendered to date at beginning of year (PBO/PBO/APBO) | $ 72,632 | $ 72,202 | |
| Service cost | 1,499 | 1,641 | 1,101 |
| Interest cost | 3,180 | 2,999 | 2,829 |
| Actuarial loss (gain) | (2,060) | (3,251) | |
| Benefits paid | (1,386) | (959) | |
| Benefit obligation at end of year (PBO/PBO/APBO) | 73,865 | 72,632 | 72,202 |
| Change in plan assets | |||
| Market value of plan assets, beginning balance | 43,584 | 44,892 | |
| Actual return on plan assets | 4,818 | (1,034) | |
| Employer contributions | 0 | 0 | |
| Benefits paid | (289) | (274) | |
| Market value of plan assets, ending balance | 48,113 | 43,584 | $ 44,892 |
| Funded status at year end | $ (25,752) | $ (29,048) | |
| Weighted-average assumptions (benefit obligation) | |||
| Discount rate | 4.50% | 4.50% | |
Pension and Other Postretirement Benefits - Schedule of Accumulated Benefit Obligation (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Qualified Retirement Plan [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Accumulated benefit obligation | $ 939,002 | $ 922,992 |
| SERP [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Accumulated benefit obligation | $ 40,852 | $ 39,270 |
Pension and Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) $ in Millions |
Dec. 31, 2016
USD ($)
|
|---|---|
| Pension [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| 2017 | $ 48.6 |
| 2018 | 50.1 |
| 2019 | 51.5 |
| 2020 | 53.2 |
| 2021 | 55.1 |
| 2022-2026 | 294.2 |
| PBOP [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| 2017 | 4.1 |
| 2018 | 4.3 |
| 2019 | 4.4 |
| 2020 | 4.5 |
| 2021 | 4.5 |
| 2022-2026 | 20.6 |
| SERP [Member] | |
| Defined Benefit Plan Disclosure [Line Items] | |
| 2017 | 2.9 |
| 2018 | 2.9 |
| 2019 | 2.9 |
| 2020 | 2.9 |
| 2021 | 2.9 |
| 2022-2026 | $ 14.4 |
Pension and Other Postretirement Benefits - Schedule of Net Periodic Benefit Cost and Weighted-Average Assumptions (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Defined Benefit Plan Disclosure [Line Items] | |||
| Net periodic benefit cost | $ 44,423 | $ 50,451 | $ 38,172 |
| Weighted-average assumptions (net benefit cost) | |||
| Discount rate | 4.50% | 4.50% | |
| Expected return on plan assets | 7.00% | 7.25% | |
| Weighted-average rate of compensation increase | 3.25% | 3.25% | |
| Qualified Retirement Plan [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Service cost | $ 22,833 | $ 25,123 | 21,360 |
| Interest cost | 46,027 | 44,229 | 43,440 |
| Expected return on plan assets | (56,558) | (57,808) | (53,342) |
| Amortization of prior service cost | 0 | 0 | 0 |
| Amortization of net actuarial loss | 25,266 | 32,743 | 22,873 |
| Net periodic benefit cost | $ 37,568 | $ 44,287 | $ 34,331 |
| Weighted-average assumptions (net benefit cost) | |||
| Discount rate | 4.50% | 4.25% | 5.00% |
| Expected return on plan assets | 7.25% | 7.75% | 7.75% |
| Weighted-average rate of compensation increase | 3.25% | 2.75% | 3.25% |
| SERP [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Service cost | $ 331 | $ 320 | $ 292 |
| Interest cost | 1,859 | 1,695 | 1,745 |
| Expected return on plan assets | 0 | 0 | 0 |
| Amortization of prior service cost | 0 | 0 | 0 |
| Amortization of net actuarial loss | 1,383 | 1,293 | 783 |
| Net periodic benefit cost | $ 3,573 | $ 3,308 | $ 2,820 |
| Weighted-average assumptions (net benefit cost) | |||
| Discount rate | 4.50% | 4.25% | 5.00% |
| Weighted-average rate of compensation increase | 3.25% | 2.75% | 3.25% |
| PBOP [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Service cost | $ 1,499 | $ 1,641 | $ 1,101 |
| Interest cost | 3,180 | 2,999 | 2,829 |
| Expected return on plan assets | (3,149) | (3,464) | (3,264) |
| Amortization of prior service cost | 1,335 | 1,335 | 355 |
| Amortization of net actuarial loss | 417 | 345 | 0 |
| Net periodic benefit cost | $ 3,282 | $ 2,856 | $ 1,021 |
| Weighted-average assumptions (net benefit cost) | |||
| Discount rate | 4.50% | 4.25% | 5.00% |
| Expected return on plan assets | 7.25% | 7.75% | 7.75% |
Pension and Other Postretirement Benefits - Schedule of Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Net actuarial loss (gain) | $ 22,770 | $ 30,519 | $ 173,646 |
| Amortization of prior service cost | (1,335) | (1,335) | (355) |
| Amortization of net actuarial loss | (27,066) | (34,381) | (23,656) |
| Prior service cost | 0 | 0 | 6,661 |
| Regulatory adjustment | 5,584 | 5,646 | (140,308) |
| Recognized in other comprehensive (income) loss | (47) | 449 | 15,988 |
| Net periodic benefit costs recognized in net income | 44,423 | 50,451 | 38,172 |
| Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss | 44,376 | 50,900 | 54,160 |
| Qualified Retirement Plan [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Net actuarial loss (gain) | 25,153 | 26,949 | 163,215 |
| Amortization of prior service cost | 0 | 0 | 0 |
| Amortization of net actuarial loss | (25,266) | (32,743) | (22,872) |
| Prior service cost | 0 | 0 | 0 |
| Regulatory adjustment | 102 | 5,214 | (129,031) |
| Recognized in other comprehensive (income) loss | (11) | (580) | 11,312 |
| Net periodic benefit costs recognized in net income | 37,568 | 44,287 | 34,331 |
| Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss | 37,557 | 43,707 | 45,643 |
| SERP [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Net actuarial loss (gain) | 1,347 | 2,322 | 5,460 |
| Amortization of prior service cost | 0 | 0 | 0 |
| Amortization of net actuarial loss | (1,383) | (1,293) | (784) |
| Prior service cost | 0 | 0 | 0 |
| Regulatory adjustment | 0 | 0 | 0 |
| Recognized in other comprehensive (income) loss | (36) | 1,029 | 4,676 |
| Net periodic benefit costs recognized in net income | 3,573 | 3,308 | 2,820 |
| Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss | 3,537 | 4,337 | 7,496 |
| PBOP [Member] | |||
| Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |||
| Net actuarial loss (gain) | (3,730) | 1,248 | 4,971 |
| Amortization of prior service cost | (1,335) | (1,335) | (355) |
| Amortization of net actuarial loss | (417) | (345) | 0 |
| Prior service cost | 0 | 0 | 6,661 |
| Regulatory adjustment | 5,482 | 432 | (11,277) |
| Recognized in other comprehensive (income) loss | 0 | 0 | 0 |
| Net periodic benefit costs recognized in net income | 3,282 | 2,856 | 1,021 |
| Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss | $ 3,282 | $ 2,856 | $ 1,021 |
Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets, including insurance contracts | $ 787,074 | $ 783,323 | |
| Assets at Fair Value [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 783,626 | 521,638 | |
| Commingled Equity Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 257,966 | |
| Insurance Company General Account Contracts (Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Contract value of insurance contracts | 3,448 | 3,719 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 24,922 | 364,610 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 7,230 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 549 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 3,402 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 42,256 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 11,395 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 30,849 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 39,059 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 30,099 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 12,708 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 26,653 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 9,312 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 5,159 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 24,922 | 111,468 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 34,478 | |
| Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Futures Contracts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | (7) | |
| Level 2 - Significant Other Observable Inputs [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 758,704 | 157,028 | |
| Level 2 - Significant Other Observable Inputs [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 31,917 | |
| Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 2,007 | |
| Level 2 - Significant Other Observable Inputs [Member] | International [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 299,808 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | Large and Medium Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 125,253 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | Small Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 26,763 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | Emerging Markets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 46,733 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | U S Corporate Bonds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 166,152 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | US Debt Market Long Duration [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 79,781 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | US Treasury Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 8,937 | 0 | |
| Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 5,105 | 15,604 | |
| Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 172 | 51,046 | |
| Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 24,243 | |
| Level 2 - Significant Other Observable Inputs [Member] | Banking [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 21,478 | |
| Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 5,042 | |
| Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 3,940 | |
| Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 978 | |
| Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 571 | |
| Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 202 | |
| Qualified Retirement Plan [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 738,962 | 736,880 | $ 754,796 |
| Fair value of plan assets, including insurance contracts | 738,962 | 739,684 | |
| Qualified Retirement Plan [Member] | Assets at Fair Value [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 735,514 | 485,454 | |
| Qualified Retirement Plan [Member] | Commingled Equity Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 250,511 | |
| Qualified Retirement Plan [Member] | Insurance Company General Account Contracts (Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Contract value of insurance contracts | 3,448 | 3,719 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 333,310 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 7,021 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 533 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 3,304 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 41,035 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 11,066 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 29,957 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 37,930 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 29,229 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 12,341 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 25,883 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 9,043 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 5,010 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 87,483 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 33,482 | |
| Qualified Retirement Plan [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Futures Contracts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | (7) | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 735,514 | 152,144 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 30,995 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 1,949 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | International [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 290,668 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Large and Medium Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 121,434 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Small Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 25,947 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Emerging Markets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 45,309 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | U S Corporate Bonds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 161,086 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | US Debt Market Long Duration [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 77,349 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | US Treasury Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 8,665 | 0 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 4,889 | 14,808 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 167 | 49,571 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 23,542 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Banking [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 20,857 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 4,896 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 3,826 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 950 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 554 | |
| Qualified Retirement Plan [Member] | Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 196 | |
| PBOP [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 48,113 | 43,584 | $ 44,892 |
| Fair value of plan assets, including insurance contracts | 48,112 | 43,639 | |
| PBOP [Member] | Assets at Fair Value [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 48,112 | 36,184 | |
| PBOP [Member] | Commingled Equity Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 7,455 | |
| PBOP [Member] | Insurance Company General Account Contracts (Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Contract value of insurance contracts | 0 | 0 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 24,922 | 31,300 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Agriculture [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 209 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Capital Equipment [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 16 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Chemicals/Materials [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 98 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Consumer Goods [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 1,221 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Energy and Mining [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 329 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Finance/Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 892 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Healthcare [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 1,129 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Information Technology [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 870 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Services [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 367 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Telecommunications/Internet/Media [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 770 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 269 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 149 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 24,922 | 23,985 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Government Fixed Income Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 996 | |
| PBOP [Member] | Level 1 - Quoted Prices in Active Markets for Identical Financial Assets [Member] | Futures Contracts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 23,190 | 4,884 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Other [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 922 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Real Estate Investment Trusts [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 58 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | International [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 9,140 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Large and Medium Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 3,819 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Small Capitalization [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 816 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Emerging Markets [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 1,424 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | U S Corporate Bonds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 5,066 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | US Debt Market Long Duration [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 2,432 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | US Treasury Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 272 | 0 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Pooled Funds and Mutual Funds [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 216 | 796 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Government Fixed Income and Mortgage Backed Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 5 | 1,475 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Asset-Backed and Mortgage-Backed [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 701 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Banking [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 621 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Insurance [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 146 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Utilities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 114 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | State and Local Obligations [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 28 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Preferred Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | 0 | 17 | |
| PBOP [Member] | Level 2 - Significant Other Observable Inputs [Member] | Convertible Securities [Member] | |||
| Defined Benefit Plan Disclosure [Line Items] | |||
| Fair value of plan assets | $ 0 | $ 6 | |
Pension and Other Postretirement Benefits - Schedule of Fair Value of Plan Assets (Parenthetical) (Detail) - USD ($) |
12 Months Ended | |
|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Defined Benefit Plan Disclosure [Line Items] | ||
| Amounts not included in funded status table | $ 2,859,000 | |
| Minimum [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Redemption request notice to prior period | 1 day | |
| Impact fee on redemptions and subscriptions of $5 million or more | 5,000,000 | |
| Maximum [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Redemption request notice to prior period | 30 days | |
| Qualified Retirement Plan [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Amounts not included in funded status table | 2,803,000 | |
| PBOP [Member] | ||
| Defined Benefit Plan Disclosure [Line Items] | ||
| Amounts not included in funded status table | $ 56,000 | |
Stock-Based Compensation - Schedule of Stock-Based Plan Compensation Expense, Including Cash Award (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
| Stock-based compensation plan expense, net of related tax benefits | $ 7,185 | $ 7,278 | $ 8,130 |
| Stock-based compensation plan related tax benefits | $ 4,404 | $ 4,461 | $ 4,983 |
Stock-Based Compensation - Additional Information (Detail) |
12 Months Ended | ||
|---|---|---|---|
|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
$ / shares
|
Dec. 31, 2014
$ / shares
|
|
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
| Options, maximum term, years | 10 years | ||
| Cash received from exercise of stock options | $ 735,000 | ||
| Tax benefit realized from exercise of stock options | $ 205,000 | ||
| Percentage of restricted stock/units vested during first year | 0.40 | ||
| Percentage of restricted stock/units vested during second and third years | 0.30 | ||
| Weighted average grant date fair value of performance shares and restricted stock/units granted | $ / shares | $ 63.09 | $ 53.73 | |
| Total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized | $ 3,300,000 | ||
Stock-Based Compensation - Schedule of Stock Options Activity (Detail) - $ / shares shares in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
| Number of options, Outstanding at the beginning of the year | 17 | 36 | 52 |
| Number of options, Exercised during the year | (17) | (19) | (16) |
| Number of options, Forfeited or expired during the year | 0 | 0 | 0 |
| Number of options, Outstanding and exercisable at year end | 0 | 17 | 36 |
| Weighted-average exercise price, Outstanding at the beginning of the year | $ 31.64 | $ 28.97 | $ 27.57 |
| Weighted-average exercise price, Exercised during the year | 31.64 | 26.69 | 24.31 |
| Weighted-average exercise price, Forfeited or expired during the year | $ 0 | 0 | 0 |
| Weighted-average exercise price, Outstanding and exercisable at year end | $ 31.64 | $ 28.97 | |
Stock-Based Compensation - Schedule of Aggregate Intrinsic Value of Outstanding and Exercisable Options (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
| Outstanding and exercisable | $ 0 | $ 394 | $ 1,194 |
| Exercised | $ 554 | $ 590 | $ 451 |
Stock-Based Compensation - Summary of Market Prices of Common Stock (Detail) - USD ($) |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|---|---|---|---|
| Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
| Market value of Company stock | $ 76.62 | $ 55.16 | $ 61.81 |
Stock-Based Compensation - Schedule of Nonvested Performance and Restricted Stock Unit Plans (Detail) - $ / shares shares in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Weighted-average grant date fair value, Granted | $ 63.09 | $ 53.73 | |
| Performance Shares [Member] | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Nonvested/unissued, Number of Units, at beginning of year | 197 | ||
| Nonvested, Number of Units, Granted | 44 | ||
| Nonvested, Number of Units, Dividends | 5 | ||
| Nonvested, Number of Units, Forfeited or expired | 0 | ||
| Nonvested, Number of Units, Vested and issued | (78) | ||
| Nonvested/unissued, Number of Units, Ending balance | 168 | 197 | |
| Weighted-average grant date fair value, Beginning balance | $ 50.63 | ||
| Weighted-average grant date fair value, Granted | 59.05 | ||
| Weighted-average grant date fair value, Dividends | 0 | ||
| Weighted-average grant date fair value, Forfeited or expired | 0 | ||
| Weighted-average grant date fair value, Vested and issued | 41.82 | ||
| Weighted-average grant date fair value, Ending balance | $ 55.62 | $ 50.63 | |
| Restricted Stock/Units [Member] | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Nonvested/unissued, Number of Units, at beginning of year | 228 | ||
| Nonvested, Number of Units, Granted | 73 | ||
| Nonvested, Number of Units, Dividends | 6 | ||
| Nonvested, Number of Units, Forfeited or expired | 0 | ||
| Nonvested, Number of Units, Vested and issued | (45) | ||
| Nonvested/unissued, Number of Units, Ending balance | 262 | 228 | |
| Weighted-average grant date fair value, Beginning balance | $ 44.36 | ||
| Weighted-average grant date fair value, Granted | 60.39 | ||
| Weighted-average grant date fair value, Dividends | 0 | ||
| Weighted-average grant date fair value, Forfeited or expired | 0 | ||
| Weighted-average grant date fair value, Vested and issued | 51.98 | ||
| Weighted-average grant date fair value, Ending balance | $ 46.41 | $ 44.36 | |
Income Taxes - Summary of Income Before Taxes and Noncontrolling Interest for Domestic and Foreign Operations (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Income Tax [Line Items] | |||
| Total income before income taxes | $ 231,523 | $ 219,332 | $ 219,521 |
| Foreign [Member] | |||
| Income Tax [Line Items] | |||
| Total income before income taxes | 12,713 | (2,328) | (1,950) |
| United States [Member] | |||
| Income Tax [Line Items] | |||
| Total income before income taxes | $ 218,810 | $ 221,660 | $ 221,471 |
Income Taxes - Summary of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Current: | |||
| Federal | $ 541 | $ 21,321 | $ 1,739 |
| State | 5,748 | 9,899 | 5,073 |
| Foreign | 4,298 | 650 | 2,193 |
| Income tax expense (benefit), Current | 10,587 | 31,870 | 9,005 |
| Deferred: | |||
| Federal | 68,270 | 51,132 | 71,439 |
| State | 140 | (2,574) | 614 |
| Foreign | (529) | (526) | (2,685) |
| Total deferred income tax expense | 67,881 | 48,032 | 69,368 |
| Total income tax expense | $ 78,468 | $ 79,902 | $ 78,373 |
Income Taxes - Significant Components of Deferred Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Deferred federal and state: | |||
| Total deferred federal and state | $ 68,719 | $ 48,893 | $ 70,229 |
| Deferred ITC, net | (838) | (861) | (861) |
| Total deferred income tax expense | 67,881 | 48,032 | 69,368 |
| Property-related Items [Member] | |||
| Deferred federal and state: | |||
| Total deferred federal and state | 76,217 | 65,931 | 52,814 |
| Purchased Gas Cost Adjustments [Member] | |||
| Deferred federal and state: | |||
| Total deferred federal and state | 361 | (32,993) | 15,049 |
| Employee Benefits [Member] | |||
| Deferred federal and state: | |||
| Total deferred federal and state | (1,327) | 623 | 109 |
| All Other Deferred [Member] | |||
| Deferred federal and state: | |||
| Total deferred federal and state | $ (6,532) | $ 15,332 | $ 2,257 |
Income Taxes - Reconciliation of U.S Federal Statutory Rate to Consolidated Effective Tax Rate (Detail) |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Income Tax Disclosure [Abstract] | |||
| U.S. federal statutory income tax rate | 35.00% | 35.00% | 35.00% |
| Net state taxes | 1.40% | 1.80% | 1.90% |
| Property-related items | 0.00% | 0.10% | 0.10% |
| Tax credits | (0.40%) | (0.40%) | (0.50%) |
| Company owned life insurance | (1.20%) | 0.10% | (1.00%) |
| All other differences | (0.90%) | (0.20%) | 0.20% |
| Consolidated effective income tax rate | 33.90% | 36.40% | 35.70% |
Income Taxes - Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Deferred tax assets: | ||
| Deferred income taxes for future amortization of ITC | $ 1,094 | $ 1,614 |
| Employee benefits | 38,231 | 36,923 |
| Alternative minimum tax credit | 4,827 | 4,809 |
| Net operating losses and credits | 1,204 | 868 |
| Interest rate swap | 6,080 | 7,351 |
| Other | 18,415 | 24,636 |
| Valuation allowance | (495) | (499) |
| Deferred tax assets, total | 69,356 | 75,702 |
| Deferred tax liabilities: | ||
| Property-related items, including accelerated depreciation | 872,136 | 794,850 |
| Regulatory balancing accounts | 1,104 | 743 |
| Unamortized ITC | 1,710 | 2,549 |
| Debt-related costs | 5,712 | 5,497 |
| Intangibles | 8,803 | 9,547 |
| Other | 19,256 | 31,533 |
| Deferred tax liabilities, total | 908,721 | 844,719 |
| Net noncurrent deferred tax liabilities | $ 839,365 | $ 769,017 |
Income Taxes - Additional Information (Detail) - USD ($) |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Income Tax Disclosure [Line Items] | |||
| Undistributed foreign earnings | $ 5,000,000 | ||
| Unrecognized tax benefits that, if recognized, would affect the effective tax rate | 935,000 | ||
| Significant increases or decreases in unrecognized tax benefit within the next 12 months | 0 | ||
| Tax-related interest income | $ 0 | $ 0 | $ 0 |
| Minimum [Member] | |||
| Income Tax Disclosure [Line Items] | |||
| Amount of benefit being recognized in financial statements upon ultimate settlement, Percentage | 50.00% | ||
| United States [Member] | |||
| Income Tax Disclosure [Line Items] | |||
| Federal net capital loss carryforward | $ 278,000 | ||
| Net capital loss carryforward expiration year | 2017 | ||
| Canada [Member] | |||
| Income Tax Disclosure [Line Items] | |||
| Federal net operating loss carryforward | $ 4,500,000 | ||
| Net operating loss carryforward expiration year | 2032 | ||
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) - USD ($) $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
| Income Tax Disclosure [Abstract] | ||
| Unrecognized tax benefits at beginning of year | $ 296 | $ 305 |
| Gross increases - tax positions in prior period | 897 | 0 |
| Gross decreases - tax positions in prior period | 0 | (9) |
| Gross increases - current period tax positions | 38 | 0 |
| Gross decreases - current period tax positions | 0 | 0 |
| Settlements | 0 | 0 |
| Lapse in statute of limitations | 0 | 0 |
| Unrecognized tax benefits at end of year | $ 1,231 | $ 296 |
Derivatives and Fair Value Measurements - Additional Information (Detail) - USD ($) |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Derivative [Line Items] | |||
| Gains (losses) recognized in income or other comprehensive income for derivative designated cash flow hedges | $ 2,075,000 | $ 2,073,000 | $ 2,073,000 |
| Derivative instrument loss at settlement amortization period | 10 years | ||
| Cash Flow Hedging [Member] | |||
| Derivative [Line Items] | |||
| Gains (losses) recognized in income or other comprehensive income for derivative designated cash flow hedges | $ 0 | ||
| Minimum [Member] | |||
| Derivative [Line Items] | |||
| Maturities of natural gas swaps | Jan. 31, 2017 | ||
| Maximum [Member] | |||
| Derivative [Line Items] | |||
| Maturities of natural gas swaps | Mar. 31, 2019 | ||
| Arizona [Member] | |||
| Derivative [Line Items] | |||
| Natural gas portfolios, maximum % rate | 25.00% | ||
| California [Member] | |||
| Derivative [Line Items] | |||
| Natural gas portfolios, maximum % rate | 25.00% | ||
Derivatives and Fair Value Measurements - Notional Amounts under Swaps Contracts (Detail) - MMBTU |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Offsetting [Abstract] | ||
| Contract notional amounts | 10,543,000 | 7,407,000 |
Derivatives and Fair Value Measurements - Amount of Gain or Losses Recognized in Income on Derivatives (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Derivative Instruments, Gain (Loss) [Line Items] | |||
| Amount of gain or (loss) recognized in income on derivative | $ 0 | $ 0 | $ 0 |
| Cash Flow Hedging [Member] | Net Cost of Gas Sold [Member] | |||
| Derivative Instruments, Gain (Loss) [Line Items] | |||
| Amount of gain or (loss) recognized in income on derivative | 5,006 | (7,598) | (2,363) |
| Regulatory Deferral Accounting Treatment [Member] | Cash Flow Hedging [Member] | Net Cost of Gas Sold [Member] | |||
| Derivative Instruments, Gain (Loss) [Line Items] | |||
| Amount of gain or (loss) recognized in income on derivative | $ (5,006) | $ 7,598 | $ 2,363 |
Derivatives and Fair Value Measurements - Fair Values of Swaps in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Derivatives, Fair Value [Line Items] | ||
| Asset derivatives not designated as hedging instruments | $ 4,450 | $ 4 |
| Liability derivatives not designated as hedging instruments | (73) | (5,490) |
| Net total not designated as hedging instruments | 4,377 | (5,486) |
| Swaps [Member] | Deferred Charges and Other Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Asset derivatives not designated as hedging instruments | 899 | |
| Liability derivatives not designated as hedging instruments | (54) | |
| Net total not designated as hedging instruments | 845 | |
| Swaps [Member] | Prepaids and Other Current Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Asset derivatives not designated as hedging instruments | 3,551 | |
| Liability derivatives not designated as hedging instruments | (19) | |
| Net total not designated as hedging instruments | $ 3,532 | |
| Swaps [Member] | Other Current Liabilities [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Asset derivatives not designated as hedging instruments | 0 | |
| Liability derivatives not designated as hedging instruments | (4,267) | |
| Net total not designated as hedging instruments | (4,267) | |
| Swaps [Member] | Other Deferred Credits [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Asset derivatives not designated as hedging instruments | 4 | |
| Liability derivatives not designated as hedging instruments | (1,223) | |
| Net total not designated as hedging instruments | $ (1,219) |
Derivatives and Fair Value Measurements - Paid to and Received from Counterparties for Settlements of Matured Swaps (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
| Paid to counterparties | $ 5,583 | $ 7,537 | $ 829 |
| Received from counterparties | $ 726 | $ 0 | $ 4,713 |
Derivatives and Fair Value Measurements - Regulatory Assets/Liabilities Offsetting Derivatives at Fair Value in Condensed Consolidated Balance Sheets (Detail) - Swaps [Member] - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Other Deferred Credits [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Net Total | $ (845) | |
| Other Current Liabilities [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Net Total | $ (3,532) | |
| Prepaids and Other Current Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Net Total | $ 4,267 | |
| Deferred Charges and Other Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Net Total | $ 1,219 |
Derivatives and Fair Value Measurements - Significant Other Observable Inputs (Detail) - Level 2 - Significant Other Observable Inputs [Member] - Swaps [Member] - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Derivatives, Fair Value [Line Items] | ||
| Net Assets (Liabilities) | $ 4,377 | $ (5,486) |
| Prepaids and Other Current Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Derivative Assets | 3,532 | 0 |
| Deferred Charges and Other Assets [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Derivative Assets | 845 | 0 |
| Other Current Liabilities [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Derivative Liabilities | 0 | (4,267) |
| Other Deferred Credits [Member] | ||
| Derivatives, Fair Value [Line Items] | ||
| Derivative Liabilities | $ 0 | $ (1,219) |
Segment Information - Additional Information (Detail) |
12 Months Ended |
|---|---|
Dec. 31, 2016 | |
| Net Assets, Geographic Area [Member] | Geographic Concentration Risk [Member] | United States [Member] | Minimum [Member] | |
| Segment Reporting Information [Line Items] | |
| Long-lived assets | 99.00% |
Segment Information - Accounts Receivable for Services (Detail) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
|---|---|---|
| Centuri Construction Group Inc [Member] | ||
| Segment Reporting Information [Line Items] | ||
| Accounts receivable for Centuri services | $ 10,585 | $ 10,006 |
Segment Information - Schedule of Revenues by Geographic Area (Detail) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
Sep. 30, 2015 |
Jun. 30, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total Revenues | $ 641,525 | $ 539,969 | $ 547,748 | $ 731,248 | $ 685,405 | $ 505,396 | $ 538,604 | $ 734,220 | $ 627,683 | $ 432,475 | $ 453,153 | $ 608,396 | $ 2,460,490 | $ 2,463,625 | $ 2,121,707 |
| United States [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total Revenues | 2,256,600 | 2,289,133 | 2,069,513 | ||||||||||||
| Canada [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total Revenues | $ 203,890 | $ 174,492 | $ 52,194 | ||||||||||||
Segment Information - Schedule of Segment Reporting Information (Detail) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
Sep. 30, 2015 |
Jun. 30, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total operating revenues | $ 641,525 | $ 539,969 | $ 547,748 | $ 731,248 | $ 685,405 | $ 505,396 | $ 538,604 | $ 734,220 | $ 627,683 | $ 432,475 | $ 453,153 | $ 608,396 | $ 2,460,490 | $ 2,463,625 | $ 2,121,707 |
| Interest revenue | 1,849 | 2,173 | 2,602 | ||||||||||||
| Interest expense | 73,660 | 71,879 | 72,069 | ||||||||||||
| Depreciation and amortization | 289,132 | 270,111 | 253,027 | ||||||||||||
| Income tax expense | 78,468 | 79,902 | 78,373 | ||||||||||||
| Segment net income | 65,180 | $ 2,472 | $ 8,943 | $ 75,446 | 66,119 | $ (4,734) | $ 4,949 | $ 71,983 | 58,746 | $ 1,970 | $ 9,627 | $ 70,783 | 152,041 | 138,317 | 141,126 |
| Segment assets | 5,581,126 | 5,358,685 | 5,208,297 | 5,581,126 | 5,358,685 | 5,208,297 | |||||||||
| Capital expenditures | 529,531 | 488,000 | 396,898 | ||||||||||||
| Revenues from unaffiliated customers [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | 2,362,369 | 2,359,509 | 2,029,519 | ||||||||||||
| Intersegment sales [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | 98,121 | 104,116 | 92,188 | ||||||||||||
| Natural Gas Operations [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total operating revenues | 1,321,412 | 1,454,639 | 1,382,087 | ||||||||||||
| Interest revenue | 1,848 | 1,754 | 2,596 | ||||||||||||
| Interest expense | 66,997 | 64,095 | 68,299 | ||||||||||||
| Depreciation and amortization | 233,463 | 213,455 | 204,144 | ||||||||||||
| Income tax expense | 58,584 | 61,355 | 63,597 | ||||||||||||
| Segment net income | 119,423 | 111,625 | 116,872 | ||||||||||||
| Segment assets | 5,001,756 | 4,822,845 | 4,652,307 | 5,001,756 | 4,822,845 | 4,652,307 | |||||||||
| Capital expenditures | 457,120 | 438,289 | 350,025 | ||||||||||||
| Natural Gas Operations [Member] | Revenues from unaffiliated customers [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | 1,321,412 | 1,454,639 | 1,382,087 | ||||||||||||
| Natural Gas Operations [Member] | Intersegment sales [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | 0 | 0 | 0 | ||||||||||||
| Construction Services [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Total operating revenues | 1,139,078 | 1,008,986 | 739,620 | ||||||||||||
| Interest revenue | 1 | 419 | 6 | ||||||||||||
| Interest expense | 6,663 | 7,784 | 3,770 | ||||||||||||
| Depreciation and amortization | 55,669 | 56,656 | 48,883 | ||||||||||||
| Income tax expense | 19,884 | 18,547 | 14,776 | ||||||||||||
| Segment net income | 32,618 | 26,692 | 24,254 | ||||||||||||
| Segment assets | $ 579,370 | $ 535,840 | 566,589 | 579,370 | 535,840 | 566,589 | |||||||||
| Capital expenditures | 72,411 | 49,711 | 46,873 | ||||||||||||
| Construction Services [Member] | Revenues from unaffiliated customers [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | 1,040,957 | 904,870 | 647,432 | ||||||||||||
| Construction Services [Member] | Intersegment sales [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Revenues | $ 98,121 | $ 104,116 | 92,188 | ||||||||||||
| Adjustments [Member] | |||||||||||||||
| Segment Reporting Information [Line Items] | |||||||||||||||
| Segment assets | $ (10,599) | $ (10,599) | |||||||||||||
Segment Information - Schedule of Segment Reporting Information (Parenthetical) (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Segment Reporting Information [Line Items] | |||
| Long-term deferred tax benefit | $ 67,881 | $ 48,032 | $ 69,368 |
| Natural Gas Operations [Member] | |||
| Segment Reporting Information [Line Items] | |||
| Deferred income tax liability | 4,500 | ||
| Construction Services [Member] | |||
| Segment Reporting Information [Line Items] | |||
| Income tax payable netted | 3,300 | ||
| Deferred income tax liability | 1,400 | ||
| Long-term deferred tax benefit | $ 1,400 | ||
Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2016 |
Sep. 30, 2016 |
Jun. 30, 2016 |
Mar. 31, 2016 |
Dec. 31, 2015 |
Sep. 30, 2015 |
Jun. 30, 2015 |
Mar. 31, 2015 |
Dec. 31, 2014 |
Sep. 30, 2014 |
Jun. 30, 2014 |
Mar. 31, 2014 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||
| Operating revenues | $ 641,525 | $ 539,969 | $ 547,748 | $ 731,248 | $ 685,405 | $ 505,396 | $ 538,604 | $ 734,220 | $ 627,683 | $ 432,475 | $ 453,153 | $ 608,396 | $ 2,460,490 | $ 2,463,625 | $ 2,121,707 |
| Operating income | 117,963 | 15,539 | 28,116 | 134,096 | 117,586 | 16,143 | 25,047 | 129,556 | 112,373 | 18,290 | 26,755 | 127,065 | 295,714 | 288,332 | 284,483 |
| Net income (loss) | 65,694 | 2,907 | 9,099 | 75,355 | 66,698 | (4,210) | 5,063 | 71,879 | 58,897 | 1,927 | 9,627 | 70,697 | 153,055 | 139,430 | 141,148 |
| Net income (loss) attributable to Southwest Gas Corporation | $ 65,180 | $ 2,472 | $ 8,943 | $ 75,446 | $ 66,119 | $ (4,734) | $ 4,949 | $ 71,983 | $ 58,746 | $ 1,970 | $ 9,627 | $ 70,783 | $ 152,041 | $ 138,317 | $ 141,126 |
| Basic earnings (loss) per common share | $ 1.37 | $ 0.05 | $ 0.19 | $ 1.59 | $ 1.40 | $ (0.10) | $ 0.11 | $ 1.54 | $ 1.26 | $ 0.04 | $ 0.21 | $ 1.52 | $ 3.20 | $ 2.94 | $ 3.04 |
| Diluted earnings (loss) per common share | $ 1.36 | $ 0.05 | $ 0.19 | $ 1.58 | $ 1.38 | $ (0.10) | $ 0.10 | $ 1.53 | $ 1.25 | $ 0.04 | $ 0.21 | $ 1.51 | $ 3.18 | $ 2.92 | $ 3.01 |
Construction Services Noncontrolling Interests - Additional Information (Detail) |
1 Months Ended | 12 Months Ended |
|---|---|---|
Oct. 31, 2014 |
Dec. 31, 2016 |
|
| Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | ||
| Noncontrolling Interest [Line Items] | ||
| Equity interest percentage | 10.00% | |
| Description of equity interest | Associated with the agreement reached in conjunction with the acquisition of the Canadian construction businesses in October 2014, the previous owners of the acquired companies initially retained an approximate 10% equity interest in the Canadian-specific businesses, and 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 are currently eligible to exit their investment retained by requiring the purchase of a portion of their interest and in incremental amounts annually. 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. | |
| Equity interest dividend rights, percentage of dividends paid by Centuri | 3.40% | |
| Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Construction Services [Member] | ||
| Noncontrolling Interest [Line Items] | ||
| Equity interest exchangeable percentage in Centuri | 3.40% | |
| Percentage of earnings attribution by Centuri to previous owners | 3.40% | |
| Principal Previous Owners [Member] | Link-Line and WS Nicholls [Member] | Construction Services [Member] | Maximum [Member] | ||
| Noncontrolling Interest [Line Items] | ||
| Percentage of retained interest may elect to sell to centuri | 100.00% | |
| IntelliChoice Energy, LLC [Member] | ||
| Noncontrolling Interest [Line Items] | ||
| Subsidiaries holding interest percentage | 65.00% |
Construction Services Noncontrolling Interests - Summary of Redeemable Noncontrolling Interest (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
| Redeemable Noncontrolling Interest [Line Items] | |||
| Balance, December 31, 2015 | $ 16,108 | ||
| Balance, December 31, 2016 | 22,590 | $ 16,108 | |
| Redeemable Noncontrolling Interest (Temporary Equity) [Member] | |||
| Redeemable Noncontrolling Interest [Line Items] | |||
| Balance, December 31, 2015 | 16,108 | 20,042 | |
| Net Income (loss) attributable to redeemable noncontrolling interest | 1,148 | 939 | $ 151 |
| Foreign currency exchange translation adjustment | 5 | (66) | (22) |
| Centuri distribution to redeemable noncontrolling interest | (439) | (99) | |
| Adjustment to redemption value | 5,768 | ||
| Balance, December 31, 2016 | $ 22,590 | $ 16,108 | $ 20,042 |