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, 2012
Commission File Number 1-7850
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) |
Registrants 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 | |
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 ü No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No ü
Indicate by check mark whether the 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 ü No
Indicate by check mark whether the 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 ü 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 registrants 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 ü |
Accelerated filer |
Non-accelerated filer |
Smaller reporting company |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No ü
Aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant:
$2,013,502,347 as of June 30, 2012
The number of shares outstanding of common stock:
Common Stock, $1 Par Value, 46,294,796 shares as of February 15, 2013
DOCUMENTS INCORPORATED BY REFERENCE
Description |
Part Into Which Incorporated | |
Annual Report to Shareholders for the Year Ended December 31, 2012 2013 Proxy Statement |
Parts I, II, and IV Part III |
PART I | 1 | |||
Item 1. |
1 | |||
1 | ||||
1 | ||||
2 | ||||
3 | ||||
3 | ||||
5 | ||||
5 | ||||
5 | ||||
5 | ||||
Item 1A. |
7 | |||
Item 1B. |
9 | |||
Item 2. |
9 | |||
Item 3. |
10 | |||
Item 4. |
10 | |||
Item 4A. |
10 | |||
10 | ||||
Item 5. |
10 | |||
Item 6. |
11 | |||
Item 7. |
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
11 | ||
Item 7A. |
11 | |||
Item 8. |
12 | |||
Item 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
12 | ||
Item 9A. |
12 | |||
Item 9B. |
12 | |||
PART III | 12 | |||
Item 10. |
12 | |||
Item 11. |
14 | |||
Item 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
14 | ||
Item 13. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
16 | ||
Item 14. |
16 | |||
PART IV | 16 | |||
Item 15. |
16 | |||
17 | ||||
SIGNATURES | 23 |
Item 1. | BUSINESS |
Southwest Gas Corporation (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.
NPL Construction Co. (NPL or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
Financial information concerning the Companys business segments is included in Note 14 of the Notes to Consolidated Financial Statements, which is included in the 2012 Annual Report to Shareholders and is incorporated herein by reference.
The Company maintains a website (www.swgas.com) for the benefit of shareholders, investors, customers, and other interested parties. The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports available, free of charge, through its website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The Companys 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 Companys website. Print versions of these documents are available to shareholders upon request directed to the Corporate Secretary, Southwest Gas Corporation, 5241 Spring Mountain Road, Las Vegas, NV 89150.
Southwest is subject to regulation by the Arizona Corporation Commission (ACC), the Public Utilities Commission of Nevada (PUCN), and the California Public Utilities Commission (CPUC). These commissions regulate public utility rates, practices, facilities, and service territories in their respective states. The CPUC also regulates the issuance of all securities by the Company, 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). NPL is not regulated by the state utilities commissions in any of its operating areas.
As of December 31, 2012, Southwest purchased and distributed or transported natural gas to 1,876,000 residential, commercial, and industrial customers in geographically diverse portions of Arizona, Nevada, and California. The southwestern United States had historically been one of the highest growth regions of the country. However, the customer growth levels experienced in recent years have greatly diminished due to the overall slowdown in the new housing market and increase in idle/vacant homes, resulting from foreclosures and challenging economic conditions. Southwest completed 17,000 first-time meter sets over the last twelve months. These meter sets led to 17,000 net additional active customers during 2012, an increase of about 1%. Given the current housing and economic environment, management expects that customer growth will be approximately 1% in the near term. Southwest estimates that the number of excess inactive meters is approximately 37,000 at December 31, 2012. Management cannot predict the timing of when currently idle and vacant homes will return to service, but to date it has been gradual.
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The table below lists the percentage of operating margin (operating revenues less net cost of gas) by major customer class for the years indicated:
Distribution | ||||||
For the Year Ended |
Residential and |
Other Sales Customers |
Transportation | |||
December 31, 2012 |
85% | 4% | 11% | |||
December 31, 2011 |
86% | 4% | 10% | |||
December 31, 2010 |
86% | 4% | 10% |
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.
Transportation of customer-secured gas to end-users accounted for 48% of total system throughput in 2012. Customers who utilized this service transported 100 million dekatherms in 2012, 94 million dekatherms in 2011, and 100 million dekatherms in 2010. Although these volumes are significant, these customers provided a much smaller proportionate share of operating margin.
The demand for natural gas is seasonal, with a 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, 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.
As of January 2012, 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 with a winter-period monthly weather adjuster is in place, for most customer classes.
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 Managements Discussion and Analysis (MD&A) in the 2012 Annual Report to Shareholders.
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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 | November 2010 | January 2012 | |||
California: |
||||||
Northern and Southern |
Annual attrition | October 2012 | January 2013 | |||
Northern and Southern |
General rate case | December 2012 | Pending | |||
Nevada: |
||||||
Northern and Southern |
General rate case | April 2012 | November 2012 | |||
FERC: |
||||||
Paiute |
General rate case | February 2009 | April 2010 |
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 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), required to be in place by August 2011, that 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 increases/strengthens 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 requires the DOT to conduct further study of existing programs and future requirements. The Company continues to monitor changing pipeline safety legislation and participates to the extent possible in the crafting of associated mandates and reporting. As rules are developed, they could impact the Companys 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 six 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.
Southwest is responsible for acquiring and arranging delivery of natural gas to its system in sufficient quantities to meet its sales customers needs. Southwests primary natural gas acquisition objective is to ensure that adequate supplies of natural gas are available at the best 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 2012, Southwest acquired natural gas from 46 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. Competitive pricing, flexibility in meeting Southwests requirements, and aggressive participation by suppliers who have demonstrated reliability of service are instrumental to any one suppliers inclusion in Southwests portfolio. The goal of this practice is to mitigate the risk of nonperformance by any one supplier and ensure competitive prices.
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
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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 (currently ranging from 25% to about 35%, depending on the jurisdiction) of its forecasted annual normal-weather volume requirement, primarily using firm, fixed-price purchasing arrangements that are secured periodically throughout the year. Southwests 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 and Nevada jurisdictional areas. 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 PGA mechanisms in the respective jurisdictional area.
For the 2012/2013 heating season, fixed-price purchases ranged from approximately $3 to $5 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 not known until the month or day of purchase.
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 Arizona or southern Nevada rate jurisdictions. Limited storage availability exists in southern and northern California and northern Nevada.
Southwest has a contract with Southern California Gas Company that is intended for delivery only within Southwests 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 Southwests ability to inject or withdraw from this interruptible storage, which consequently limits Southwests 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.
Natural gas supplies for Southwests 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 has changed dramatically during recent years. Advanced drilling techniques have provided access to abundant and sustainable natural gas supplies. The natural gas market has responded with reductions to both price volatility and the total price of the commodity. Most recently, natural gas has reached the lowest prices recorded in a decade. An ample and diverse natural gas supply is available to Southwests 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 Southwests 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
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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, Southwest has continued to experience growth in the new home market among the 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 at levels competitive with commercially available alternative energy sources such as electricity, fuel oils, and coal. However, high natural gas prices can impact Southwests 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, 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 Environmental Protection Agency (EPA) has issued regulations that require the reporting of greenhouse gas emissions (GHG) from large sources and suppliers in the United States in order to facilitate the development of policies and programs to reduce GHGs. The Company reports required information to the EPA under the Mandatory Reporting Rule (MRR) including the volumes of natural gas it receives for distribution to LDC customers (Subpart NN) and its fugitive GHG emissions that result from the operation of its LDC pipelines (Subpart W). While some parts of the MRR do not apply to Southwest, other required information is already being reported to the Department of Energy, the Department of Transportation, or is available in existing Company databases. The Company also monitors the development of other climate legislation which could result in additional requirements or have financial implications.
At December 31, 2012, the natural gas operations segment had 2,245 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.
NPL is a full-service contractor whose customers are primarily energy services utility companies. NPL derives revenue from installation, replacement, and maintenance of energy distribution systems. NPL 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 NPL operations is distribution pipe and service hook-up replacements as well as line installations for new business
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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 Midwest. In the warmer climate areas, such as the southwestern United States, construction continues year round.
During the past few years, several factors have impacted the nations natural gas distribution system and resulted in an increase in large multi-year distribution pipe replacement projects. The Department of Transportations Pipeline and Hazardous Materials Safety Administration instituted DIMP, which requires 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 the bonus depreciation tax deduction incentives provided for by the Small Jobs Act of 2010 and the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010. Additionally, funding for planned replacement projects increased due to the general improvement of the national credit markets.
The above factors resulted in several large multi-year distribution pipe replacement projects being awarded to NPL. NPL was selected as the contractor on certain of these projects, or one of several contractors to work on others. These contracts are usually multi-year, and the amount of work to be completed by NPL will vary from year to year. NPL continues to bid on pipe replacement projects throughout the country and has made structural and transitional changes to match the increased size and complexity of the business, including key management changes.
The American Taxpayer Relief Act of 2012 was enacted recently which extends the 50% bonus tax depreciation deduction from January 1, 2013 through December 31, 2013 providing further incentive for replacement projects.
NPL business activities are often concentrated in utility service territories where existing energy lines are scheduled for replacement. An LDC will typically contract with NPL 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 2012, approximately 83% of revenue was earned under unit-price contracts. As of December 31, 2012, a backlog of approximately $35 million existed with respect to outstanding fixed-priced construction contracts.
Materials used by NPL in its construction activities are typically specified, purchased, and supplied by NPLs 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, NPLs operations have minimal environmental impact (dust control, normal waste disposal, handling harmful materials, etc.)
Competition within the industry has traditionally been limited to several regional and local competitors in what has been a largely fragmented industry. Some national competitors also exist within the industry. NPL currently operates in 18 major markets nationwide. Its customers are primarily the principal LDCs in those markets. During 2012, NPL served 73 major customers, with Southwest accounting for approximately 14% of NPL revenues. Additionally, two customers accounted for approximately 26% of total revenue, while five other customers individually accounted for 5% or more of NPL revenues.
Employment fluctuates between seasonal construction periods, which are normally heaviest in the summer and fall months. At December 31, 2012, NPL had 3,770 regular full-time equivalent employees. Employment peaked in August 2012 when there were 4,134 employees. Most employees are represented by unions and are covered by collective bargaining agreements, which is typical of the utility construction industry.
Operations are conducted from 18 field locations 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.
NPL is not directly affected by regulations promulgated by the ACC, PUCN, CPUC, or FERC in its construction services. NPL is an unregulated energy services subsidiary of Southwest Gas Corporation. However, because NPL performs work for the regulated natural gas segment of the Company, its 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 NPL under the regulatory jurisdiction of any of the commissions noted above.
NPL has a 65% interest in IntelliChoice Energy, LLC (ICE) and consolidates ICE as a majority owned subsidiary. ICE was established in late 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 NPL operating results.
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Item 1A. | 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. Unless indicated otherwise, references below to we, us, and our should be read to refer to Southwest Gas Corporation and its subsidiaries.
Governmental policies and regulatory actions can reduce our earnings.
Regulatory commissions set our 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 Arizona Corporation Commission, the California Public Utilities Commission, the Federal Energy Regulatory Commission, and the Public Utilities Commission of Nevada 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 and policies, can reduce our earnings. Risks and uncertainties relating to delays in obtaining regulatory approvals, conditions imposed in regulatory approvals, or determinations in regulatory investigations can also impact financial performance. In particular, the timing and amount of rate relief can materially impact results of operations.
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. We received regulatory approval of a settlement in our most recent Arizona general rate case filing in which we agreed to not file a general rate case in Arizona until April 30, 2016. This could result in gradual earnings deterioration as costs increase during the stay-out period. If approval of the decoupling mechanism is rescinded by Arizona regulators, the prohibition against the filing of general rate cases will be eliminated.
Our operating results may be adversely impacted by a prolonged economic downturn.
The recent 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) have also been impacted, resulting in reductions in operations or closures. A continued slow recovery could result in customers voluntarily reducing consumption. If the recovery process is prolonged or regresses, 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 recovery, or any future economic slowdowns. If the economy or the markets in which we operate do not improve (or worsen) 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, 2012 of approximately $230 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 $80 million
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at December 31, 2012 and is included in the caption Other property and investments on the balance sheet. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, 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 2012, Southwest recognized $6.6 million in Other income (deductions) due to increases in the cash surrender values of its company-owned life insurance policies (compared to an increase of $700,000 resulting from recognized death benefits net of decreases in cash surrender values in 2011). 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 and purchase additional policies as necessary. 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 would result in increased contributions and higher pension expense which would have a negative impact on our cash flows and results of operations.
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 2013, 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 a 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 dollars (self-insured retention) of each incident plus the first $5 million in total claims above our self-insured retention in the policy year. We cannot predict the
8
likelihood 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.
Fixed-price contracts at NPL are subject to potential losses that could adversely affect results of operations.
NPL enters into a variety of types of contracts customary in the pipeline 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.
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 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.
Item 1B. | UNRESOLVED STAFF COMMENTS |
None.
Item 2. | 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, including a portion of the corporate headquarters office complex located in Las Vegas, Nevada and the administrative offices in Phoenix, Arizona. Total gas plant, exclusive of leased property, at December 31, 2012 was $5.1 billion, including construction work in progress. It is the opinion of management that the properties of Southwest are suitable and adequate for its purposes.
9
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 NPL can be found on pages 5 and 6 of this Form 10-K under Construction Services.
Item 3. | LEGAL PROCEEDINGS |
The Company is 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 the Companys financial position or results of operations.
Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
Item 4A. | EXECUTIVE OFFICERS OF THE REGISTRANT |
The listing of the executive officers of the Company is set forth under Part III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE, which by this reference is incorporated herein.
Item 5. | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2013, there were 15,969 holders of record of common stock, and the market price of the common stock was $44.50. The quarterly market price of, and dividends on, Company common stock required by this item are included in the 2012 Annual Report to Shareholders filed as an exhibit hereto and incorporated herein by reference.
In February 2013, the Board of Directors (Board) increased the quarterly dividend payout to 33 cents per share, effective with the June 2013 payment. This marks the seventh consecutive year in which the dividend was increased. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average, while maintaining the Companys stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Boards continued review of the Companys dividend rate in the context of the performance of the Companys two operating segments and their future growth
10
prospects. The quarterly common stock dividend declared was 25 cents per share throughout 2010, 26.5 cents per share throughout 2011, and 29.5 cents per share throughout 2012.
Item 6. | SELECTED FINANCIAL DATA |
Information required by this item is included in the 2012 Annual Report to Shareholders and is incorporated herein by reference.
Item 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Information required by this item is included in the 2012 Annual Report to Shareholders and is incorporated herein by reference.
Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is exposed to various forms of market risk, including commodity price risk, weather risk, and interest rate risk. The following describes the Companys 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 2013 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 (currently ranging from 25% to 35%, depending on the jurisdiction) of its natural gas portfolio using fixed-price contracts and/or derivative instruments (fixed-for-floating swaps), and where available, natural gas storage.
Southwests 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 Southwests 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 the Company from the effects of lower usage (including volumes associated with unusual weather). In Arizona, a full revenue decoupling mechanism, which includes a winter-period monthly weather adjuster, is in place for most customer classes. With decoupled rate structures, Southwests operating margin is limited during unusually cold weather. However, 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 the Company 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 ($100 million prior to November 2012) 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, 2012 and 2011, Southwest had $161 million and $209 million, respectively, in variable-rate debt outstanding, excluding the IDRBs noted above. 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 $2 million.
Other risk information is included in Item 1A. Risk Factors of this report.
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Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The Consolidated Financial Statements of Southwest Gas Corporation and Notes thereto, together with the report of PricewaterhouseCoopers LLP, are included in the 2012 Annual Report to Shareholders and are incorporated herein by reference.
Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
Item 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
The Company has 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 SECs rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, 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, 2012, management of the Company, including the Chief Executive Officer and Chief Financial Officer, believe the Companys disclosure controls and procedures are effective at attaining the level of reasonable assurance noted above.
Internal Control Over Financial Reporting
The report of management of the Company required to be reported herein is incorporated by reference to the information reported in the 2012 Annual Report to Shareholders under the caption Managements Report on Internal Control Over Financial Reporting on page 79.
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 2012 Annual Report to Shareholders under the caption Report of Independent Registered Public Accounting Firm on page 80.
There have been no changes in the Companys internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected or that are reasonably likely to materially affect the Companys internal control over financial reporting.
Item 9B. | OTHER INFORMATION |
None.
Item 10. | 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 2013 Proxy Statement, which by this reference is incorporated herein.
12
(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, 2012 are as follows:
Name |
Age |
Position |
Period Position Held | |||
Jeffrey W. Shaw |
54 | President and Chief Executive Officer |
2012-Present | |||
Chief Executive Officer |
2008-2012 | |||||
Roy R. Centrella |
55 | Senior Vice President/Chief Financial Officer |
2010-Present | |||
Vice President/Controller and Chief Accounting Officer |
2008-2010 | |||||
Eric DeBonis |
45 | Senior Vice President/Operations |
2012-Present | |||
Senior Vice President/Staff Operations & Technology |
2011-2012 | |||||
Vice President/Special Projects |
2010-2011 | |||||
Vice President/Central Arizona Division |
2008-2010 | |||||
General Manager/East Region/Central Arizona Division |
2008 | |||||
Karen S. Haller |
49 | Senior Vice President/General Counsel and Corporate Secretary |
2012-Present | |||
Vice President/General Counsel, Compliance Officer, |
||||||
and Corporate Secretary |
2010-2012 | |||||
Vice President/General Counsel and Compliance Officer |
2008-2010 | |||||
Vice President/Deputy General Counsel and Compliance Officer |
2008 | |||||
Assistant General Counsel and Director/Legal Affairs |
2008 | |||||
John P. Hester |
50 | Senior Vice President/Regulatory Affairs & Energy Resources |
2008-Present | |||
Laura Lopez Hobbs |
53 | Senior Vice President/Human Resources and Administration |
2012-Present | |||
Vice President/Administration |
2010-2012 | |||||
Vice President/Human Resources |
2008-2010 | |||||
Director/Human Resources |
2008 | |||||
Edward A. Janov |
58 | Senior Vice President/Corporate Development |
2010-Present | |||
Senior Vice President/Finance |
2008-2010 | |||||
William N. Moody |
56 | Senior Vice President/Staff Operations & Technology |
2012-Present | |||
Vice President/Gas Resources |
2008-2012 | |||||
Kenneth J. Kenny |
50 | Vice President/Finance/Treasurer |
2010-Present | |||
Vice President/Treasurer |
2008-2010 | |||||
Gregory J. Peterson |
53 | Vice President/Controller and Chief Accounting Officer |
2010-Present | |||
Assistant Controller |
2008-2010 |
(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 2013 Proxy Statement, which by this reference is incorporated herein. All Executive Officers have held responsible positions with the Company for at least five years as described in (b) above.
(f) Involvement in Certain Legal Proceedings. None.
(g) Promoters and Control Persons. None.
(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 2013 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 2013 Proxy Statement, which by this reference is incorporated herein.
(j) Material Changes in Director Nomination Procedures for Security Holders. On July 31, 2012, the Board approved the amendment of the Companys Bylaws (as amended, the Bylaws). The amendment, which was effective immediately upon approval, implemented a change to Section 3 of Article III of the Bylaws. Prior to the
13
amendment, the Bylaws allowed shareholders to make nominations of individuals to be elected to the Board 20 days prior to the anniversary of the date that the prior years annual meeting was held. The amended provision requires that the Company receive notice of any such nominations from shareholders at least 120 days before the anniversary of the date of the proxy statement for the prior years annual meeting.
Section 16(a) Beneficial Ownership Reporting Compliance. The Company has adopted procedures to assist its 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, the Company believes that all of its directors and executive officers complied during 2012 with the reporting requirements of Section 16(a) of the Exchange Act, except for the following Form 4:
The purchase of Company common stock by director José A. Cárdenas of 1,500 shares on March 2, 2012 was reported on March 7, 2012.
Code of Business Conduct and Ethics. The Company has adopted a code of business conduct and ethics for its employees, including its 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 Companys Code of Business Conduct & Ethics can be viewed on the Companys website (www.swgas.com). If any substantive amendments to the Code of Business Conduct & Ethics are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct & Ethics, to the Companys chief executive officer, chief financial officer and chief accounting officer, the Company will disclose the nature of such amendment or waiver on the Companys website, www.swgas.com.
Item 11. | EXECUTIVE COMPENSATION |
Information with respect to executive compensation is set forth under the heading Executive Compensation in the definitive 2013 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 2013 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 2013 Proxy Statement, which by this reference is incorporated herein.
Item 12. | 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 2013 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 2013 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, 2012, the Company had three stock-based compensation plans. With respect to the first plan, the Company 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 and no future grants are anticipated.
14
Equity Compensation Plan Information |
||||||||||||
Plan category |
Number of securities to be issued upon exercise of outstanding options, warrants and rights |
Weighted average exercise price of outstanding options, warrants and rights |
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 |
125 | $ | 28.13 | - | ||||||||
Equity compensation plans not approved by security holders |
- | - | - | |||||||||
|
|
|
|
|
|
|||||||
Total |
125 | $ | 28.13 | - | ||||||||
|
|
|
|
|
|
Pursuant to the terms of the management incentive plan, the Company may issue performance shares to encourage key employees to remain in its employment 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 |
348 | $ | 36.03 | 243 | ||||||||
Equity compensation plans not approved by security holders |
- | - | - | |||||||||
|
|
|
|
|
|
|||||||
Total |
348 | $ | 36.03 | 243 | ||||||||
|
|
|
|
|
|
Pursuant to the terms of the restricted stock/unit plan, the Company 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 of the Company 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 |
207 | $ | 37.18 | 236 | ||||||||
Equity compensation plans not approved by security holders |
- | - | - | |||||||||
|
|
|
|
|
|
|||||||
Total |
207 | $ | 37.18 | 236 | ||||||||
|
|
|
|
|
|
Additional information regarding the three equity compensation plans is included in Note 11 of the Notes to Consolidated Financial Statements in the 2012 Annual Report to Shareholders.
15
Item 13. | 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 2013 Proxy Statement, which by this reference is incorporated herein.
Item 14. | 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 2013 Proxy Statement, which by this reference is incorporated herein.
Item 15. | 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 2012 Annual Report to Shareholders under the following captions: |
Consolidated Balance Sheets |
38 | |||
Consolidated Statements of Income |
40 | |||
Consolidated Statements of Comprehensive Income |
41 | |||
Consolidated Statements of Cash Flows |
42 | |||
Consolidated Statements of Equity |
44 | |||
Notes to Consolidated Financial Statements |
46 | |||
Managements Report on Internal Control Over Financial Reporting |
79 | |||
Report of Independent Registered Public Accounting Firm |
80 |
(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. |
16
Exhibit Number |
Description of Document | |
3(i) | Restated Articles of Incorporation, as amended. Incorporated herein by reference to Exhibit 3(i) to Form 10-Q for the quarter ended September 30, 2007, File No. 1-07850. | |
3(ii) | Amended Bylaws of Southwest Gas Corporation. Incorporated herein by reference to Exhibit 3(ii) to Form 8-K dated July 31, 2012, File No. 1-07850. | |
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 | Form of Deposit Agreement. Incorporated herein by reference to Exhibit 4.01 to Form S-3 dated September 26, 1994, File No. 33-55621. | |
4.03 | Form of Depositary Receipt (attached as Exhibit A to Form of Deposit Agreement included as Exhibit 4.02 hereto). Incorporated herein by reference to Exhibit 4.01 to Form S-3 dated September 26, 1994, File No. 33-55621. | |
4.04 | Indenture between the Company 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. | |
4.05 | First Supplemental Indenture of the Company 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. | |
4.06 | Second Supplemental Indenture of the Company 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. | |
4.07 | Indenture between Clark County, Nevada, and Harris Trust and Savings Bank as Trustee, dated as of October 1, 1999, with respect to the issuance of $35,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), Series 1999A and Taxable Series 1999B or convertibles of Series B (Series C and D), due 2038. Incorporated herein by reference to Exhibit 4.20 to Form 10-K for the year ended December 31, 1999, File No. 1-07850. | |
4.08 | Third Supplemental Indenture between the Company and The Bank of New York, as successor to Harris Trust and Savings Bank, dated as of February 13, 2001, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the $200,000,000, 8.375% Notes, due 2011. Incorporated herein by reference to Exhibit 4.01 to Form 8-K dated February 8, 2001, File No. 1-07850. | |
4.09 | Fourth Supplemental Indenture of the Company to The Bank of New York, as successor to Harris Trust and Savings Bank, dated as of May 6, 2002, supplementing and amending the Indenture dated as of July 15, 1996, with respect to the 7.625% Senior Unsecured Notes due 2012. Incorporated herein by reference to Exhibit 4.01 to Form 8-K dated May 1, 2002, File No. 1-07850. |
17
Exhibit Number |
Description of Document | |
4.10 | Certificate of Trust of Southwest Gas Capital II. Incorporated herein by reference to Exhibit 4.03 to Form S-3 dated August 7, 2003, File No. 333-106419. | |
4.11 | 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. | |
4.12 | 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. | |
4.13 | 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. | |
4.14 | 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. | |
4.15 | Form of Common Stock Certificate. Incorporated herein by reference to Exhibit 4 to Form 8-K dated July 22, 2003, File No. 1-07850. | |
4.16 | Form of Amended and Restated Trust Agreement of Southwest Gas Capital II. Incorporated herein by reference to Exhibit 4.09 to Form 8-K dated August 20, 2003, File No. 1-07850. | |
4.17 | Indenture between Clark County, Nevada, and BNY Midwest Trust Company as Trustee, dated as of July 1, 2004, with respect to the issuance of $65,000,000 Industrial Development Revenue Bonds (Southwest Gas Corporation), Series 2004A, due 2034. Incorporated herein by reference to Exhibit 4 to Form 10-Q for the quarter ended September 30, 2004, File No. 1-07850. | |
4.18 | Indenture between Clark County, Nevada, and BNY Midwest Trust Company as Trustee, dated as of October 1, 2004, with respect to the issuance of $75,000,000 Industrial Development Refunding Revenue Bonds (Southwest Gas Corporation), Series 2004B, due 2033. Incorporated herein by reference to Exhibit 4.01 to Form 10-K for the year ended December 31, 2004, File No. 1-07850. | |
4.19 | 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. | |
4.20 | 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. | |
4.21 | 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. | |
4.22 | 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. | |
4.23 | 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. |
18
Exhibit Number |
Description of Document | |
4.24 | Note Purchase Agreement, dated November 18, 2010, by and between the Company 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. | |
4.25 | 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. | |
4.26 | 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. | |
4.27 | 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. | |
4.28 | Form of Indenture for Senior Notes Due 2022. Incorporated herein by reference to Exhibit 4.1 to Form S-3ASR dated March 20, 2012, File No. 333-180226. | |
4.29 | Indenture, dated March 23, 2012, 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 March 20, 2012, File No. 1-07850. | |
4.30 | The Company hereby agrees 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 Corporation or its subsidiaries; the total amount of securities authorized thereunder does not exceed 10% of the consolidated total assets of Southwest Gas Corporation and its subsidiaries. | |
10.01 | Project Agreement between the Company 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 | Amended and Restated Lease Agreement between the Company and Spring Mountain Road Associates, dated as of July 1, 1996. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 1996, File No. 1-07850. | |
10.03 * | 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. | |
10.04 * | 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. | |
10.05 | Financing Agreement between the Company and Clark County, Nevada, dated as of October 1, 1999. Incorporated herein by reference to Exhibit 10.16 to Form 10-K for the year ended December 31, 1999, File No. 1-07850. | |
10.06 * | Amended Form of Employment Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998, Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2000, Exhibit 10 to Form 10-Q for the quarter ended September 30, 2001, Form 8-K dated September 21, 2004, Form 8-K dated August 1, 2006, and Exhibit 10.19 to Form 10-K for the year ended December 31, 2006, File No. 1-07850. |
19
Exhibit Number |
Description of Document | |
10.07 * | Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended March 31, 2011, File No. 1-07850. | |
10.08 * | Form of General Release - Attachment A to Form of Change in Control Agreement with Company Officers. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended March 31, 2011, File No. 1-07850. | |
10.09 * | Southwest Gas Corporation Management Incentive Plan, amended and restated effective January 20, 2009. Incorporated herein by reference to Appendix A to the Proxy Statement dated March 18, 2009, File No. 1-07850. | |
10.10 * | Southwest Gas Corporation 2002 Stock Incentive Plan. Incorporated herein by reference to the Proxy Statement dated April 2, 2002, File No. 1-07850. Southwest Gas Corporation 1996 Stock Incentive Plan. Incorporated herein by reference to Appendix C to the Proxy Statement dated May 30, 1996, File No. 1-07850. | |
10.11 * | 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. | |
10.12 * | 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. | |
10.13 | 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. | |
10.14 * | Form of Executive Option Grant under 2002 Stock Incentive Plan. Incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 2004, File No. 1-07850. | |
10.15 | Financing Agreement dated as of October 1, 2004 by and between the Company and Clark County, Nevada, relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2004B. Incorporated herein by reference to Exhibit 10.01 to Form 10-K for the year ended December 31, 2004, File No. 1-07850. | |
10.16 | $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2005, File No. 1-07850. First Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2006, File No. 1-07850. Second Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2007, File No. 1-07850. Third Amendment to $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.02 to Form 10-Q for the quarter ended June 30, 2007, File No. 1-07850. | |
10.17 | 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. |
20
Exhibit Number |
Description of Document | |
10.18 | Financing Agreement dated as of October 1, 2005 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2005A. Incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2005, File No. 1-07850. | |
10.19 | Financing Agreement dated as of September 1, 2006 by and between Clark County, Nevada, and Southwest Gas Corporation relating to Clark County, Nevada Industrial Development Revenue Bonds Series 2006A. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2006, File No. 1-07850. | |
10.20 | 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. | |
10.21 | 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. | |
10.22 | $300 million Credit Facility. Incorporated herein by reference to Exhibit 10.1 to Form 8-K dated March 15, 2012, File No. 1-07850. | |
10.23 * | 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 28, 2012, File No. 1-07850. | |
10.24 * | Change in Control Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation. Incorporated herein by reference to Exhibit 10.23 to Form 10-K for the year ended December 31, 2011, File No. 1-07850. | |
10.25 * | Letter Agreement with Jeffrey W. Shaw, Chief Executive Officer of Southwest Gas Corporation, with respect to post-termination benefits. Incorporated herein by reference to Exhibit 10.24 to Form 10-K for the year ended December 31, 2011, File No. 1-07850. | |
10.26 * | NPL Employment Agreement with James P. Kane. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2012, File No. 1-07850. | |
99.01 | NPL Credit Facility Agreement. Incorporated herein by reference to Exhibit 99.01 to Form 10-Q for the quarter ended June 30, 2012, File No. 1-07850. | |
99.02 | NPL Credit Facility Agreement - First Amendment. Incorporated herein by reference to Exhibit 99.01 to Form 10-Q for the quarter ended September 30, 2012, File No. 1-07850. | |
99.03 | NPL Credit Facility Agreement - Second Amendment. Incorporated herein by reference to Exhibit 99.02 to Form 10-Q for the quarter ended September 30, 2012, File No. 1-07850. | |
12.01 | Computation of Ratios of Earnings to Fixed Charges of Southwest Gas Corporation. | |
13.01 | Portions of 2012 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. | |
31.01 | Section 302 Certifications. |
21
Exhibit Number |
Description of Document | |
32.01 | Section 906 Certifications. | |
101.01 | The following materials from the Companys Annual Report on Form 10-K for the year ended December 31, 2012, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows, (v) the Consolidated Statements of Equity, and (vi) the Notes to the Consolidated Financial Statements. |
* Management Contracts or Compensation Plans
22
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 | ||||||
Date: February 27, 2013 |
By /s/ JEFFREY W. SHAW | |||||
Jeffrey W. Shaw | ||||||
President and Chief Executive Officer |
23
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/ ROBERT L. BOUGHNER (Robert L. Boughner) |
Director | February 27, 2013 | ||
/s/ JOSÉ A. CÁRDENAS (José A. Cárdenas) |
Director | February 27, 2013 | ||
/s/ THOMAS E. CHESTNUT (Thomas E. Chestnut) |
Director | February 27, 2013 | ||
/s/ STEPHEN C. COMER (Stephen C. Comer) |
Director | February 27, 2013 | ||
/s/ LEROY C. HANNEMAN, JR. (LeRoy C. Hanneman, Jr.) |
Director | February 27, 2013 | ||
/s/ MICHAEL O. MAFFIE (Michael O. Maffie) |
Director | February 27, 2013 | ||
/s/ ANNE L. MARIUCCI (Anne L. Mariucci) |
Director | February 27, 2013 | ||
/s/ MICHAEL J. MELARKEY (Michael J. Melarkey) |
Chairman of the Board of Directors |
February 27, 2013 | ||
/s/ JEFFREY W. SHAW (Jeffrey W. Shaw) |
Director, President and Chief Executive Officer |
February 27, 2013 | ||
/s/ A. RANDALL THOMAN (A. Randall Thoman) |
Director | February 27, 2013 | ||
/s/ THOMAS A. THOMAS (Thomas A. Thomas) |
Director | February 27, 2013 | ||
/s/ TERRENCE L. WRIGHT (Terrence L. Wright) |
Director | February 27, 2013 | ||
/s/ ROY R. CENTRELLA (Roy R. Centrella) |
Senior Vice President/ Chief Financial Officer |
February 27, 2013 | ||
/s/ GREGORY J. PETERSON (Gregory J. Peterson) |
Vice President, Controller, and Chief Accounting Officer |
February 27, 2013 |
24
Exhibit 12.01
SOUTHWEST GAS CORPORATION
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
(Thousands of dollars)
|
||||||||||||||||||||
December 31, | ||||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
1. Fixed charges: |
||||||||||||||||||||
A) Interest expense |
$ | 67,148 | $ | 68,183 | $ | 75,481 | $ | 81,861 | $ | 90,403 | ||||||||||
B) Amortization |
2,001 | 2,137 | 2,620 | 2,097 | 2,880 | |||||||||||||||
C) Interest portion of rentals |
10,605 | 8,943 | 6,455 | 6,644 | 7,802 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total fixed charges |
$ | 79,754 | $ | 79,263 | $ | 84,556 | $ | 90,602 | $ | 101,085 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
2. Earnings (as defined): |
||||||||||||||||||||
D) Pretax income from continuing operations |
$ | 207,915 | $ | 175,066 | $ | 158,378 | $ | 132,035 | $ | 101,808 | ||||||||||
Fixed Charges (1. above) |
79,754 | 79,263 | 84,556 | 90,602 | 101,085 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total earnings as defined |
$ | 287,669 | $ | 254,329 | $ | 242,934 | $ | 222,637 | $ | 202,893 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
3.61 | 3.21 | 2.87 | 2.46 | 2.01 | ||||||||||||||||
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|
|
15 |
Exhibit 13.01
Consolidated Selected Financial Statistics
Year Ended December 31, | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||||||||||
Operating revenues |
$ | 1,927,778 | $ | 1,887,188 | $ | 1,830,371 | $ | 1,893,824 | $ | 2,144,743 | ||||||||||
Operating expenses |
1,656,254 | 1,637,108 | 1,598,254 | 1,685,433 | 1,936,881 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating income |
$ | 271,524 | $ | 250,080 | $ | 232,117 | $ | 208,391 | $ | 207,862 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net income |
$ | 133,331 | $ | 112,287 | $ | 103,877 | $ | 87,482 | $ | 60,973 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total assets at year end |
$ | 4,488,057 | $ | 4,276,007 | $ | 3,984,193 | $ | 3,906,292 | $ | 3,820,384 | ||||||||||
|
|
|
|
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|
|
|||||||||||
Capitalization at year end |
||||||||||||||||||||
Total equity |
$ | 1,308,498 | $ | 1,225,031 | $ | 1,166,996 | $ | 1,102,086 | $ | 1,037,841 | ||||||||||
Subordinated debentures |
| | | 100,000 | 100,000 | |||||||||||||||
Long-term debt, excluding current maturities |
1,268,373 | 930,858 | 1,124,681 | 1,169,357 | 1,185,474 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
$ | 2,576,871 | $ | 2,155,889 | $ | 2,291,677 | $ | 2,371,443 | $ | 2,323,315 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Current maturities of long-term debt |
$ | 50,137 | $ | 322,618 | $ | 75,080 | $ | 1,327 | $ | 7,833 | ||||||||||
Common stock data |
||||||||||||||||||||
Common equity percentage of capitalization |
50.8 | % | 56.8 | % | 50.9 | % | 46.5 | % | 44.7 | % | ||||||||||
Return on average common equity |
10.4 | % | 9.3 | % | 9.1 | % | 8.1 | % | 6.0 | % | ||||||||||
Basic earnings per share |
$ | 2.89 | $ | 2.45 | $ | 2.29 | $ | 1.95 | $ | 1.40 | ||||||||||
Diluted earnings per share |
$ | 2.86 | $ | 2.43 | $ | 2.27 | $ | 1.94 | $ | 1.39 | ||||||||||
Dividends declared per share |
$ | 1.18 | $ | 1.06 | $ | 1.00 | $ | 0.95 | $ | 0.90 | ||||||||||
Payout ratio |
41 | % | 43 | % | 44 | % | 49 | % | 64 | % | ||||||||||
Book value per share at year end |
$ | 28.39 | $ | 26.68 | $ | 25.60 | $ | 24.44 | $ | 23.48 | ||||||||||
Market value per share at year end |
$ | 42.41 | $ | 42.49 | $ | 36.67 | $ | 28.53 | $ | 25.22 | ||||||||||
Market value per share to book value per share |
149 | % | 159 | % | 143 | % | 117 | % | 107 | % | ||||||||||
Common shares outstanding at year end (000) |
46,148 | 45,956 | 45,599 | 45,092 | 44,192 | |||||||||||||||
Number of common shareholders at year end |
16,028 | 16,834 | 17,821 | 20,489 | 22,244 | |||||||||||||||
Ratio of earnings to fixed charges |
3.61 | 3.21 | 2.87 | 2.46 | 2.01 |
16 |
Natural Gas Operations
Year Ended December 31, | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||
Sales |
$ | 1,238,513 | $ | 1,329,512 | $ | 1,438,809 | $ | 1,547,081 | $ | 1,728,924 | ||||||||||
Transportation |
83,215 | 73,854 | 73,098 | 67,762 | 62,471 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating revenue |
1,321,728 | 1,403,366 | 1,511,907 | 1,614,843 | 1,791,395 | |||||||||||||||
Net cost of gas sold |
479,602 | 613,489 | 736,175 | 866,630 | 1,055,977 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating margin |
842,126 | 789,877 | 775,732 | 748,213 | 735,418 | |||||||||||||||
Expenses |
||||||||||||||||||||
Operations and maintenance |
369,979 | 358,498 | 354,943 | 348,942 | 338,660 | |||||||||||||||
Depreciation and amortization |
186,035 | 175,253 | 170,456 | 166,850 | 166,337 | |||||||||||||||
Taxes other than income taxes |
41,728 | 40,949 | 38,869 | 37,318 | 36,780 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating income |
$ | 244,384 | $ | 215,177 | $ | 211,464 | $ | 195,103 | $ | 193,641 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Contribution to consolidated net income |
$ | 116,619 | $ | 91,420 | $ | 91,382 | $ | 79,420 | $ | 53,747 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total assets at year end |
$ | 4,204,948 | $ | 4,048,613 | $ | 3,845,111 | $ | 3,782,913 | $ | 3,680,327 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net gas plant at year end |
$ | 3,343,794 | $ | 3,218,944 | $ | 3,072,436 | $ | 3,034,503 | $ | 2,983,307 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Construction expenditures and property additions |
$ | 308,951 | $ | 305,542 | $ | 188,379 | $ | 212,919 | $ | 279,254 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Cash flow, net |
||||||||||||||||||||
From operating activities |
$ | 344,441 | $ | 216,745 | $ | 342,522 | $ | 371,416 | $ | 261,322 | ||||||||||
From (used in) investing activities |
(296,886 | ) | (289,234 | ) | (178,685 | ) | (265,850 | ) | (237,093 | ) | ||||||||||
From (used in) financing activities |
(43,453 | ) | (2,327 | ) | (107,779 | ) | (81,744 | ) | (34,704 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net change in cash |
$ | 4,102 | $ | (74,816 | ) | $ | 56,058 | $ | 23,822 | $ | (10,475 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total throughput (thousands of therms) |
||||||||||||||||||||
Residential |
655,046 | 718,765 | 704,693 | 669,736 | 704,986 | |||||||||||||||
Small commercial |
270,665 | 303,923 | 300,940 | 294,225 | 314,555 | |||||||||||||||
Large commercial |
116,582 | 112,256 | 111,833 | 117,241 | 125,121 | |||||||||||||||
Industrial/Other |
47,830 | 50,208 | 58,922 | 72,623 | 97,702 | |||||||||||||||
Transportation |
998,095 | 941,544 | 998,600 | 1,043,894 | 1,164,190 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total throughput |
2,088,218 | 2,126,696 | 2,174,988 | 2,197,719 | 2,406,554 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Weighted average cost of gas purchased ($/therm) |
$ | 0.42 | $ | 0.58 | $ | 0.62 | $ | 0.71 | $ | 0.84 | ||||||||||
Customers at year end |
1,876,000 | 1,859,000 | 1,837,000 | 1,824,000 | 1,819,000 | |||||||||||||||
Employees at year end |
2,245 | 2,298 | 2,349 | 2,423 | 2,447 | |||||||||||||||
Customer to employee ratio |
836 | 809 | 782 | 753 | 743 | |||||||||||||||
Degree days actual |
1,740 | 2,002 | 1,998 | 1,824 | 1,902 | |||||||||||||||
Degree days ten-year average |
1,866 | 1,888 | 1,876 | 1,882 | 1,893 |
17 |
Managements Discussion and Analysis of Financial Condition and Results of Operations
About Southwest Gas Corporation
Southwest Gas Corporation and its subsidiaries (the Company) consist of two business segments: natural gas operations (Southwest or the natural gas operations segment) and construction services.
Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Southwest is the largest distributor of natural gas in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas for customers in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.
As of December 31, 2012, Southwest had 1,876,000 residential, commercial, industrial, and other natural gas customers, of which 1,010,000 customers were located in Arizona, 681,000 in Nevada, and 185,000 in California. Residential and commercial customers represented over 99% of the total customer base. During 2012, 56% of operating margin was earned in Arizona, 34% in Nevada, and 10% in California. During this same period, Southwest earned 85% of its operating margin from residential and small commercial customers, 4% from other sales customers, and 11% from transportation customers. These general patterns are expected to remain materially consistent for the foreseeable future.
Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The principal factors affecting operating margin changes are general rate relief, weather, conservation and efficiencies, and customer growth. Weather has traditionally been the primary reason for volatility in margin, which continued throughout 2011 with respect to Southwests Arizona service territories. In January 2012, however, a full revenue decoupling mechanism, which includes a monthly weather adjuster, was implemented in the Arizona service territories. With this change, all of Southwests service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on margin and allow the Company to aggressively pursue energy efficiency initiatives.
NPL Construction Co. (NPL or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in 18 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in weather, general and local economic conditions (including the housing market), interest rates, employment levels, job growth, the equipment resale market, pipe replacement programs of utilities, and local and federal regulation (including tax rates and incentives). During the past few years, utilities have implemented pipeline integrity management programs to enhance safety pursuant to federal and state mandates. These programs, coupled with bonus depreciation tax deduction incentives, have resulted in a significant increase in multi-year pipeline replacement projects throughout the country. 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. In certain circumstances, such as with large, longer duration bid contracts, or unit-price contracts with caps, results may be impacted by differences between costs incurred and those anticipated when the work was originally bid.
18 |
Executive Summary
The items discussed in this Executive Summary are intended to provide an overview of the results of the Companys operations and are covered in greater detail in later sections of managements discussion and analysis. As reflected in the table below, the natural gas operations segment accounted for an average of 86% of consolidated net income over the past three years. As such, managements discussion and analysis is primarily focused on that segment.
Summary Operating Results
Year ended December 31, | 2012 | 2011 | 2010 | |||||||||
(In thousands, except per share amounts) | ||||||||||||
Contribution to net income |
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Natural gas operations |
$ | 116,619 | $ | 91,420 | $ | 91,382 | ||||||
Construction services |
16,712 | 20,867 | 12,495 | |||||||||
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Consolidated |
$ | 133,331 | $ | 112,287 | $ | 103,877 | ||||||
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Average number of common shares outstanding |
46,115 | 45,858 | 45,405 | |||||||||
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Basic earnings per share |
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Consolidated |
$ | 2.89 | $ | 2.45 | $ | 2.29 | ||||||
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Natural Gas Operations |
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Operating margin |
$ | 842,126 | $ | 789,877 | $ | 775,732 | ||||||
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2012 Overview
Consolidated operating results for 2012 increased compared to 2011 due to improved operating results from the natural gas segment. Basic earnings per share were $2.89 in 2012 compared to basic earnings per share of $2.45 in 2011.
Natural gas operations highlights include the following:
| Operating margin increased $52 million, or 7%, compared to the prior year |
| Operating expenses increased $23 million, or 4%, between years |
| Net financing costs decreased $2 million between 2012 and 2011 |
| Other income increased $10 million between years |
| Replacement of expiring credit facility with a new $300 million facility in March 2012 |
| Issued $250 million 3.875% Senior Notes in March 2012 with approximately $200 million of the net proceeds used to repay $200 million of 7.625% Senior Notes that matured in May 2012 |
| The Companys credit rating was upgraded from Baa2 to Baa1 by Moodys and from BBB+ to A- by Fitch, in March and May 2012, respectively |
| Nevada general rate increase of $7 million was approved effective November 2012 |
Construction services highlights include the following:
| Revenues in 2012 increased $122 million, or 25%, compared to 2011 |
| Construction expenses increased $118 million or 28%, compared to 2011 |
| Replacement of a $30 million credit facility with a new $75 million facility in June 2012 |
Arizona Rate Relief. During 2012, Southwest realized $45 million of incremental operating margin from rate relief in its Arizona operating areas. See Rates and Regulatory Proceedings for additional information on the associated general rate case with new rates that were effective January 2012.
19 |
Weather and Conservation. Weather has traditionally been the primary reason for volatility in margin, which continued throughout 2011 with respect to Southwests Arizona service territories. In January 2012, however, a full revenue decoupling mechanism, which includes a winter-period monthly weather adjuster, was implemented in the Arizona service territories for most customer classes. With this change, all of Southwests service territories have decoupled rate structures, which are designed to mitigate the impacts of weather variability and conservation on margin and allow the Company to aggressively pursue energy efficiency initiatives on behalf of its customers.
Nevada General Rate Case. In the fourth quarter of 2012, a decision was reached at a public hearing (the Decision) in the general rate application Southwest filed with the Public Utilities Commission of Nevada (PUCN), with rates effective November 2012. The Decision is estimated to provide a revenue increase of $5.8 million in southern Nevada based on an overall rate of return of 6.49% and a 9.85% return on 42.6% common equity. For northern Nevada, the Decision is estimated to provide a revenue increase of $1.2 million with an overall rate of return of 8.01% and a 9.20% return on 65.6% common equity. Approximately $2 million in incremental margin was recorded in the fourth quarter of 2012. Factoring in other aspects of the Decision, including lower depreciation rates, the Decision is expected to increase annual operating income by $11.4 million. Following the Decision, the Company filed a Petition for Reconsideration requesting reconsideration of the findings in the Decision relating to the capital structure and other cost of service issues. See Rates and Regulatory Proceedings for more information.
California General Rate Case. In December 2012, Southwest filed a general rate case application with the California Public Utilities Commission (CPUC) requesting $11.6 million in annual rate increases for its California rate jurisdictions with a proposed effective date of January 2014. See Rates and Regulatory Proceedings for more information.
Customer Growth. Southwest added 17,000 net new customers over the last twelve months. First-time meter sets also approximated 17,000 during the year. Recently, Southwest has experienced customer growth in excess of first-time meter sets as meters on previously vacant homes return to service. Southwest estimates the remaining number of excess inactive meters is approximately 37,000 at December 31, 2012. Southwest projects customer growth associated with new meter sets of about 1% for 2013, along with a gradual return of customers associated with previously vacant homes.
Company-Owned Life Insurance (COLI). Southwest has life insurance policies on members of management and other key employees to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. The COLI policies have a combined net death benefit value of approximately $230 million at December 31, 2012. The net cash surrender value of these policies (which is the cash amount that would be received if Southwest voluntarily terminated the policies) is approximately $80 million at December 31, 2012 and is included in the caption Other property and investments on the balance sheet. The Company currently intends to hold the COLI policies for their duration and purchase additional policies as necessary. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the changes in the cash surrender value components of COLI policies as they progress toward the ultimate death benefits are also recorded without tax consequences. Cash surrender values are directly influenced by the investment portfolio underlying the insurance policies. This portfolio includes both equity and fixed income (mutual fund) investments. As a result, generally the cash surrender value (but not the net death benefit) moves up and down consistent with the movements in the broader stock and bond markets. As indicated in Note 1, cash surrender values of COLI policies increased $6.6 million in 2012. Investment returns during 2012 were significantly higher than normal. In 2011, income from changes in the cash surrender value of COLI policies
20 |
and recognized death benefits was $700,000. Management currently expects average returns of $2 million to $4 million annually on the COLI policies, excluding any net death benefits recognized. Based on the current investment mix, both positive and negative deviations from expected levels are likely to continue.
Credit Facility and Commercial Paper Program. In March 2012, Southwest replaced its $300 million credit facility, which would have expired in May 2012, with a new $300 million facility that expires in March 2017. Southwest has a $50 million commercial paper program, which is supported by (and not incremental to) the credit facility. See Capital Resources and Liquidity for more information.
Liquidity. Southwest believes its liquidity position is solid. As noted above, Southwest has a $300 million credit facility maturing in March 2017. The facility is provided through a consortium of eight major banking institutions. Historically, facility borrowings have been low and concentrated in the first half of the winter heating period when gas purchases require temporary financing. The maximum amount outstanding on the credit facility during 2012 was $130 million in the fourth quarter. At December 31, 2012, $91 million was outstanding on the long-term portion, and no borrowings were outstanding on the short-term portion of the credit facility. At December 31, 2012, the amount outstanding under the commercial paper program was $20 million.
Southwest also believes its ability to obtain funding for ongoing expenditures and future expansions is secure and adequate. Historically, Southwest has accessed the public debt markets for funding, most recently in March 2012 in connection with the issuance of $250 million of 3.875% Senior Notes. Southwests solid liquidity position also provided an opportunity to redeem $12.4 million of 6.10% IDRBs and $14.3 million of 5.95% IDRBs in 2012. Each of these redemptions was at par. Southwest plans to redeem $30 million of 5.45% IDRBs and $15 million of 5.80% IDRBs at par in March 2013. Southwest has no subsequent long-term debt maturities until 2017.
Credit Rating Upgrades. Moodys Investors Service, Inc. (Moodys) and Fitch Ratings (Fitch) upgraded the Companys senior unsecured rating to Baa1 from Baa2 in March 2012 and to A- from BBB+ in May 2012, respectively. See Credits Ratings for more information.
Loss on NPL Contract. In the first half of 2012, NPL recorded $18 million in losses on a large fixed-price pipe replacement contract in a single geographic location. A number of factors contributed to the loss on the contract, which was the largest fixed-price contract ever undertaken by NPL. Approved change orders during the fourth quarter of 2012 helped to reduce current-year losses on the contract to $15 million. At December 31, 2012, work on the contract is substantially complete with the exception of some restoration work. Since inception in 2011, NPL has recognized approximately $75 million of revenues on this contract, including $37 million in 2011. Construction costs recorded to date total approximately $85 million, including $32 million during 2011. No significant additional losses are anticipated on the remaining work to be performed, although no assurances can be provided that additional losses on this contract will not occur.
NPL has another contract with the same customer in the same geographical area with a fixed-price component of approximately $28 million. Work began in the middle of 2012 and will continue into 2013. Based on the progress to date and review of estimated costs to complete, management expects this contract to be marginally profitable overall.
21 |
Results of Natural Gas Operations
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(Thousands of dollars) | ||||||||||||
Gas operating revenues |
$ | 1,321,728 | $ | 1,403,366 | $ | 1,511,907 | ||||||
Net cost of gas sold |
479,602 | 613,489 | 736,175 | |||||||||
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Operating margin |
842,126 | 789,877 | 775,732 | |||||||||
Operations and maintenance expense |
369,979 | 358,498 | 354,943 | |||||||||
Depreciation and amortization |
186,035 | 175,253 | 170,456 | |||||||||
Taxes other than income taxes |
41,728 | 40,949 | 38,869 | |||||||||
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Operating income |
244,384 | 215,177 | 211,464 | |||||||||
Other income (deductions) |
4,165 | (5,404 | ) | 4,016 | ||||||||
Net interest deductions |
66,957 | 68,777 | 75,113 | |||||||||
Net interest deductions on subordinated debentures |
| | 1,912 | |||||||||
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Income before income taxes |
181,592 | 140,996 | 138,455 | |||||||||
Income tax expense |
64,973 | 49,576 | 47,073 | |||||||||
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Contribution to consolidated net income |
$ | 116,619 | $ | 91,420 | $ | 91,382 | ||||||
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2012 vs. 2011
Contribution to consolidated net income from natural gas operations increased by $25 million between 2012 and 2011. The improvement was primarily due to increases in operating margin and other income, partially offset by higher operating expenses.
Operating margin increased $52 million between years. Rate relief in Arizona ($45 million) and Nevada ($2 million) provided $47 million of the increase in operating margin. New customers contributed the remaining $5 million increase in operating margin during 2012. A $4 million increase between years due to an adjustment (related to a regulatory deferral mechanism) that decreased operating margin in 2011 was offset by a reduction of $4 million in operating margin between years primarily due to moderately cold weather experienced in Arizona in the first half of 2011. With a new rate decoupling mechanism in Arizona, effective January 2012, weather is no longer a significant factor in operating margin overall.
Operations and maintenance expense increased $11.5 million, or 3%, between years primarily due to higher general costs and employee-related costs including approximately $6 million of net pension expense, and to approximately $1 million in leak survey costs associated with a special Arizona program (see Pipe Replacement Tracking Mechanisms in the Rates and Regulatory Proceedings section).
Depreciation expense increased $10.8 million, or 6%, as a result of additional plant in service. Average gas plant in service for 2012 increased $247 million, or 5%, compared to 2011. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and to a lesser degree, new business. The increase was partially offset by approximately $1 million due to a reduction in depreciation rates in Nevada, which became effective in November 2012.
Other income, which principally includes returns on COLI policies (including recognized net death benefits) and non-utility expenses, increased $9.6 million between 2012 and 2011. Cash surrender values of COLI policies increased $6.6 million in 2012, while COLI-related income (resulting from recognized death benefits net of decreases in cash surrender values) was $700,000 in the prior year. COLI income in 2012 was especially high due to strong equity-market returns on investments underlying the policies. In addition, Arizona non-recoverable pipe replacement and other non-utility costs were lower in 2012, especially during the fourth quarter, as compared to 2011. The non-recoverable portion of this pipe replacement activity is complete.
22 |
Net interest deductions decreased $1.8 million between 2012 and 2011 primarily due to cost savings from refinancing, partially offset by a temporary increase in debt outstanding for approximately two months associated with the issuance of $250 million 3.875% Senior Notes in March 2012 to repay $200 million 7.625% Senior Notes that matured in May 2012, and by additional interest on variable-rate IDRBs.
2011 vs. 2010
The contribution to consolidated net income from natural gas operations was relatively unchanged between 2011 and 2010; however, operating income improved by $3.7 million between years. The increase in operating margin and reduced financing costs were offset by higher operating expenses and a decrease in other income.
Operating margin increased $14 million between 2011 and 2010. Differences in heating demand, caused primarily by weather variations, accounted for the $14 million increase as colder-than-normal temperatures were experienced in Arizona in 2011. Incremental margin from rate relief in California ($2 million) and new customers ($2 million) was offset by an adjustment recorded during the third quarter of 2011 related to a regulatory deferral mechanism.
Operations and maintenance expense increased $3.6 million, or 1%, between 2011 and 2010 primarily due to general cost increases, partially offset by favorable claims experience under Southwests self-insured medical plan. The increase also included approximately $1 million of costs associated with restoring service to approximately 20,000 Arizona customers in early February 2011, following an outage due to extreme weather conditions. Cost containment efforts (including lower staffing levels) mitigated the increases.
Depreciation expense increased $4.8 million, or 3%, as a result of additional plant in service. Average gas plant in service for 2011 increased $151 million, or 3%, as compared to 2010. This was attributable to pipeline capacity reinforcement work, franchise requirements, scheduled and accelerated pipe replacement activities, and new business.
Taxes other than income taxes increased $2.1 million primarily due to higher property tax rates in Arizona.
Other income declined $9.4 million between 2011 and 2010. COLI-related income in 2011 (resulting from recognized death benefits net of decreases in cash surrender values) was $700,000, while 2010 included income of $9.8 million due to an increase in COLI cash surrender values and recognized net death benefits. COLI income in 2010 was especially high due to strong equity-market returns on investments underlying the policies.
Net financing costs decreased $8.2 million between 2011 and 2010 primarily due to the redemption of $100 million of subordinated debentures in March 2010, cost savings from debt refinancing, and reduced interest rates associated with variable-rate debt (including reductions relating to the interest tracking mechanism for 2003 and 2008 Series A IDRBs).
Income tax expense included $1.6 million of previously unrecognized tax benefits and related interest associated with the expiration of the statute of limitations with respect to a previously recorded uncertain tax position.
Outlook for 2013
Operating margin for 2013 is expected to be favorably influenced by customer growth similar to 2012, as well as incremental margin associated with the Nevada rate case decision and California attrition adjustment.
23 |
Operating expenses for 2013 compared to 2012 will continue to be impacted by inflation, general cost increases, and depreciation expense on plant additions. A reduction in depreciation rates in Nevada will mitigate the depreciation expense increase. Incremental costs, including a $6.4 million increase in pension expense ($5 million net) for 2013 and higher property and general taxes, are expected to result in an overall operating expense increase of approximately 3% to 4%.
Southwest anticipates approximately $5 million in interest savings on an annualized basis due to debt refinancings and redemptions. These savings relate to the March 2012 issuance of $250 million in 3.875% Senior Notes and the repayment of the $200 million of 7.625% debt that occurred in May 2012, as well as the August 2012 redemption of the $14.3 million 1999 5.95% Series C IDRBs. Also included are interest savings expected to be realized from the planned redemption of the $30 million 5.45% 2003 Series C and $15 million 5.80% 2003 Series E IDRBs in the first quarter of 2013.
Results of Construction Services
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(Thousands of dollars) | ||||||||||||
Construction revenues |
$ | 606,050 | $ | 483,822 | $ | 318,464 | ||||||
Operating expenses: |
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Construction expenses |
541,523 | 423,703 | 277,804 | |||||||||
Depreciation and amortization |
37,387 | 25,216 | 20,007 | |||||||||
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Operating income |
27,140 | 34,903 | 20,653 | |||||||||
Other income (deductions) |
246 | (8 | ) | (166 | ) | |||||||
Net interest deductions |
1,063 | 825 | 564 | |||||||||
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Income before income taxes |
26,323 | 34,070 | 19,923 | |||||||||
Income tax expense |
10,303 | 13,727 | 7,852 | |||||||||
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Net income |
16,020 | 20,343 | 12,071 | |||||||||
Net income (loss) attributable to noncontrolling interest |
(692 | ) | (524 | ) | (424 | ) | ||||||
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Contribution to consolidated net income attributable to NPL |
$ | 16,712 | $ | 20,867 | $ | 12,495 | ||||||
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2012 vs. 2011
Contribution to consolidated net income from construction services for 2012 decreased $4.2 million compared to 2011. The decline was primarily due to the loss on a large fixed-price contract in 2012, partially offset by additional replacement work and increased gains on sale of equipment.
Revenues increased $122 million, or 25%, when compared to 2011 due primarily to an increase in the volume of replacement work. The construction revenues included NPL contracts with Southwest totaling $83.4 million in 2012 and $92.1 million in 2011. NPL accounts for the services provided to Southwest at contractual (market) prices at contract inception.
Construction expenses increased $118 million, or 28%, due to the increase in replacement construction work. See Loss on NPL Contract on page 5 for additional information. Depreciation expense increased $12.2 million between the current year and the prior year due to an increase in equipment purchases. Gains on sale of equipment, included in construction expenses, were $8 million and $3.3 million in 2012 and 2011, respectively.
NPLs revenues and operating profits are influenced by weather, customer requirements, mix of work, local economic conditions, bidding results, the equipment resale market, and the credit market. Typically, revenues are lowest during the first quarter of the year due to unfavorable winter weather conditions.
24 |
Revenues typically improve as more favorable weather conditions occur during the summer and fall months. The current low interest rate environment, the impact of bonus depreciation legislation, and the regulatory environment (encouraging the natural gas industry to replace aging pipeline infrastructure) are having a positive influence on NPLs revenue growth.
During the past several years, NPL has focused its efforts on obtaining pipe replacement work under both blanket contracts and incremental bid projects. For 2012 and 2011, approximately 75% of revenues were from replacement work. Federal and state pipeline safety-related programs and bonus depreciation incentives have resulted in many utilities undertaking multi-year distribution pipe replacement projects. NPL continues to bid on pipe replacement projects throughout the country and has made structural and transitional changes to match the increased size and complexity of the business, including key management changes. Though it sustained a sizeable individual contract loss during 2012, it nonetheless experienced its second highest net income in its history.
2011 vs. 2010
Contribution to consolidated net income from construction services for 2011 increased $8.4 million compared to 2010.
Revenues increased $165 million in 2011, a 52% improvement, when compared to 2010 primarily due to increased replacement construction. The construction revenues included NPL contracts with Southwest totaling $92.1 million in 2011 and $61.3 million in 2010. NPL accounts for the services provided to Southwest at contractual (market) prices.
Construction expenses increased $146 million, or 53%, between 2010 and 2011 due primarily to costs associated with the increase in replacement construction work. Depreciation expense increased $5.2 million as a result of an increase in the construction equipment fleet. Interest expense increased $261,000 between 2010 and 2011 due to an increase in outstanding debt. Gains on sales of equipment were $3.3 million and $1.5 million in 2011 and 2010, respectively.
Outlook for 2013
Revenues are subject to the timing and amount of work awarded to NPL by its utility customers. While it is very early in this process, current expectations are for 2013 revenues to approximate 2012 levels. Construction expenses for 2013 are expected to be favorably impacted by elimination of the loss on the fixed-price contract, partially offset by reduced gains on sales of equipment and increased costs associated with the structural changes made to management and support functions, as well as general cost increases in labor and materials.
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 Southwests service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management has worked with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such rate structures were in place in all of Southwests operating areas during 2012.
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Nevada General Rate Case. Southwest filed a general rate application with the PUCN in April 2012 to recover increased costs for operations in northern and southern Nevada. In addition, the filing reflected additional investments in infrastructure and included changes in depreciation, cost of service, and cost of capital. Southwest requested an increase in revenue of $1.5 million, or 1.41%, in northern Nevada and $25.4 million, or 6.15%, in southern Nevada. In the application, Southwest requested an overall rate of return of 8.45% on original cost rate base of $115 million for northern Nevada and an overall rate of return of 7.44% on original cost rate base of $821 million for southern Nevada, a return on common equity of 10.65%, and a capital structure utilizing 54% common equity. Southwest also requested to implement an infrastructure replacement mechanism to defer and recover certain costs associated with up to $40 million annually of proposed accelerated replacement of early vintage plastic and steel pipe.
The PUCN reached a decision in this proceeding in the fourth quarter of 2012 with rates effective November 2012. The Decision provides an annual revenue increase of $5.8 million in southern Nevada based on an overall rate of return of 6.49% and a 9.85% return on 42.6% common equity on original cost rate base of $825 million. For northern Nevada, the Decision provides a revenue increase of $1.2 million with an overall rate of return of 8.01% and a 9.20% return on 65.6% common equity on original cost rate base of $116 million. The Decision also included a reduction in annualized depreciation expense of $5.2 million and $1.7 million in southern and northern Nevada, respectively. In addition, the Decision reclassified approximately $2.5 million of modified business and mill taxes from pass-through items to operating expenses. On a combined basis, the Decision is expected to increase annual operating income by $11.4 million.
The Company reviewed the Decision and identified certain items that it ultimately submitted to the PUCN for reconsideration. Notably, the PUCN employed alternative capital structures for northern and southern Nevada instead of the actual capital structure of the Company that was supported by all parties. A Petition for Reconsideration (Petition) was filed with the PUCN after the PUCN issued its order in this proceeding, requesting reconsideration of the findings in the decision relating to the capital structure and other cost of service issues. Similarly, the PUCN Staff filed a Petition for Rehearing on the same alternative capital structure issue addressed in Southwests Petition. In December 2012, a decision was received which granted Southwests Petition on certain issues pertaining to the cost of service items, denied the Companys request related to the capital structure, but granted the PUCN Staffs requested Petition for Rehearing on the capital structure. The reconsideration of the cost of service issues required a modification of the final Order, however ultimately continued to deny cost recovery for these items. The hearing related to the capital structure was held in January 2013, and the parties to the proceeding presented evidence in support of their respective positions on what capital structure the PUCN should utilize in establishing rates. A final PUCN decision on the rehearing is expected in the first quarter of 2013.
As it relates to the proposed infrastructure replacement mechanism, the PUCN Decision indicated a separate rulemaking docket will be needed to address the regulatory issues necessary to implement such a mechanism. In January 2013, the PUCN authorized the opening of a new docket to review the merits of such mechanisms. An initial round of comments and reply comments were submitted and a workshop on the matter has already been convened. The scope of the rulemaking was recently expanded in order to consider additional forms of recovery mechanisms. The next steps in the proceeding include the filing of additional comments by interested parties, reply comments, and the convening of another workshop in the first quarter of 2013. The Company anticipates the PUCN will issue a decision in this rulemaking docket by the end of the third quarter of this year.
California Annual Attrition. As part of the 2009 rate decision by the CPUC in Southwests last California general rate case, attrition increases were authorized for the years 2010-2013. The level of increase authorized for 2013 was $1.8 million in southern California, $500,000 in northern California, and $100,000 in
26 |
South Lake Tahoe. However, the continued low interest rate environment has triggered an automatic rate of return adjustment mechanism, which resulted in decreases of $700,000 in southern California, $500,000 in northern California, and $100,000 in South Lake Tahoe. The resulting net margin impact for the California rate jurisdictions is $1.1 million.
California General Rate Case. In December 2012, Southwest filed a general rate case application with the CPUC requesting annual revenue increases of $5.6 million for southern California, $3.2 million for northern California, and $2.8 million for the South Lake Tahoe rate jurisdiction. The application included a capital structure consisting of 43% debt and 57% common equity, with an overall rate of return of 7.32% in southern California and 8.61% in both northern California and South Lake Tahoe. Southwest is also seeking to continue the Post-Test Year Ratemaking Mechanism, which allows for annual attrition increases. The application includes the addition of an Infrastructure Reliability and Replacement Adjustment Mechanism to facilitate and complement projects involving the enhancement and replacement of gas infrastructure, providing timely cost recovery for qualifying non-revenue producing capital expenditures. Hearings on the general rate case application are anticipated in the third quarter of 2013 with new rates proposed to be effective January 2014.
Arizona General Rate Case. In November 2010, Southwest filed a general rate application with the Arizona Corporation Commission (ACC) for its Arizona rate jurisdiction. The ACC authorized a general rate increase of $52.6 million effective January 2012 which included a return on common equity of 9.50%, a fair value rate of return of 6.92% and a capital structure consisted of 47.7% long-term debt and 52.3% common equity, with an embedded cost of debt of 8.34%. The ACC also approved a full revenue decoupling mechanism with a monthly weather adjuster. Management has not determined the timing of filing its next general rate case in Arizona; however, Southwest agreed in the settlement in the most recent Arizona general rate case filing to not file a general rate case in Arizona until April 30, 2016. If approval of the decoupling mechanism is rescinded by the ACC, the prohibition against the filing of general rate cases will be eliminated.
Pipe Replacement Tracking Mechanisms
Customer-Owned Yardline (COYL) Program. At December 31, 2011, there were approximately 100,000 customers in Arizona whose natural gas meters are set-off away from the customers home (e.g., near a backyard property line), as opposed to a more traditional configuration in which the meter is adjacent to the home. Under the COYL configuration, the customer owns, operates, and is responsible for maintaining the service line that runs from the meter to the home. As these lines age, they periodically develop low pressure leaks which result in immediate termination of natural gas service, and a subsequent need for the customer to repair or replace the COYL prior to service restoration. To address the cost normally borne by the customer to repair or replace the COYL, the Company received approval to implement a program (as part of its 2010 Arizona rate case decision) under which the Company will replace the customers facilities at no immediate direct cost to the customer, and relocate the customers meter adjacent to the home, thereby eliminating the customers previous operating and maintenance responsibilities associated with the COYL. In addition, the program provides for the Company to endeavor to leak survey all such COYLs over a 3-year period; anticipated costs for the survey are reflected in current rates. As of December 31, 2012, approximately 50,000 COYL services had been inspected and 2,000 relocated. The costs of the replacement portion of this program are capitalized by the Company and were approximately $4 million in 2012. Subject to an annual reporting requirement, a surcharge is added to all bills to recover an amount approximately equal to the amount that the Company would have earned if the additional pipe replacement costs had been included in the rate base amount filed in the 2010 Arizona rate case. Recovery of the surcharge will cease as of the next Arizona general rate case (as the expenditures will then be included in rate base).
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Nevada Pipe Replacement Program. The Company identified specific pipe replacement projects (including early vintage plastic pipe) for accelerated replacement in its Northern Nevada jurisdiction during 2011 and for its Southern Nevada jurisdiction during 2011 and 2012. The PUCN authorized Southwest to accumulate the incremental depreciation and carrying costs associated with these projects as a regulatory asset through January 2015, by which time any accumulated costs must be reflected in rates pursuant to a general rate case filing, or become subject to an eight-year amortization period; recovery of unamortized post-2015 balances may also be requested in a general rate case filing. As part of the Decision reached in the 2012 general rate case, Southwest was authorized to recover costs accumulated through May 2012 over an eight-year period and to continue to defer the incremental depreciation and carrying costs for approved projects, which will be included in a future general rate case proceeding.
FERC Jurisdiction. In February 2009, Paiute Pipeline Company, a wholly owned subsidiary of the Company, filed its most recent general rate case with the Federal Energy Regulatory Commission (FERC). In April 2010, the FERC approved an offer of settlement from Paiute which resolved all issues related to its general rate case. The settlement provided for an increase of approximately $900,000 in Paiutes annual operating income and was effective September 2009. Management has not determined the timing of filing its next general rate case with the FERC; however, in the settlement, Paiute agreed to file its next general rate case on or by February 28, 2014.
PGA Filings
The rate schedules in all of Southwests 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, 2012, over-collections in Arizona and Nevada resulted in a liability of $98.9 million and under-collections in California resulted in an asset of $6 million on the Companys balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions, and Other income (deductions).
Southwest had the following outstanding PGA balances receivable/(payable) at the end of its two most recent fiscal years (millions of dollars):
2012 | 2011 | |||||||
Arizona |
$ | (46.6 | ) | $ | (28.4 | ) | ||
Northern Nevada |
(7.1 | ) | (7.9 | ) | ||||
Southern Nevada |
(45.2 | ) | (36.1 | ) | ||||
California |
6.0 | 2.3 | ||||||
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$ | (92.9 | ) | $ | (70.1 | ) | |||
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Arizona PGA Filings. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits measured on a twelve-month rolling average. A temporary surcredit of $0.08 per therm was put into place in December 2009 to help accelerate the refund of the over-collected balance to customers. During 2012, approximately $40 million was refunded to customers via the surcredit; however, continued low natural gas prices resulted in a continuing balance due customers. In order to accelerate the refunds to customers, Southwest filed to temporarily increase this rate to $0.10 per therm effective January 2013, which was approved by the ACC in December 2012. A prudence review of gas costs is conducted in conjunction with general rate cases.
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California Gas Cost Filings. In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments modeled in this fashion provide the timeliest recovery of gas costs in any Southwest jurisdiction and are designed to send appropriate pricing signals to customers.
Nevada Annual Rate Adjustment (ARA) Application. In June 2012, Southwest filed its ARA application with the PUCN to establish revised Deferred Energy Account Adjustment (DEAA) rates (in addition to adjustments to the Variable Interest Expense rate, the Uncollectible Gas Cost Expense rates, and other rate-related items), which was approved effective January 2013. Southwest makes quarterly DEAA adjustments based upon a twelve-month rolling average. During 2012, approximately $53 million was refunded to customers via billing credits; however, base tariff rates continued to exceed average rates paid for natural gas in 2012 resulting in a net increase in the balance payable to customers.
Gas Price Volatility Mitigation
Regulators in Southwests service territories have encouraged Southwest to take proactive steps to mitigate price volatility to its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts and fixed-for-floating swap contracts (Swaps) under its collective volatility mitigation programs for a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its annual normal weather supply needs. For the 2012/2013 heating season, contracts contained in the fixed-price portion of the portfolio range in price from approximately $3 to $5 per dekatherm. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities, and on the spot market. Prices for these contracts are not known until the month of purchase.
Capital Resources and Liquidity
Cash on hand and cash flows from operations have generally been sufficient over the past three years to provide for net investing activities (primarily construction expenditures and property additions). Certain pipe replacement work was accelerated during 2011 and 2012 to take advantage of bonus depreciation tax incentives. During the same three-year period, the Company was able to achieve cost savings from debt refinancing and strategic debt redemptions. The Companys capitalization strategy is to maintain an appropriate balance of equity and debt to maintain strong investment-grade credit ratings which should minimize interest costs.
Cash Flows
Operating Cash Flows. Cash flows provided by consolidated operating activities increased $134 million in 2012 as compared to 2011. The improvement in operating cash flows was attributable to greater net income and non-cash depreciation expense and temporary net cash flow increases resulting from changes in working capital components.
Investing Cash Flows. Cash used in consolidated investing activities increased $15.2 million in 2012 as compared to 2011. The increase was primarily due to additional construction expenditures, including scheduled and accelerated pipe replacement, and equipment purchases by NPL due to the increased replacement construction work of its customers.
Financing Cash Flows. Net cash used in consolidated financing activities increased $21.3 million in 2012 as compared to 2011. A forward-starting interest rate swap (FSIRS) contract was settled by paying $21.8 million during the first quarter of 2012 (at maturity). See Note 13 Derivatives and Fair Value Measurements for more information regarding the FSIRS. Dividends paid increased in 2012 as compared to 2011 as a result of an increase in the quarterly dividend and an increase in the number of shares
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outstanding. The issuance of new debt including the $250 million 3.875% Senior Notes and borrowings on the long-term portion of the credit facility was partially offset by debt repayments including the $12.4 million 1999 6.1% Series A fixed-rate IDRBs repaid in January 2012, the $200 million 7.625% Senior Notes repaid in May 2012, the $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038) repaid in August 2012. The remaining issuance amounts and retirements of long-term debt primarily relate to borrowings and repayments under NPLs line of credit. The prior year included the repayment of the $200 million 8.375% Notes and the issuance of the $125 million 6.1% Notes.
The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources.
2012 Construction Expenditures
During the three-year period ended December 31, 2012, total gas plant increased from $4.4 billion to $5 billion, or at an average annual rate of 4%. Replacement, reinforcement, and franchise work was a substantial portion of the plant increase. To a lesser extent, customer growth impacted expenditures as the Company set approximately 47,000 meters during the three-year period.
During 2012, construction expenditures for the natural gas operations segment were $309 million. The majority of these expenditures represented costs associated with scheduled and accelerated replacement of existing transmission, distribution, and general plant (see also Bonus Depreciation below). Cash flows from operating activities of Southwest were $344 million and provided approximately 95% of construction expenditures and dividend requirements of the natural gas operations segment. Other necessary funding was provided by cash on hand, external financing activities, and existing credit facilities.
2012 Financing Activity
In January 2012, the Company redeemed at par its $12.4 million 1999 6.1% Series A fixed-rate IDRBs. The IDRBs were originally due in 2038. In February 2012, the Company drew down the remaining $12.8 million in restricted cash from a 2009 IDRB offering. In March 2012, the Company issued $250 million in 3.875% Senior Notes. The notes will mature on April 1, 2022. Management used approximately $200 million of the net proceeds in connection with the repayment of the $200 million 7.625% Senior Notes that matured in May 2012. The remaining net proceeds were used for general corporate purposes. In August 2012, the Company redeemed at par its $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038). During 2012, the Company issued shares of common stock through its various stock plans, including the Stock Incentive Plan, raising approximately $2 million.
Bonus Depreciation. In September 2010, the Small Business Jobs Act of 2010 (Act) was signed into law. The Act provided a 50% bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2010. In December 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (Tax Relief Act) was signed into law. The Tax Relief Act provided for a temporary 100% bonus tax depreciation deduction for qualified property acquired or constructed and placed in service after September 8, 2010 and before January 1, 2012 and extended the availability of the 50% bonus tax depreciation deduction through December 31, 2012. In January 2013, the American Taxpayer Relief Act of 2012 (Taxpayer Relief Act) was enacted extending the 50% bonus tax depreciation deduction for qualified property acquired or constructed and placed in-service during 2013. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation provisions of the two acts will defer the payment of approximately $30 million and $37 million of federal income taxes for 2012 and 2013, respectively.
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Three-Year Construction Expenditures, Debt Maturities, and Financing
Southwest estimates natural gas segment construction expenditures during the three-year period ending December 31, 2015 will be approximately $1 billion. Of this amount, approximately $320 million to $360 million are expected to be incurred in 2013 depending on the approval and timing of requested infrastructure replacement mechanisms in Nevada (see Rates and Regulatory Proceedings). Southwest has taken advantage of bonus depreciation tax benefits to accelerate projects that improve system flexibility and reliability (including replacement of early vintage plastic and steel pipe). Significant replacement activities are expected to continue during the next several years. During the three-year period, cash flows from operating activities of Southwest (including the bonus depreciation benefits) are expected to provide approximately 85% of the funding for the gas operations total construction expenditures and dividend requirements. Any additional cash requirements are expected to be provided by existing credit facilities and/or other external financing sources. The timing, types, and amounts of any additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwests service areas, and earnings. External financings could include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.
The Companys $30 million 2003 5.45% Series C fixed-rate IDRBs and $15 million 2003 5.8% Series E fixed-rate IDRBs include a put feature that requires the remarketing of these IDRBs on March 1, 2013. The Company has the option to remarket these IDRBs at various intervals until the due date of 2038. However, once the remarketing process in March 2013 is complete, the Company intends to redeem these IDRBs at par. These IDRBs are shown as current maturities in the Companys consolidated balance sheet. The Company will facilitate the redemption primarily from borrowings under its $300 million credit facility.
Liquidity
Liquidity refers to the ability of an enterprise to generate sufficient amounts of cash through its operating activities and external financings to meet its cash requirements. Several general factors (some of which are out of the control of the Company) that could significantly affect liquidity in future years include: variability of natural gas prices, changes in the ratemaking policies of regulatory commissions, regulatory lag, customer growth in the natural gas segments service territories, Southwests ability to access and obtain capital from external sources, interest rates, changes in income tax laws, pension funding requirements, inflation, and the level of Company earnings. Natural gas prices and related gas cost recovery rates have historically had the most significant impact on Company liquidity.
On an interim basis, Southwest defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2012, the combined balance in the PGA accounts totaled an over-collection of $92.9 million. See PGA Filings for more information.
In March 2012, the Company replaced a $300 million revolving credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. 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 Companys senior unsecured debt rating. At the Companys current unsecured debt rating, the applicable margin is 1.125% for loans bearing interest with reference to LIBOR and 0.125% for loans bearing interest with reference to the alternative base rate. Southwest has designated $150 million of the $300 million facility for long-term borrowing needs and the
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remaining $150 million for working capital purposes. The borrowings at December 31, 2011 (and additional borrowings which resulted in a maximum outstanding balance of $128 million during the first quarter) under the predecessor facility were repaid during the first quarter of 2012. At December 31, 2012, $111 million was outstanding on the long-term portion of the new credit facility (including $20 million under the commercial paper program), and no borrowings were outstanding on the short-term portion. No borrowings occurred under the new facility during the second quarter of 2012, and the maximum amount outstanding during the third and fourth quarters of 2012 was $40 million and $130 million, respectively. The credit facility can be used as necessary to meet liquidity requirements, including temporarily financing under-collected PGA balances, if any, or meeting the refund needs of over-collected balances. This credit facility has been, and is expected to continue to be, adequate for Southwests working capital needs outside of funds raised through operations and other types of external financing.
The Company has a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Companys current revolving credit facility and, therefore, does not represent additional borrowing capacity. Any borrowing under the commercial paper program will be designated as long-term debt. Interest rates for the commercial paper program are calculated at the then current commercial paper rate. At December 31, 2012, $20 million was outstanding on the commercial paper program. The maximum amount outstanding during the year was $20 million.
In June 2012, NPL replaced its existing $30 million revolving credit facility that was to expire in June 2013 with a $75 million facility that is scheduled to expire in June 2015. The credit facility was amended in October 2012 to temporarily increase the facility from $75 million to $85 million until December 29, 2012 and then reverted back to $75 million. Interest rates for the credit facility were also amended in October 2012 and are now calculated at either LIBOR or a base rate, plus, in each case, 1.00% or 0.75% depending on NPLs leverage ratio at the end of each quarter. At December 31, 2012, $41.6 million was outstanding on the NPL credit facility.
Credit Ratings
The Companys borrowing costs and ability to raise funds are directly impacted by its credit ratings. Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., generally the better the rating, the lower the cost to borrow funds).
In March 2012, Moodys upgraded the Companys senior unsecured long-term debt rating to Baa1 from Baa2 (the outlook remains stable). Moodys cited the Companys prospects for continued strong financial results and credit metrics, as well as the resolution of the Arizona rate case as factors in its decision. Moodys applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.
In May 2012, Fitch upgraded the Companys senior unsecured long-term debt rating to A- from BBB+ (the outlook has been revised to positive from stable). Fitch cited the Companys strong operational performance for 2011 and expectations for continued strong performance for 2012, due in part to the recent rate design changes adopted in Arizona. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of A- indicates low credit risk and a strong ability to pay financial commitments.
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The Companys unsecured long-term debt rating from Standard & Poors Ratings Services (S&P) is BBB+ with a stable outlook as of April 2011. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB+ indicates the issuer of the debt is regarded as having an adequate capacity to pay interest and repay principal.
A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency. The foregoing securities ratings are subject to change at any time in the discretion of the applicable ratings agencies. Numerous factors, including many that are not within the Companys control, are considered by the ratings agencies in connection with assigning securities ratings.
No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2012, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.7 billion in additional debt and meet the leverage ratio requirement. The Company has at least $700 million of cushion in equity relating to the minimum net worth requirement.
Inflation
Inflation can impact the Companys results of operations. Natural gas, labor, employee benefits, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to the cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor and employee benefits are components of the cost of service, and construction costs are the primary component of rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.
Off-Balance Sheet Arrangements
All Company debt is recorded on its balance sheets. The Company has long-term operating leases, which are described in Note 2 Utility Plant of the Notes to Consolidated Financial Statements, and included in the Contractual Obligations Table below.
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Contractual Obligations
The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statement of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Companys contractual obligations at December 31, 2012 (millions of dollars):
Payments due by period | ||||||||||||||||||||
Contractual Obligations | Total | 2013 | 2014-2015 | 2016-2017 | Thereafter | |||||||||||||||
Operating activities: |
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Operating leases (Note 2) |
$ | 18 | $ | 7 | $ | 7 | $ | 4 | $ | | ||||||||||
Gas purchase obligations |
165 | 117 | 48 | | | |||||||||||||||
Pipeline capacity |
793 | 110 | 194 | 123 | 366 | |||||||||||||||
Derivatives (Note 13) |
3 | 2 | 1 | | | |||||||||||||||
Other commitments |
15 | 7 | 7 | 1 | | |||||||||||||||
Financing activities: |
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Long-term debt, including current maturities (Note 7) |
1,319 | 50 | 52 | 141 | 1,076 | |||||||||||||||
Interest on long-term debt |
843 | 52 | 102 | 99 | 590 | |||||||||||||||
Other |
16 | | 1 | 2 | 13 | |||||||||||||||
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Total |
$ | 3,172 | $ | 345 | $ | 412 | $ | 370 | $ | 2,045 | ||||||||||
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Obligations for Operating Activities: The table above provides a summary of the Companys obligations associated with operating activities. Operating leases represent multi-year obligations for office rent and certain equipment. Gas purchase obligations include fixed-price and variable-rate gas purchase contracts covering approximately 147 million dekatherms. Fixed-price contracts range in price from approximately $3 to $5 per dekatherm. Variable-price contracts reflect minimum contractual obligations.
Southwest has pipeline capacity contracts for firm transportation service, both on a short- and long-term basis, with several companies for all of its service territories, some with terms extending to 2044. Southwest also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise. Costs associated with these pipeline capacity contracts are a component of the cost of gas sold and are recovered from customers primarily through the PGA mechanism.
Obligations for Financing Activities: Contractual obligations for financing activities are debt obligations consisting of scheduled principal and interest payments over the life of the debt. Southwests plans to redeem $45 million of IDRBs in March 2013 (originally due in 2038) are also reflected in the table above. See Capital Resources and Liquidity.
Other: Estimated funding for pension and other postretirement benefits during calendar year 2013 is $47 million.
Recently Issued Accounting Standards Updates
The Financial Accounting Standards Board (FASB) recently issued Accounting Standards Updates related to offsetting of assets and liabilities on the balance sheets, testing of indefinite-lived intangible
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assets for impairment, and technical corrections and improvements. See Note 1 Summary of Significant Accounting Policies for more information regarding these accounting standards updates and their potential impact on the Companys 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 Companys operating environment changes. The following are accounting policies that are deemed critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1 Summary of Significant Accounting Policies.
Regulatory Accounting
Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated entities and reflect the effects of the ratemaking process. As such, the Company is allowed to defer as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. The Company reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset (which would be recognized as current-period expense). Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The timing and inclusion of costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings. Refer to Note 4 Regulatory Assets and Liabilities for a list of regulatory assets and liabilities.
Accrued Utility Revenues
Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of natural gas sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, margin associated with natural gas service that has been provided but not yet billed is accrued. This accrued utility revenue is estimated each month based primarily on applicable rates, number of customers, rate structure, analyses reflecting significant historical trends, seasonality, and experience. The interplay of these assumptions can impact the variability of the accrued utility revenue estimates. All Company rate jurisdictions have decoupled rate structures, limiting variability due to extreme weather conditions.
Accounting for Income Taxes
The income tax calculations of the Company require estimates due to known future tax rate changes, book to tax differences, and uncertainty with respect to regulatory treatment of certain property items. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability
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method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recoverable from or refunded to customers in future rates. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The Company regularly assesses financial statement tax provisions to identify any change in the regulatory treatment or tax-related estimates, assumptions, or enacted tax rates that could have a material impact on cash flows, the financial position, and/or results of operations of the Company.
Accounting for Pensions and Other Postretirement Benefits
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Companys 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 $31.4 million and future pension expense by $3.3 million. A change of 0.25% in the employee compensation assumption would change the pension obligation by approximately $7.8 million and expense by $1.6 million. A 0.25% change in the expected asset return assumption would change pension expense by approximately $1.5 million (but has no impact on the pension obligation).
At December 31, 2012, the Company lowered the discount rate to 4.25% from a rate of 5.00% at December 31, 2011. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase decreased to 2.75% at December 31, 2012 from 3.00% in the prior year. The asset return assumption remains the same at 8.00%. The significant reduction in the discount rate will increase the expense level for 2013. Pension expense for 2013 is estimated to increase by $6.4 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.
Certifications
The Securities and Exchange Commission (SEC) requires the Company to file certifications of its Chief Executive Officer (CEO) and Chief Financial Officer (CFO) regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to the Companys periodic filings. The CEO and CFO certifications for the period ended December 31, 2012 are included as exhibits to the 2012 Annual Report on Form 10-K filed with the SEC.
Forward-Looking Statements
This annual report contains statements which constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (Reform Act). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements,
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including, without limitation, statements regarding the Companys 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, 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, use of proceeds, the Companys COLI strategy, annual COLI returns, replacement market and new construction market, bonus depreciation tax deductions, amount and timing for completion of estimated future construction expenditures, forecasted operating cash flows and results of operations, incremental operating margin in 2013, operating expense increases in 2013, funding sources of cash requirements, sufficiency of working capital, bank lending practices, the Companys views regarding its liquidity position, ability to raise funds and receive external financing capacity, future dividend increases, earnings trends, NPLs projected financial performance and related market growth potential, NPLs bid contracts (or contracts with caps) and results thereunder, including expectations regarding estimates of costs and revenues, pension and post-retirement benefits, certain benefits of tax acts, the effect of rate decoupling in Arizona, the effect of any rate changes or regulatory proceedings, including the Decision from the PUCN and the California general rate case filing, statements regarding future gas prices, gas purchase contracts and derivative financial instruments, the impact of certain legal proceedings, and the timing and results of future rate hearings and approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.
A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, customer growth rates, conditions in the housing market, the ability to recover costs through the PGA mechanisms, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, effects of pension expense forecasts, accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, results of NPL bid work, impacts of structural and management changes at NPL, acquisitions and managements plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing and operating expenses will continue in future periods. For additional information on the risks associated with the Companys business, see Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures About Market Risk in the Companys Annual Report on Form 10-K for the year ended December 31, 2012.
All forward-looking statements in this annual report are made as of the date hereof, based on information available to the Company as of the date hereof, and the Company assumes no obligation to update or revise any of its forward-looking statements even if experience or future changes show that the indicated results or events will not be realized. We caution you not to unduly rely on any forward-looking statement(s).
37 |
Common Stock Price and Dividend Information
2012 | 2011 | Dividends Declared | ||||||||||||||||||||||
High | Low | High | Low | 2012 | 2011 | |||||||||||||||||||
First quarter |
$ | 43.64 | $ | 40.51 | $ | 39.68 | $ | 36.33 | $ | 0.295 | $ | 0.265 | ||||||||||||
Second quarter |
44.64 | 39.46 | 40.59 | 36.61 | 0.295 | 0.265 | ||||||||||||||||||
Third quarter |
46.08 | 42.19 | 39.92 | 32.12 | 0.295 | 0.265 | ||||||||||||||||||
Fourth quarter |
44.83 | 39.01 | 43.20 | 34.55 | 0.295 | 0.265 | ||||||||||||||||||
|
|
|
|
|||||||||||||||||||||
$ | 1.180 | $ | 1.060 | |||||||||||||||||||||
|
|
|
|
The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2013, there were 15,969 holders of record of common stock, and the market price of the common stock was $44.50.
In reviewing dividend policy, the Board of Directors (Board) considers the adequacy and sustainability of earnings and cash flows of the Company and its subsidiaries; the strength of the Companys capital structure; the sustainability of the dividend through all business cycles; and whether the dividend is within a normal payout range for its respective businesses. The quarterly common stock dividend declared was 25 cents per share throughout 2010, 26.5 cents per share throughout 2011, and 29.5 cents per share throughout 2012. As a result of its ongoing review of dividend policy, in February 2013, the Board increased the quarterly dividend from 29.5 cents to 33 cents per share, effective with the June 2013 payment. This marks the seventh consecutive year in which the dividend was increased. Over time, the Board intends to increase the dividend such that the payout ratio approaches a local distribution company peer group average, while maintaining the Companys stable and strong credit ratings and the ability to effectively fund future rate base growth. The timing and amount of any future increases will be based upon the Boards continued review of the Companys dividend rate in the context of the performance of the Companys two operating segments and their future growth prospects.
38 |
SOUTHWEST GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except par value)
December 31, | 2012 | 2011 | ||||||
ASSETS |
||||||||
Utility plant: |
||||||||
Gas plant |
$ | 5,019,500 | $ | 4,811,050 | ||||
Less: accumulated depreciation |
(1,750,795 | ) | (1,638,091 | ) | ||||
Acquisition adjustments, net |
911 | 1,091 | ||||||
Construction work in progress |
74,178 | 44,894 | ||||||
|
|
|
|
|||||
Net utility plant (Note 2) |
3,343,794 | 3,218,944 | ||||||
|
|
|
|
|||||
Other property and investments |
242,096 | 192,004 | ||||||
|
|
|
|
|||||
Restricted cash |
| 12,785 | ||||||
|
|
|
|
|||||
Current assets: |
||||||||
Cash and cash equivalents |
25,530 | 21,937 | ||||||
Accounts receivable, net of allowances (Note 3) |
196,913 | 209,246 | ||||||
Accrued utility revenue |
72,000 | 70,300 | ||||||
Income taxes receivable, net |
2,945 | 7,793 | ||||||
Deferred income taxes (Note 12) |
47,088 | 53,435 | ||||||
Deferred purchased gas costs (Note 4) |
6,031 | 2,323 | ||||||
Prepaids and other current assets (Notes 1 and 4) |
107,910 | 96,598 | ||||||
|
|
|
|
|||||
Total current assets |
458,417 | 461,632 | ||||||
|
|
|
|
|||||
Deferred charges and other assets (Notes 4 and 13) |
443,750 | 390,642 | ||||||
|
|
|
|
|||||
Total assets |
$ | 4,488,057 | $ | 4,276,007 | ||||
|
|
|
|
39 |
CONSOLIDATED BALANCE SHEETS - Continued
December 31, | 2012 | 2011 | ||||||
CAPITALIZATION AND LIABILITIES |
||||||||
Capitalization: |
||||||||
Common stock, $1 par (authorized 60,000,000 shares; issued and outstanding 46,147,788 and 45,956,088 shares) (Note 11) |
$ | 47,778 | $ | 47,586 | ||||
Additional paid-in capital |
828,777 | 821,640 | ||||||
Accumulated other comprehensive income (loss), net (Note 5) |
(50,745 | ) | (49,331 | ) | ||||
Retained earnings |
484,369 | 406,125 | ||||||
|
|
|
|
|||||
Total Southwest Gas Corporation equity |
1,310,179 | 1,226,020 | ||||||
Noncontrolling interest |
(1,681 | ) | (989 | ) | ||||
|
|
|
|
|||||
Total equity |
1,308,498 | 1,225,031 | ||||||
Long-term debt, less current maturities (Note 7) |
1,268,373 | 930,858 | ||||||
|
|
|
|
|||||
Total capitalization |
2,576,871 | 2,155,889 | ||||||
|
|
|
|
|||||
Commitments and contingencies (Note 9) |
||||||||
Current liabilities: |
||||||||
Current maturities of long-term debt (Note 7) |
50,137 | 322,618 | ||||||
Accounts payable |
155,667 | 186,755 | ||||||
Customer deposits |
77,858 | 83,839 | ||||||
Accrued general taxes |
37,644 | 42,102 | ||||||
Accrued interest |
16,080 | 16,699 | ||||||
Deferred purchased gas costs (Note 4) |
98,957 | 72,426 | ||||||
Other current liabilities (Notes 4 and 13) |
98,786 | 123,129 | ||||||
|
|
|
|
|||||
Total current liabilities |
535,129 | 847,568 | ||||||
|
|
|
|
|||||
Deferred income taxes and other credits: |
||||||||
Deferred income taxes and investment tax credits (Note 12) |
616,184 | 557,118 | ||||||
Taxes payable |
551 | 828 | ||||||
Accumulated removal costs (Note 4) |
256,000 | 233,000 | ||||||
Other deferred credits (Notes 4 and 10) |
503,322 | 481,604 | ||||||
|
|
|
|
|||||
Total deferred income taxes and other credits |
1,376,057 | 1,272,550 | ||||||
|
|
|
|
|||||
Total capitalization and liabilities |
$ | 4,488,057 | $ | 4,276,007 | ||||
|
|
|
|
The accompanying notes are an integral part of these statements.
40 |
SOUTHWEST GAS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
Operating revenues: |
||||||||||||
Gas operating revenues |
$ | 1,321,728 | $ | 1,403,366 | $ | 1,511,907 | ||||||
Construction revenues |
606,050 | 483,822 | 318,464 | |||||||||
|
|
|
|
|
|
|||||||
Total operating revenues |
1,927,778 | 1,887,188 | 1,830,371 | |||||||||
|
|
|
|
|
|
|||||||
Operating expenses: |
||||||||||||
Net cost of gas sold |
479,602 | 613,489 | 736,175 | |||||||||
Operations and maintenance |
369,979 | 358,498 | 354,943 | |||||||||
Depreciation and amortization |
223,422 | 200,469 | 190,463 | |||||||||
Taxes other than income taxes |
41,728 | 40,949 | 38,869 | |||||||||
Construction expenses |
541,523 | 423,703 | 277,804 | |||||||||
|
|
|
|
|
|
|||||||
Total operating expenses |
1,656,254 | 1,637,108 | 1,598,254 | |||||||||
|
|
|
|
|
|
|||||||
Operating income |
271,524 | 250,080 | 232,117 | |||||||||
|
|
|
|
|
|
|||||||
Other income and (expenses): |
||||||||||||
Net interest deductions (Notes 7 and 8) |
(68,020 | ) | (69,602 | ) | (75,677 | ) | ||||||
Net interest deductions on subordinated debentures (Note 6) |
| | (1,912 | ) | ||||||||
Other income (deductions) |
4,411 | (5,412 | ) | 3,850 | ||||||||
|
|
|
|
|
|
|||||||
Total other income and (expenses) |
(63,609 | ) | (75,014 | ) | (73,739 | ) | ||||||
|
|
|
|
|
|
|||||||
Income before income taxes |
207,915 | 175,066 | 158,378 | |||||||||
Income tax expense (Note 12) |
75,276 | 63,303 | 54,925 | |||||||||
|
|
|
|
|
|
|||||||
Net income |
132,639 | 111,763 | 103,453 | |||||||||
Net income (loss) attributable to noncontrolling interest |
(692 | ) | (524 | ) | (424 | ) | ||||||
|
|
|
|
|
|
|||||||
Net income attributable to Southwest Gas Corporation |
$ | 133,331 | $ | 112,287 | $ | 103,877 | ||||||
|
|
|
|
|
|
|||||||
Basic earnings per share (Note 15) |
$ | 2.89 | $ | 2.45 | $ | 2.29 | ||||||
|
|
|
|
|
|
|||||||
Diluted earnings per share (Note 15) |
$ | 2.86 | $ | 2.43 | $ | 2.27 | ||||||
|
|
|
|
|
|
|||||||
Average number of common shares outstanding |
46,115 | 45,858 | 45,405 | |||||||||
Average shares outstanding (assuming dilution) |
46,555 | 46,291 | 45,823 |
The accompanying notes are an integral part of these statements.
41 |
SOUTHWEST GAS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of dollars)
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
Net Income |
$ | 132,639 | $ | 111,763 | $ | 103,453 | ||||||
|
|
|
|
|
|
|||||||
Other comprehensive income (loss), net of tax |
||||||||||||
Defined benefit pension plans (Notes 5 and 10): |
||||||||||||
Net actuarial gain (loss) |
(46,409 | ) | (84,005 | ) | (5,616 | ) | ||||||
Amortization of transition obligation |
538 | 537 | 538 | |||||||||
Amortization of net actuarial loss |
15,870 | 9,653 | 7,516 | |||||||||
Prior service cost |
(1,502 | ) | | | ||||||||
Regulatory adjustment |
26,518 | 65,677 | 404 | |||||||||
|
|
|
|
|
|
|||||||
Net defined benefit pension plans |
(4,985 | ) | (8,138 | ) | 2,842 | |||||||
|
|
|
|
|
|
|||||||
Forward-starting interest rate swaps: |
||||||||||||
Unrealized/realized gain (loss) (Notes 5 and 13) |
1,834 | (11,134 | ) | (11,436 | ) | |||||||
Amounts reclassified into net income (Notes 5 and 13) |
1,737 | 725 | 60 | |||||||||
|
|
|
|
|
|
|||||||
Net forward-starting interest rate swaps |
3,571 | (10,409 | ) | (11,376 | ) | |||||||
|
|
|
|
|
|
|||||||
Total other comprehensive income (loss), net of tax |
(1,414 | ) | (18,547 | ) | (8,534 | ) | ||||||
|
|
|
|
|
|
|||||||
Comprehensive income |
131,225 | 93,216 | 94,919 | |||||||||
Comprehensive income (loss) attributable to noncontrolling interest |
(692 | ) | (524 | ) | (424 | ) | ||||||
|
|
|
|
|
|
|||||||
Comprehensive income attributable to Southwest Gas Corporation |
$ | 131,917 | $ | 93,740 | $ | 95,343 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
42 |
SOUTHWEST GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
CASH FLOW FROM OPERATING ACTIVITIES: |
||||||||||||
Net Income |
$ | 132,639 | $ | 111,763 | $ | 103,453 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
Depreciation and amortization |
223,422 | 200,469 | 190,463 | |||||||||
Deferred income taxes |
66,280 | 56,467 | 50,111 | |||||||||
Changes in current assets and liabilities: |
||||||||||||
Accounts receivable, net of allowances |
12,333 | (61,641 | ) | 10,117 | ||||||||
Accrued utility revenue |
(1,700 | ) | (5,900 | ) | 7,300 | |||||||
Deferred purchased gas costs |
22,823 | (52,885 | ) | 33,013 | ||||||||
Accounts payable |
(25,998 | ) | 15,826 | 6,680 | ||||||||
Accrued taxes |
113 | 14,979 | (15,240 | ) | ||||||||
Other current assets and liabilities |
(18,948 | ) | (3,347 | ) | 12,895 | |||||||
Gains on sale |
(8,040 | ) | (3,307 | ) | (1,547 | ) | ||||||
Changes in undistributed stock compensation |
5,137 | 6,125 | 4,429 | |||||||||
AFUDC and property-related changes |
(1,943 | ) | (1,154 | ) | (945 | ) | ||||||
Changes in other assets and deferred charges |
(15,367 | ) | 11,025 | (12,262 | ) | |||||||
Changes in other liabilities and deferred credits |
(4,427 | ) | (36,378 | ) | (17,474 | ) | ||||||
|
|
|
|
|
|
|||||||
Net cash provided by operating activities |
386,324 | 252,042 | 370,993 | |||||||||
|
|
|
|
|
|
43 |
CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
CASH FLOW FROM INVESTING ACTIVITIES: |
||||||||||||
Construction expenditures and property additions |
(395,712 | ) | (380,991 | ) | (215,439 | ) | ||||||
Restricted cash |
12,785 | 24,996 | 11,988 | |||||||||
Changes in customer advances |
(3,025 | ) | (7,771 | ) | (830 | ) | ||||||
Miscellaneous inflows |
13,963 | 7,686 | 4,075 | |||||||||
Miscellaneous outflows |
(2,004 | ) | (2,719 | ) | (2,800 | ) | ||||||
|
|
|
|
|
|
|||||||
Net cash used in investing activities |
(373,993 | ) | (358,799 | ) | (203,006 | ) | ||||||
|
|
|
|
|
|
|||||||
CASH FLOW FROM FINANCING ACTIVITIES: |
||||||||||||
Issuance of common stock, net |
1,581 | 7,402 | 11,098 | |||||||||
Dividends paid |
(53,040 | ) | (47,929 | ) | (44,846 | ) | ||||||
Interest rate swap settlement |
(21,754 | ) | | (11,691 | ) | |||||||
Issuance of long-term debt, net |
489,518 | 274,598 | 123,960 | |||||||||
Retirement of long-term debt |
(427,043 | ) | (330,473 | ) | (3,327 | ) | ||||||
Redemption of subordinated debentures |
| | (100,000 | ) | ||||||||
Change in credit facility and commercial paper |
2,000 | 109,000 | (92,400 | ) | ||||||||
|
|
|
|
|
|
|||||||
Net cash provided by (used in) financing activities |
(8,738 | ) | 12,598 | (117,206 | ) | |||||||
|
|
|
|
|
|
|||||||
Change in cash and cash equivalents |
3,593 | (94,159 | ) | 50,781 | ||||||||
Cash and cash equivalents at beginning of period |
21,937 | 116,096 | 65,315 | |||||||||
|
|
|
|
|
|
|||||||
Cash and cash equivalents at end of period |
$ | 25,530 | $ | 21,937 | $ | 116,096 | ||||||
|
|
|
|
|
|
|||||||
Supplemental information: |
||||||||||||
Interest paid, net of amounts capitalized |
$ | 87,439 | $ | 69,842 | $ | 87,000 | ||||||
|
|
|
|
|
|
|||||||
Income taxes paid (received) |
$ | 2,843 | $ | (13,635 | ) | $ | 19,200 | |||||
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
44 |
SOUTHWEST GAS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except per share amounts)
Southwest Gas Corporation Equity | ||||||||||||||||||||||||||||
|
||||||||||||||||||||||||||||
Common Stock | Additional Paid-in Capital |
Accumulated Other Comprehensive Income (Loss) |
Retained Earnings |
Non- controlling Interest |
Total |
|||||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||||||
DECEMBER 31, 2009 |
45,092 | $ | 46,722 | $ | 792,339 | $ | (22,250 | ) | $ | 285,316 | $ | (41 | ) | $ | 1,102,086 | |||||||||||||
Common stock issuances |
507 | 507 | 15,546 | 16,053 | ||||||||||||||||||||||||
Net income (loss) |
103,877 | (424 | ) | 103,453 | ||||||||||||||||||||||||
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10) |
2,842 | 2,842 | ||||||||||||||||||||||||||
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13) |
(11,436 | ) | (11,436 | ) | ||||||||||||||||||||||||
Amounts reclassified to net income, net of tax (Notes 5 and 13) |
60 | 60 | ||||||||||||||||||||||||||
Dividends declared Common: $1.00 per share |
(46,062 | ) | (46,062 | ) | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||
DECEMBER 31, 2010 |
45,599 | 47,229 | 807,885 | (30,784 | ) | 343,131 | (465 | ) | 1,166,996 | |||||||||||||||||||
Common stock issuances |
357 | 357 | 13,755 | 14,112 | ||||||||||||||||||||||||
Net income (loss) |
112,287 | (524 | ) | 111,763 | ||||||||||||||||||||||||
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10) |
(8,138 | ) | (8,138 | ) | ||||||||||||||||||||||||
FSIRS realized and unrealized loss, net of tax (Notes 5 and 13) |
(11,134 | ) | (11,134 | ) | ||||||||||||||||||||||||
Amounts reclassified to net income, net of tax (Notes 5 and 13) |
725 | 725 | ||||||||||||||||||||||||||
Dividends declared Common: $1.06 per share |
(49,293 | ) | (49,293 | ) | ||||||||||||||||||||||||
|
45 |
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 |
|||||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||||||
DECEMBER 31, 2011 |
45,956 | 47,586 | 821,640 | (49,331 | ) | 406,125 | (989 | ) | 1,225,031 | |||||||||||||||||||
Common stock issuances |
192 | 192 | 7,137 | 7,329 | ||||||||||||||||||||||||
Net income (loss) |
133,331 | (692 | ) | 132,639 | ||||||||||||||||||||||||
Net actuarial gain (loss) arising during the period, less amortization of unamortized benefit plan cost, net of tax (Notes 5 and 10) |
(4,985 | ) | (4,985 | ) | ||||||||||||||||||||||||
FSIRS realized and unrealized gain, net of tax (Notes 5 and 13) |
1,834 | 1,834 | ||||||||||||||||||||||||||
Amounts reclassified to net income, net of tax (Notes 5 and 13) |
1,737 | 1,737 | ||||||||||||||||||||||||||
Dividends declared Common: $1.18 per share |
(55,087 | ) | (55,087 | ) | ||||||||||||||||||||||||
|
||||||||||||||||||||||||||||
DECEMBER 31, 2012 |
46,148 | * | $ | 47,778 | $ | 828,777 | $ | (50,745 | ) | $ | 484,369 | $ | (1,681 | ) | $ | 1,308,498 | ||||||||||||
|
* | At December 31, 2012, 2.2 million common shares were registered and available for issuance under provisions of the Companys various stock issuance plans. In addition, approximately 125,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 11). |
The accompanying notes are an integral part of these statements.
46 |
Notes to Consolidated Financial Statements
Note 1 Summary of Significant Accounting Policies
Nature of Operations. Southwest Gas Corporation and its subsidiaries (the Company) consist of two segments: natural gas operations (Southwest or the natural gas operations segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. NPL Construction Co. (NPL or the construction services segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (HVAC) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, ICE) and consolidates ICE as a majority-owned subsidiary.
Basis of Presentation. The Company follows generally accepted accounting principles in the United States (U.S. GAAP) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with U.S. GAAP as applied to regulated companies and as prescribed by federal agencies and commissions of the various states in which the utility operates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities.
Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction, less contributions in aid of construction.
Other Property and Investments. Other property and investments includes (millions of dollars):
2012 | 2011 | |||||||
NPL property and equipment |
$ | 287 | $ | 237 | ||||
Accumulated provision for depreciation and amortization |
(136 | ) | (128 | ) | ||||
Net cash surrender value of COLI policies |
80 | 74 | ||||||
Other property |
11 | 9 | ||||||
|
|
|
|
|||||
Total |
$ | 242 | $ | 192 | ||||
|
|
|
|
47 |
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 plant materials and operating supplies of $25 million in 2012 and $21 million in 2011.
Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. For regulatory and financial reporting purposes, investment tax credits (ITC) related to gas utility operations are deferred and amortized over the life of related fixed assets.
Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. 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. During 2012, approximately $20 million of customer advances, upon contract expiration, were applied as contributions offsetting construction expenditures as a non-cash investing activity.
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 Commissions (SEC) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):
December 31, 2012 | December 31, 2011 | |||||||
Accumulated removal costs |
$ | 256,000 | $ | 233,000 | ||||
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|
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Gas Operating Revenues. Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs and state and local laws, regulations, and agreements. An estimate of the margin associated with natural gas service provided, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals.
The Company acts as an agent for state and local taxing authorities in the collection and remission of a variety of taxes, including sales and use taxes and surcharges. These taxes are not included in gas operating revenues. The Company uses the net classification method to report taxes collected from customers to be remitted to governmental authorities.
48 |
Construction Revenues. The majority of NPL contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two weeks or less. Revenues are recorded as installations are completed. Long-term fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized 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 the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps, that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model.
In 2011, NPL recorded $5 million in estimated pretax profit associated with a large fixed-price contract. In connection with significant changes in estimated costs to complete the fixed-price contract, NPL results reflect pretax losses (with after-tax earnings per share impacts) of $15 million ($0.20 per share) for the year ended December 31, 2012, including $18 million ($0.24 per share) in the first half of 2012. The estimated cost changes that resulted in the losses recognized included reductions in projected productivity and higher costs of restoration work. Change orders approved during the fourth quarter of 2012 helped to reduce losses overall on the contract. On a contract-to-date basis the cumulative loss is $10 million. At December 31, 2012, work on this sizeable contract is over 95% complete.
Construction Expenses. The construction expenses classification in the income statement includes payroll expenses, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, and office-related fixed costs of NPL.
Net Cost of Gas Sold. Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of natural gas derivative instruments. Also included are the net impacts of PGA deferrals and recoveries.
Operations and Maintenance Expense. For financial reporting purposes, operations and maintenance expense includes Southwests operating and maintenance costs associated with serving utility customers, uncollectible expense, administrative and general salaries and expense, employee benefits expense, and legal expense (including injuries and damages).
Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for removal costs (net of salvage value), and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense.
Allowance for Funds Used During Construction (AFUDC). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net
49 |
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.
2012 | 2011 | 2010 | ||||||||||
(In thousands) | ||||||||||||
AFUDC: |
||||||||||||
Debt portion |
$ | 1,129 | $ | 718 | $ | 512 | ||||||
Equity portion |
1,943 | 1,154 | 945 | |||||||||
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AFUDC capitalized as part of utility plant |
$ | 3,072 | $ | 1,872 | $ | 1,457 | ||||||
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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):
2012 | 2011 | 2010 | ||||||||||
Change in COLI policies |
$ | 6,600 | $ | 700 | $ | 9,770 | ||||||
Interest income |
924 | 485 | 194 | |||||||||
Pipe replacement costs |
(2,680 | ) | (4,761 | ) | (5,024 | ) | ||||||
Miscellaneous income and (expense) |
(433 | ) | (1,836 | ) | (1,090 | ) | ||||||
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Total other income (deductions) |
$ | 4,411 | $ | (5,412 | ) | $ | 3,850 | |||||
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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 Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, is also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work. The replacement program work subject to non-recoverability was completed in 2012.
Earnings Per Share. Basic earnings per share (EPS) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of additional weighted-average common stock equivalents (stock options, performance shares, and restricted stock units). Unless otherwise noted, the term Earnings Per Share refers to Basic EPS. A reconciliation of the shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.
2012 | 2011 | 2010 | ||||||||||
(In thousands) | ||||||||||||
Average basic shares |
46,115 | 45,858 | 45,405 | |||||||||
Effect of dilutive securities: |
||||||||||||
Stock options |
42 | 52 | 56 | |||||||||
Performance shares |
254 | 271 | 260 | |||||||||
Restricted stock units |
144 | 110 | 102 | |||||||||
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|
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Average diluted shares |
46,555 | 46,291 | 45,823 | |||||||||
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50 |
Recently Issued Accounting Standards Updates. In October 2012, the Financial Accounting Standards Board (FASB) issued the update Technical Corrections and Improvements which clarifies or corrects unintended application of accounting guidance. Many of these changes are not expected to have a significant effect on current accounting practice but some improvements are more substantive and are not technical corrections. Amendments included in the update without transition guidance were effective upon issuance. Amendments subject to transition guidance were effective for the Company on January 1, 2013 for interim and annual reporting periods. The adoption of the update is not expected to have a material impact on the Companys disclosures, financial position, or results of operations.
In July 2012, the FASB issued the update Intangibles Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment, which provides that an entity has the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that an indefinite-lived intangible asset is impaired. If, in electing the qualitative evaluation step, there is no indication of impairment, quantitative impairment testing would not be required to be performed. The update would provide consistency in evaluation for goodwill and indefinite-lived intangibles other than goodwill. The Company adopted this update, as required, on January 1, 2013. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company.
In December 2011, the FASB issued the update Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entitys financial statements to understand the effect of those arrangements on the entitys financial position. In January 2013, the FASB issued the update Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (Clarification) that clarifies the scope of the Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities update. The amendments included in the Clarification apply to entities that have derivatives, repurchase agreements and reverse repurchase agreements, and certain securities borrowing and securities lending transactions that are offset, or subject to a master netting or similar agreement. Entities with other types of financial assets and financial liabilities subject to a master netting or similar agreements would no longer be subject to the disclosure requirements in the initial update. All disclosures are required to be provided retrospectively for all periods presented. The Company adopted both updates, as required, on January 1, 2013 for interim and annual reporting periods. These updates are not expected to have a material impact on the Companys disclosures.
Subsequent Events. Management of the Company monitors events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued or disclosures to be made, and has reflected them where appropriate.
51 |
Note 2 Utility Plant
Net utility plant as of December 31, 2012 and 2011 was as follows (thousands of dollars):
December 31, | 2012 | 2011 | ||||||
Gas plant: |
||||||||
Storage |
$ | 20,503 | $ | 20,496 | ||||
Transmission |
301,505 | 295,103 | ||||||
Distribution |
4,224,560 | 4,048,078 | ||||||
General |
310,936 | 291,639 | ||||||
Other |
161,996 | 155,734 | ||||||
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|
|||||
5,019,500 | 4,811,050 | |||||||
Less: accumulated depreciation |
(1,750,795 | ) | (1,638,091 | ) | ||||
Acquisition adjustments, net |
911 | 1,091 | ||||||
Construction work in progress |
74,178 | 44,894 | ||||||
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|
|||||
Net utility plant |
$ | 3,343,794 | $ | 3,218,944 | ||||
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Depreciation and amortization expense on gas plant was as follows (thousands of dollars):
2012 | 2011 | 2010 | ||||||||||
Depreciation and amortization expense |
$ | 182,612 | $ | 172,712 | $ | 167,050 |
Operating Leases and Rentals. Southwest leases a portion of its corporate headquarters office complex in Las Vegas and its administrative offices in Phoenix. The table below presents the rental payments and the current term expiration dates, although both leases have optional renewal terms available.
2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Corporate headquarters (expires in 2017) |
$ | 2,140 | $ | 2,190 | $ | 2,270 | $ | 2,343 | $ | 1,194 | ||||||||||
Phoenix administrative offices (expires in 2014) |
1,446 | 243 | | | |
In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases and, for the gas segment, are also treated as such for regulatory purposes. NPL has various short-term operating leases of equipment and temporary office sites. The table below presents Southwest rental payments and NPL lease payments that are included in operating expenses for all operating leases (in thousands):
2012 | 2011 | 2010 | ||||||||||
Southwest Gas |
$ | 7,762 | $ | 7,812 | $ | 7,585 | ||||||
NPL |
24,054 | 19,017 | 11,780 | |||||||||
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Consolidated rental payments/lease expense |
$ | 31,816 | $ | 26,829 | $ | 19,365 | ||||||
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52 |
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, 2012 (thousands of dollars):
Year Ending December 31, | ||||
2013 |
$ | 6,757 | ||
2014 |
4,304 | |||
2015 |
3,181 | |||
2016 |
2,510 | |||
2017 |
1,238 | |||
Thereafter |
61 | |||
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Total minimum lease payments |
$ | 18,051 | ||
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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 at December 31, 2012, and the percentage of customers in each of the three states.
Gas utility customer accounts receivable balance (in thousands) |
$ | 94,695 | ||
December 31, 2012 | ||||
Percent of customers by state |
||||
Arizona |
54 | % | ||
Nevada |
36 | % | ||
California |
10 | % |
53 |
Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Customer accounts are subject to collection procedures that vary by jurisdiction (late fee assessment, noticing requirements for disconnection of service, and procedures for actual disconnection and/or reestablishment of service). After disconnection of service, accounts are generally written off approximately one month after inactivation. Dependent upon the jurisdiction, reestablishment of service requires both payment of previously unpaid balances and additional deposit requirements. Provisions for uncollectible accounts are recorded monthly based on experience, customer and rate composition, and write-off processes. They are included in the ratemaking process as a cost of service. The Nevada jurisdictions have a regulatory mechanism associated with the gas cost-related portion of uncollectible accounts. Such amounts are deferred and collected through a surcharge in the ratemaking process. Activity in the allowance account for uncollectibles is summarized as follows (thousands of dollars):
Allowance for Uncollectibles |
||||
Balance, December 31, 2009 |
$ | 3,953 | ||
Additions charged to expense |
2,646 | |||
Accounts written off, less recoveries |
(3,405 | ) | ||
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|
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Balance, December 31, 2010 |
3,194 | |||
Additions charged to expense |
2,678 | |||
Accounts written off, less recoveries |
(2,690 | ) | ||
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|
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Balance, December 31, 2011 |
3,182 | |||
Additions charged to expense |
2,471 | |||
Accounts written off, less recoveries |
(3,149 | ) | ||
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Balance, December 31, 2012 |
$ | 2,504 | ||
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Note 4 Regulatory Assets and Liabilities
Natural gas operations are subject to the regulation of the Arizona Corporation Commission (ACC), the Public Utilities Commission of Nevada (PUCN), the California Public Utilities Commission (CPUC), and the Federal Energy Regulatory Commission (FERC). Southwest accounting policies conform to U.S. GAAP applicable to rate-regulated entities and reflect the effects of the ratemaking process. Accounting treatment for rate-regulated entities allows for deferral as regulatory assets, costs that otherwise would be expensed, if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.
54 |
The following table represents existing regulatory assets and liabilities (thousands of dollars):
December 31, | 2012 | 2011 | ||||||
Regulatory assets: |
||||||||
Accrued pension and other postretirement benefit costs (1) |
$ | 373,615 | $ | 330,844 | ||||
Unrealized net loss on non-trading derivatives (Swaps) (2) |
2,395 | 11,743 | ||||||
Deferred purchased gas costs (3) |
6,031 | 2,323 | ||||||
Accrued purchased gas costs (4) |
30,300 | 18,400 | ||||||
Unamortized premium on reacquired debt (5) |
19,452 | 19,011 | ||||||
Other (6) |
44,927 | 32,988 | ||||||
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|
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476,720 | 415,309 | |||||||
Regulatory liabilities: |
||||||||
Deferred purchased gas costs (3) |
(98,957 | ) | (72,426 | ) | ||||
Accumulated removal costs |
(256,000 | ) | (233,000 | ) | ||||
Unrealized net gain on non-trading derivatives (Swaps) (2) |
(6 | ) | | |||||
Deferred gain on southern Nevada division operations facility (7) |
(392 | ) | (806 | ) | ||||
Unamortized gain on reacquired debt (8) |
(11,934 | ) | (12,470 | ) | ||||
Other (9) |
(6,951 | ) | (14,501 | ) | ||||
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Net regulatory assets |
$ | 102,480 | $ | 82,106 | ||||
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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 balance sheets (thousands of dollars). The actual amounts, when realized at settlement, become a component of purchased gas costs under the Companys purchased gas adjustment (PGA) mechanisms. (See Note 13). |
Instrument | Balance Sheet Location | 2012 | 2011 | |||||||
Swaps |
Deferred charges and other assets | $ | 319 | $ | 621 | |||||
Swaps |
Prepaids and other current assets | 2,076 | 11,122 | |||||||
Swaps |
Other deferred credits | (6 | ) | |
(3) | Balance recovered or refunded on an ongoing basis with interest. |
(4) | Included in Prepaids and other current assets on the Consolidated Balance Sheets and recovered over one year or less. |
(5) | Included in Deferred charges and other assets on the Consolidated Balance Sheets. Recovered over life of debt instruments. |
(6) | Other regulatory assets including deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as margin and interest-tracking accounts, amounts associated with accrued absence time, and deferred post-retirement benefits other than pensions. Recovery periods vary. |
(7) | Balance was originally being amortized over a four-year period beginning in the fourth quarter of 2009. As a result of the most recent Nevada general rate case Decision, the amortization period was extended through 2015. |
(8) | Included in Other deferred credits on the Consolidated Balance Sheet. Amortized over life of debt instruments. |
(9) | Other regulatory liabilities includes amounts associated with income tax and gross-up. |
55 |
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 Companys Consolidated Balance Sheets and Consolidated Statements of Equity.
Related Tax Effects Allocated to Each Component of Other Comprehensive Income (Loss)
2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||
Before- Tax Amount |
Tax (Expense) or Benefit (1) |
Net-of- Tax Amount |
Before- Tax Amount |
Tax (Expense) or Benefit (1) |
Net-of- Tax Amount |
Before- Tax Amount |
Tax (Expense) or Benefit (1) |
Net-of- Tax |
||||||||||||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||||||||||||||
Defined benefit pension plans: |
||||||||||||||||||||||||||||||||||||
Net actuarial gain/(loss) |
$ | (74,853 | ) | $ | 28,444 | $ | (46,409 | ) | $ | (135,492 | ) | $ | 51,487 | $ | (84,005 | ) | $ | (9,058 | ) | $ | 3,442 | $ | (5,616 | ) | ||||||||||||
Amortization of transition obligation |
867 | (329 | ) | 538 | 867 | (330 | ) | 537 | 867 | (329 | ) | 538 | ||||||||||||||||||||||||
Amortization of net actuarial (gain)/loss |
25,597 | (9,727 | ) | 15,870 | 15,569 | (5,916 | ) | 9,653 | 12,122 | (4,606 | ) | 7,516 | ||||||||||||||||||||||||
Prior service cost |
(2,423 | ) | 921 | (1,502 | ) | | | | | | | |||||||||||||||||||||||||
Regulatory adjustment |
42,771 | (16,253 | ) | 26,518 | 105,931 | (40,254 | ) | 65,677 | 652 | (248 | ) | 404 | ||||||||||||||||||||||||
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Pension plans other comprehensive income (loss) |
(8,041 | ) | 3,056 | (4,985 | ) | (13,125 | ) | 4,987 | (8,138 | ) | 4,583 | (1,741 | ) | 2,842 | ||||||||||||||||||||||
FSIRS (designated hedging activities): |
||||||||||||||||||||||||||||||||||||
Unrealized/realized gain (loss) |
2,959 | (1,125 | ) | 1,834 | (17,958 | ) | 6,824 | (11,134 | ) | (18,446 | ) | 7,010 | (11,436 | ) | ||||||||||||||||||||||
Amounts reclassified into net income |
2,801 | (1,064 | ) | 1,737 | 1,169 | (444 | ) | 725 | 97 | (37 | ) | 60 | ||||||||||||||||||||||||
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FSIRS other comprehensive income (loss) |
5,760 | (2,189 | ) | 3,571 | (16,789 | ) | 6,380 | (10,409 | ) | (18,349 | ) | 6,973 | (11,376 | ) | ||||||||||||||||||||||
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Total other comprehensive income (loss) |
$ | (2,281 | ) | $ | 867 | $ | (1,414 | ) | $ | (29,914 | ) | $ | 11,367 | $ | (18,547 | ) | $ | (13,766 | ) | $ | 5,232 | $ | (8,534 | ) | ||||||||||||
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(1) | Tax amounts are calculated using a 38% rate. |
Approximately $2.1 million of realized losses (net of tax) related to the forward-starting interest rate swaps (FSIRS), reported in AOCI at December 31, 2012, will be reclassified into expense within the next twelve months as the related interest payments on long-term debt occur.
56 |
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 |
$ | 32,400 | ||
SERP net actuarial loss |
1,000 | |||
PBOP net actuarial loss |
1,000 | |||
PBOP prior service cost |
400 |
The following represents a rollforward of AOCI, presented on the Companys Consolidated Balance Sheets and its Consolidated Statements of Equity:
AOCI Rollforward
(Thousands of dollars)
Defined Benefit Plans (Note 10) | FSIRS (Note 13) | |||||||||||||||||||||||||||
Before- Tax |
Tax (Expense) Benefit |
After- Tax |
Before- Tax |
Tax (Expense) Benefit |
After- Tax |
AOCI | ||||||||||||||||||||||
Beginning Balance AOCI December 31, 2011 |
$ | (44,429 | ) | $ | 16,883 | $ | (27,546 | ) | $ | (35,138 | ) | $ | 13,353 | $ | (21,785 | ) | $ | (49,331 | ) | |||||||||
Current period other comprehensive income (loss) |
(8,041 | ) | 3,056 | (4,985 | ) | 5,760 | (2,189 | ) | 3,571 | (1,414 | ) | |||||||||||||||||
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Ending Balance AOCI December 31, 2012 |
$ | (52,470 | ) | $ | 19,939 | $ | (32,531 | ) | $ | (29,378 | ) | $ | 11,164 | $ | (18,214 | ) | $ | (50,745 | ) | |||||||||
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The following table represents amounts (before income tax impacts) included in Accumulated other comprehensive income (in the table above), that have not yet been recognized in net periodic benefit cost, as of December 31, 2012 and 2011:
Amounts Recognized in AOCI (Before Tax)
(Thousands of dollars)
2012 | 2011 | |||||||
Net actuarial (loss) gain |
$ | (423,662 | ) | $ | (374,406 | ) | ||
Prior service cost |
(2,423 | ) | | |||||
Net transition obligation |
| (867 | ) | |||||
Less: amount recognized in regulatory assets |
373,615 | 330,844 | ||||||
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|
|
|||||
Recognized in AOCI |
$ | (52,470 | ) | $ | (44,429 | ) | ||
|
|
|
|
See Note 10 Pension and Other Postretirement Benefits for more information on the defined benefit pension plans and Note 13 Derivatives and Fair Value Measurements for more information on the FSIRS.
Note 6 Preferred Trust Securities and Subordinated Debentures
In June 2003, the Company created Southwest Gas Capital II (Trust II), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In
57 |
August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (Preferred Trust Securities). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (Common Securities), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures (Subordinated Debentures) to Trust II. The Subordinated Debentures became redeemable at the option of the Company in August 2008.
In February 2010, the Company notified holders of the Subordinated Debentures that all of these debentures (and the associated preferred and common securities) would be redeemed (at par) by the Company in March 2010. All of the outstanding Subordinated Debentures were redeemed in March 2010. The Company accomplished the redemption using existing cash and borrowings under the previous $300 million credit facility.
Interest payments and amortizations associated with the Subordinated Debentures are classified on the 2010 consolidated statement of income as Net interest deductions on subordinated debentures.
Note 7 Long-Term Debt
Carrying amounts of the Companys long-term debt and their related estimated fair values as of December 31, 2012 and December 31, 2011 are disclosed in the following table. The fair values of the revolving credit facility, the NPL revolving credit facility, and the variable-rate Industrial Development Revenue Bonds (IDRBs) approximate their carrying values, and 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. The market values of debentures (except the 4.45% Notes) and fixed-rate IDRBs are categorized as Level 2. The 4.45% Notes and NPL other debt obligations are categorized as Level 3 (based on significant unobservable inputs to their fair values). Fair values for the debentures, fixed-rate IDRBs, and NPL other debt obligations were determined through 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 and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.
December 31, | 2012 | 2011 | ||||||||||||||
Carrying Amount |
Market Value |
Carrying Amount |
Market Value |
|||||||||||||
(Thousands of dollars) | ||||||||||||||||
Debentures: |
||||||||||||||||
Notes, 7.625%, due 2012 |
$ | | $ | | $ | 200,000 | $ | 204,312 | ||||||||
Notes, 4.45%, due 2020 |
125,000 | 141,771 | 125,000 | 128,673 | ||||||||||||
Notes, 6.1%, due 2041 |
125,000 | 165,779 | 125,000 | 143,074 | ||||||||||||
Notes, 3.875%, due 2022 |
250,000 | 277,950 | | | ||||||||||||
8% Series, due 2026 |
75,000 | 111,501 | 75,000 | 96,340 | ||||||||||||
Medium-term notes, 7.59% series, due 2017 |
25,000 | 30,710 | 25,000 | 30,199 | ||||||||||||
Medium-term notes, 7.78% series, due 2022 |
25,000 | 34,637 | 25,000 | 31,932 | ||||||||||||
Medium-term notes, 7.92% series, due 2027 |
25,000 | 36,953 | 25,000 | 31,648 | ||||||||||||
Medium-term notes, 6.76% series, due 2027 |
7,500 | 10,058 | 7,500 | 8,510 | ||||||||||||
Unamortized discount |
(3,403 | ) | (2,087 | ) | ||||||||||||
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654,097 | 605,413 | |||||||||||||||
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Revolving credit facility and commercial paper |
111,000 | 111,000 | 109,000 | 109,000 | ||||||||||||
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|
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December 31, | 2012 | 2011 | ||||||||||||||
Carrying Amount |
Market Value |
Carrying Amount |
Market Value |
|||||||||||||
(Thousands of dollars) | ||||||||||||||||
Industrial development revenue bonds: |
||||||||||||||||
Variable-rate bonds: |
||||||||||||||||
Tax-exempt Series A, due 2028 |
50,000 | 50,000 | 50,000 | 50,000 | ||||||||||||
2003 Series A, due 2038 |
50,000 | 50,000 | 50,000 | 50,000 | ||||||||||||
2008 Series A, due 2038 |
50,000 | 50,000 | 50,000 | 50,000 | ||||||||||||
2009 Series A, due 2039 |
50,000 | 50,000 | 50,000 | 50,000 | ||||||||||||
Fixed-rate bonds: |
||||||||||||||||
6.10% 1999 Series A, due 2038 |
| | 12,410 | 12,410 | ||||||||||||
5.95% 1999 Series C, due 2038 |
| | 14,320 | 14,449 | ||||||||||||
5.55% 1999 Series D, due 2038 |
8,270 | 8,375 | 8,270 | 8,253 | ||||||||||||
5.45% 2003 Series C, due 2038 (rate resets in March 2013) |
30,000 | 30,152 | 30,000 | 31,332 | ||||||||||||
5.25% 2003 Series D, due 2038 |
20,000 | 20,571 | 20,000 | 19,583 | ||||||||||||
5.80% 2003 Series E, due 2038 (rate resets in March 2013) |
15,000 | 15,102 | 15,000 | 15,634 | ||||||||||||
5.25% 2004 Series A, due 2034 |
65,000 | 66,955 | 65,000 | 64,291 | ||||||||||||
5.00% 2004 Series B, due 2033 |
31,200 | 31,655 | 31,200 | 30,283 | ||||||||||||
4.85% 2005 Series A, due 2035 |
100,000 | 101,184 | 100,000 | 94,836 | ||||||||||||
4.75% 2006 Series A, due 2036 |
24,855 | 25,189 | 24,855 | 23,179 | ||||||||||||
Unamortized discount |
(3,195 | ) | (3,360 | ) | ||||||||||||
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491,130 | 517,695 | |||||||||||||||
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NPL credit facility |
41,562 | 41,562 | 16,566 | 16,566 | ||||||||||||
NPL other debt obligations |
20,721 | 20,991 | 4,802 | 4,814 | ||||||||||||
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1,318,510 | 1,253,476 | |||||||||||||||
Less: current maturities |
(50,137 | ) | (322,618 | ) | ||||||||||||
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|
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Long-term debt, less current maturities |
$ | 1,268,373 | $ | 930,858 | ||||||||||||
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|
|
In January 2012, the Company redeemed at par its $12.4 million 1999 6.1% Series A fixed-rate IDRBs (originally due in 2038). In August 2012, the Company redeemed at par its $14.3 million 1999 5.95% Series C fixed-rate IDRBs (originally due in 2038).
In March 2012, the Company issued $250 million in 3.875% Senior Notes at a 0.034% discount. The notes will mature on April 1, 2022. Management used approximately $200 million of the net proceeds in connection with the repayment of the $200 million 7.625% Senior Notes that matured in May 2012. The remaining net proceeds were used for general corporate purposes.
In March 2012, the Company replaced the existing $300 million revolving credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Interest rates for the credit facility are calculated at either the London Interbank Offered Rate (LIBOR) or the alternate base rate, plus, in each case, an applicable margin that is determined based on the Companys senior unsecured debt rating. At the Companys current unsecured debt rating, the applicable margin is 1.125% for loans bearing interest with reference to LIBOR and 0.125% for loans bearing interest with reference to the
59 |
alternative base rate. Southwest has designated $150 million of the $300 million facility for long-term purposes and the remaining $150 million for working capital purposes. At December 31, 2012, $91 million was outstanding on the credit facility. Borrowings under the credit facility ranged from $0 during the second quarter of 2012 to a high of $130 million during November 2012. The effective interest rate on the long-term portion of the credit facility was 1.43% at December 31, 2012. There were no borrowings outstanding on the short-term portion of the credit facility at December 31, 2011 and 2012. (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 Companys 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 new program are calculated at the then current commercial paper rate. At December 31, 2012, $20 million was outstanding on the commercial paper program. The effective interest rate on the commercial paper program was 0.84% at December 31, 2012.
In February 2013, a notice of mandatory tender was sent to holders of the Clark County, Nevada 5.45% Series 2003C and 5.80% Series 2003E IDRBs. These IDRBs (totaling $45 million) are subject to mandatory tender on March 1, 2013 at a price of 100% plus accrued interest, and the Company intends to tender these IDRBs to the trustee for cancellation immediately following the mandatory tender, thereby extinguishing this debt. Therefore, these IDRBs are shown as current maturities in the Companys consolidated balance sheet. The Company will facilitate the redemption primarily from borrowings under its $300 million credit facility.
In June 2012, NPL replaced its existing $30 million revolving credit facility that was to expire in June 2013 with a $75 million facility that is scheduled to expire in June 2015. The credit facility was amended in October 2012 to temporarily increase the facility from $75 million to $85 million until December 29, 2012 and then reverted back to $75 million. Interest rates for the credit facility were also amended in October 2012 and are now calculated at either LIBOR or a base rate, plus, in each case, 1.00% or 0.75% depending on NPLs leverage ratio at the end of each quarter. At December 31, 2012, $41.6 million was outstanding on the NPL credit facility. The effective interest rate on NPLs credit facility was 0.97% at December 31, 2012.
The effective interest rates on the variable-rate IDRBs are included in the table below:
December 31, 2012 | December 31, 2011 | |||||||
2003 Series A |
1.71 | % | 0.83 | % | ||||
2008 Series A |
1.59 | % | 1.62 | % | ||||
2009 Series A |
1.14 | % | 1.56 | % | ||||
Tax-exempt Series A |
1.25 | % | 2.22 | % |
In Nevada, interest fluctuations due to changing interest rates on the 2003 Series A, 2008 Series A, and 2009 Series A variable-rate IDRBs are tracked and recovered from ratepayers through an interest balancing account.
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Estimated maturities of long-term debt for the next five years are (in thousands):
2013 |
$ | 50,137 | ||
2014 |
5,249 | |||
2015 |
46,705 | |||
2016 |
4,143 | |||
2017 |
137,049 |
No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain securities ratings covenants that, if set in motion, would increase financing costs. Certain debt instruments also have leverage ratio caps and minimum net worth requirements. At December 31, 2012, the Company is in compliance with all of its covenants. Under the most restrictive of the covenants, the Company could issue over $1.7 billion in additional debt and meet the leverage ratio requirement. The Company has at least $700 million of cushion in equity relating to the minimum net worth requirement.
Note 8 Short-Term Debt
As discussed in Note 7, Southwest replaced the existing $300 million credit facility that was to expire in May 2012 with a $300 million facility that is scheduled to expire in March 2017. Of the $300 million available under the facility, $150 million was designated by management for working capital purposes. The Company had no short-term borrowings outstanding at December 31 in either 2011 or 2012.
Note 9 Commitments and Contingencies
The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is currently subject will have a material adverse impact on its financial position or results of operations.
The Company maintains liability insurance for various risks associated with the operation of its natural gas pipelines and facilities. In connection with these liability insurance policies, the Company is responsible for an initial deductible or self-insured retention amount per incident, after which the insurance carriers are responsible for amounts up to the policy limits. The self-insured retention amount associated with general liability claims is $1 million per incident plus payment of the first $5 million in aggregate claims above $1 million in the policy year.
Note 10 Pension and Other Postretirement Benefits
Southwest has an Employees Investment Plan that provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deduction of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is 3.5% of an employees annual compensation. NPL has a separate plan, the cost and liability of which are not significant. The cost of the Southwest plan is listed below (in thousands):
2012 | 2011 | 2010 | ||||||||||
Employee Investment Plan cost |
$ | 4,707 | $ | 4,626 | $ | 4,583 |
61 |
Southwest has a deferred compensation plan for all officers and a separate deferred compensation plan for members of the Board of Directors. The plans provide the opportunity to defer up to 100% of annual cash compensation. Southwest matches one-half of amounts deferred by officers, up to a maximum matching contribution of 3.5% of an officers 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 Moodys Seasoned Corporate Bond Rate Index.
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees and a separate unfunded supplemental retirement plan (SERP) which is limited to officers. Southwest also provides postretirement benefits other than pensions (PBOP) to its qualified retirees for health care, dental, and life insurance benefits.
The Company recognizes the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in its balance sheets. Any actuarial gains and losses, prior service costs and transition assets or obligations are recognized in accumulated other comprehensive income under stockholders equity, net of tax, until they are amortized as a component of net periodic benefit cost.
In accordance with regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities, the Company has established a regulatory asset for the portion of the total amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through rates in future periods. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset will be recognized as an adjustment to the regulatory asset account as these amounts are recognized as components of net periodic pension costs each year.
Investment objectives and strategies for the qualified retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors of the Company. They are designed to enhance capital, maintain minimum liquidity required for retirement plan operations and effectively manage pension assets.
A target portfolio of investments in the qualified retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Asset return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. The current percentage ranges of the target portfolio are:
Type of Investment | Percentage Range | |||
Equity securities |
59 to 71 | |||
Debt securities |
31 to 37 | |||
Other |
up to 5 |
The Companys 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
62 |
include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan.
U.S. GAAP states that the assumed discount rate should reflect the rate at which the pension benefits could be effectively settled. In making this estimate, in addition to rates implicit in current prices of annuity contracts that could be used to settle the liabilities, employers may look to rates of return on high-quality fixed-income investments available on December 31 of each year and expected to be available during the period to maturity of the pension benefits. In determining the discount rate, the Company matches the plans projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are generally made in increments of 25 basis points.
Due to the continuing low interest rate environment for high-quality fixed income investments, the Company lowered the discount rate in 2012 from 2011. The methodology utilized to determine the discount rate was consistent with prior years. The weighted-average rate of compensation increase was also lowered (consistent with managements expectations overall) in 2012 from 2011 and the asset return assumption was unchanged between periods. The rates are presented in the table below:
December 31, 2012 | December 31, 2011 | |||||||
Discount rate |
4.25 | % | 5.00 | % | ||||
Weighted-average rate of compensation increase |
2.75 | % | 3.00 | % | ||||
Asset return assumption |
8.00 | % | 8.00 | % |
The significant reduction in the discount rate will increase the expense level for 2013. Pension expense for 2013 is estimated to increase by $6.4 million. Future years expense level movements (up or down) will continue to be greatly influenced by long-term interest rates, asset returns, and funding levels.
63 |
The following table sets forth the retirement plan, SERP, and PBOP funded statuses and amounts recognized on the Consolidated Balance Sheets and Statements of Income.
2012 | 2011 | |||||||||||||||||||||||
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) |
$ | 780,571 | $ | 33,827 | $ | 52,182 | $ | 662,134 | $ | 31,860 | $ | 46,765 | ||||||||||||
Service cost |
20,319 | 274 | 977 | 17,725 | 217 | 858 | ||||||||||||||||||
Interest cost |
38,266 | 1,629 | 2,547 | 37,276 | 1,766 | 2,631 | ||||||||||||||||||
Plan amendments |
- | - | 2,423 | - | - | - | ||||||||||||||||||
Actuarial loss (gain) |
92,409 | 4,111 | 2,775 | 89,922 | 2,427 | 2,835 | ||||||||||||||||||
Benefits paid |
(28,753 | ) | (2,468 | ) | (1,200 | ) | (26,486 | ) | (2,443 | ) | (907 | ) | ||||||||||||
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Benefit obligation at end of year (PBO/PBO/APBO) |
902,812 | 37,373 | 59,704 | 780,571 | 33,827 | 52,182 | ||||||||||||||||||
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Change in plan assets |
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Market value of plan assets at beginning of year |
521,829 | - | 29,944 | 475,931 | - | 29,640 | ||||||||||||||||||
Actual return on plan assets |
68,174 | - | 4,454 | 2,384 | - | (200 | ) | |||||||||||||||||
Employer contributions |
48,500 | 2,468 | 1,256 | 70,000 | 2,443 | 904 | ||||||||||||||||||
Benefits paid |
(28,753 | ) | (2,468 | ) | (404 | ) | (26,486 | ) | (2,443 | ) | (400 | ) | ||||||||||||
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Market value of plan assets at end of year |
609,750 | - | 35,250 | 521,829 | - | 29,944 | ||||||||||||||||||
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Funded status at year end |
$ | (293,062 | ) | $ | (37,373 | ) | $ | (24,454 | ) | $ | (258,742 | ) | $ | (33,827 | ) | $ | (22,238 | ) | ||||||
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Weighted-average assumptions (benefit obligation) |
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Discount rate |
4.25 | % | 4.25 | % | 4.25 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||||||
Weighted-average rate of compensation increase |
2.75 | % | 2.75 | % | 2.75 | % | 3.00 | % | 3.00 | % | 3.00 | % |
Estimated funding for the plans above during calendar year 2013 is approximately $49 million of which $46 million pertains to the retirement plan. Management monitors plan assets and liabilities and could, at its discretion, increase plan funding levels above the minimum in order to achieve a desired funded status and avoid or minimize potential benefit restrictions.
The accumulated benefit obligation for the retirement plan and the SERP is presented below (in thousands):
December 31, 2012 | December 31, 2011 | |||||||
Retirement plan |
$ | 811,184 | $ | 699,269 | ||||
SERP |
35,362 | 32,695 |
64 |
Benefits expected to be paid for the pension, PBOP, and the SERP over the next 10 years are as follows (in millions):
2013 | 2014 | 2015 | 2016 | 2017 | 2018-2022 | |||||||||||||||||||
Pension |
$ | 33.2 | $ | 34.9 | $ | 36.7 | $ | 38.5 | $ | 40.6 | $ | 234.4 | ||||||||||||
PBOP |
2.6 | 2.8 | 3.0 | 3.2 | 3.3 | 17.4 | ||||||||||||||||||
SERP |
2.5 | 2.5 | 2.5 | 2.5 | 2.5 | 12.0 |
No assurance can be made that actual funding and benefits paid will match these estimates.
For PBOP measurement purposes, the per capita cost of the covered health care benefits medical rate trend assumption is 7.5% declining to 5%. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays all covered health care costs for employees who retired prior to 1989. The medical trend rate assumption noted above applies to the benefit obligations of pre-1989 retirees only.
Components of net periodic benefit cost
Qualified Retirement Plan |
SERP | PBOP | ||||||||||||||||||||||||||||||||||
2012 | 2011 | 2010 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||||||||||||||
Service cost |
$ | 20,319 | $ | 17,725 | $ | 16,932 | $ | 274 | $ | 217 | $ | 372 | $ | 977 | $ | 858 | $ | 856 | ||||||||||||||||||
Interest cost |
38,266 | 37,276 | 35,614 | 1,629 | 1,766 | 2,045 | 2,547 | 2,631 | 2,491 | |||||||||||||||||||||||||||
Expected return on plan assets |
(45,780 | ) | (40,114 | ) | (36,538 | ) | - | - | - | (2,404 | ) | (2,379 | ) | (2,093 | ) | |||||||||||||||||||||
Amortization of transition obligation |
- | - | - | - | - | - | 867 | 867 | 867 | |||||||||||||||||||||||||||
Amortization of net actuarial loss |
23,883 | 14,348 | 10,478 | 683 | 631 | 1,155 | 1,031 | 590 | 489 | |||||||||||||||||||||||||||
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Net periodic benefit cost |
$ | 36,688 | $ | 29,235 | $ | 26,486 | $ | 2,586 | $ | 2,614 | $ | 3,572 | $ | 3,018 | $ | 2,567 | $ | 2,610 | ||||||||||||||||||
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Weighted-average assumptions (net benefit cost) |
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Discount rate |
5.00 | % | 5.75 | % | 6.00 | % | 5.00 | % | 5.75 | % | 6.00 | % | 5.00 | % | 5.75 | % | 6.00 | % | ||||||||||||||||||
Expected return on plan assets |
8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | 8.00 | % | ||||||||||||||||||
Weighted-average rate of compensation increase |
3.00 | % | 3.25 | % | 3.25 | % | 3.00 | % | 3.25 | % | 3.25 | % | 3.00 | % | 3.25 | % | 3.25 | % |
65 |
Other Changes in Plan Assets and Benefit Obligations Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||||||||||||||
Total | Qualified Retirement Plan |
SERP | PBOP | Total | Qualified Retirement Plan |
SERP | PBOP | Total | Qualified Retirement Plan |
SERP | PBOP | |||||||||||||||||||||||||||||||||||||
(Thousands of dollars) |
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Net actuarial loss (gain) (a) |
$ | 74,853 | $ | 70,016 | $ | 4,111 | $ | 726 | $ | 135,492 | $ | 127,651 | $ | 2,427 | $ | 5,414 | $ | 9,058 | $ | 10,994 | $ | (3,480 | ) | $ | 1,544 | |||||||||||||||||||||||
Amortization of transition obligation (b) |
(867 | ) | - | - | (867 | ) | (867 | ) | - | - | (867 | ) | (867 | ) | - | - | (867 | ) | ||||||||||||||||||||||||||||||
Amortization of net actuarial loss (b) |
(25,597 | ) | (23,883 | ) | (683 | ) | (1,031 | ) | (15,569 | ) | (14,348 | ) | (631 | ) | (590 | ) | (12,122 | ) | (10,478 | ) | (1,155 | ) | (489 | ) | ||||||||||||||||||||||||
Prior service cost |
2,423 | - | - | 2,423 | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||||||
Regulatory adjustment |
(42,771 | ) | (41,520 | ) | - | (1,251 | ) | (105,931 | ) | (101,974 | ) | - | (3,957 | ) | (652 | ) | (464 | ) | - | (188 | ) | |||||||||||||||||||||||||||
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Recognized in other comprehensive (income) loss |
8,041 | 4,613 | 3,428 | - | 13,125 | 11,329 | 1,796 | - | (4,583 | ) | 52 | (4,635 | ) | - | ||||||||||||||||||||||||||||||||||
Net periodic benefit costs recognized in net income |
42,292 | 36,688 | 2,586 | 3,018 | 34,416 | 29,235 | 2,614 | 2,567 | 32,668 | 26,486 | 3,572 | 2,610 | ||||||||||||||||||||||||||||||||||||
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Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss |
$ | 50,333 | $ | 41,301 | $ | 6,014 | $ | 3,018 | $ | 47,541 | $ | 40,564 | $ | 4,410 | $ | 2,567 | $ | 28,085 | $ | 26,538 | $ | (1,063 | ) | $ | 2,610 | |||||||||||||||||||||||
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The table above discloses the net gain or loss, prior service cost, and transition amount recognized in other comprehensive income, separated into (a) amounts initially recognized in other comprehensive income, and (b) amounts subsequently recognized as adjustments to other comprehensive income as those amounts are amortized as components of net periodic benefit cost.
See also Note 5 Other Comprehensive Income and Accumulated Other Comprehensive Income (AOCI).
U.S. GAAP states that a fair value measurement should be based on the assumptions that market participants would use in pricing the asset or liability and establishes a fair value hierarchy that ranks the inputs used to measure fair value by their reliability. The three levels of the fair value hierarchy are as follows:
Level 1 quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access at the measurement date.
Level 2 inputs other than quoted prices included within Level 1 that are observable for similar assets or liabilities, either directly or indirectly.
66 |
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, 2012 and December 31, 2011. The SERP has no assets. There were no transfers between Levels 1 and 2.
December 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Qualified Retirement Plan |
PBOP | Total | Qualified Retirement Plan |
PBOP | Total | |||||||||||||||||||
Assets at fair value (thousands of dollars): |
||||||||||||||||||||||||
Level 1 - Quoted prices in active markets for identical financial assets |
||||||||||||||||||||||||
Cash equivalents |
$ | | $ | | $ | | $ | 20 | $ | 1 | $ | 21 | ||||||||||||
Common stock |
||||||||||||||||||||||||
Capital equipment |
3,510 | 106 | 3,616 | 4,332 | 133 | 4,465 | ||||||||||||||||||
Chemicals/materials |
6,741 | 204 | 6,945 | 7,425 | 227 | 7,652 | ||||||||||||||||||
Consumer goods |
49,247 | 1,492 | 50,739 | 40,806 | 1,249 | 42,055 | ||||||||||||||||||
Energy and mining |
39,454 | 1,195 | 40,649 | 39,080 | 1,196 | 40,276 | ||||||||||||||||||
Finance/insurance |
28,861 | 874 | 29,735 | 23,808 | 729 | 24,537 | ||||||||||||||||||
Healthcare |
29,615 | 897 | 30,512 | 26,070 | 798 | 26,868 | ||||||||||||||||||
Information technology |
30,534 | 925 | 31,459 | 29,052 | 889 | 29,941 | ||||||||||||||||||
Services |
25,316 | 767 | 26,083 | 17,417 | 533 | 17,950 | ||||||||||||||||||
Telecommunications/utilities |
24,355 | 738 | 25,093 | 16,257 | 498 | 16,755 | ||||||||||||||||||
Other |
20,298 | 615 | 20,913 | 22,473 | 688 | 23,161 | ||||||||||||||||||
Real estate investment trusts |
6,572 | 199 | 6,771 | 5,779 | 177 | 5,956 | ||||||||||||||||||
Mutual funds |
67,749 | 17,802 | 85,551 | 57,512 | 14,154 | 71,666 | ||||||||||||||||||
Government fixed income securities |
18,663 | 565 | 19,228 | 5,727 | 175 | 5,902 | ||||||||||||||||||
Futures contracts |
| | | 4 | | 4 | ||||||||||||||||||
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Total Level 1 Assets (1) |
$ | 350,915 | $ | 26,379 | $ | 377,294 | $ | 295,762 | $ | 21,447 | $ | 317,209 | ||||||||||||
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Level 2Significant other observable inputs |
||||||||||||||||||||||||
Commercial paper |
$ | 635 | $ | 19 | $ | 654 | $ | | $ | | $ | | ||||||||||||
Government fixed income and mortgage backed securities |
42,997 | 1,302 | 44,299 | 42,361 | 1,297 | 43,658 | ||||||||||||||||||
Corporate fixed income securities |
||||||||||||||||||||||||
Asset-backed and mortgage-backed |
16,637 | 504 | 17,141 | 16,969 | 519 | 17,488 | ||||||||||||||||||
Banking |
17,966 | 544 | 18,510 | 16,192 | 496 | 16,688 | ||||||||||||||||||
Utilities |
4,107 | 124 | 4,231 | 5,064 | 155 | 5,219 | ||||||||||||||||||
Other |
28,925 | 876 | 29,801 | 25,769 | 789 | 26,558 | ||||||||||||||||||
Pooled funds and mutual funds |
20,636 | 1,789 | 22,425 | 17,447 | 2,244 | 19,691 | ||||||||||||||||||
State and local obligations |
1,273 | 39 | 1,312 | 936 | 29 | 965 | ||||||||||||||||||
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Total Level 2 assets (2) |
$ | 133,176 | $ | 5,197 | $ | 138,373 | $ | 124,738 | $ | 5,529 | $ | 130,267 | ||||||||||||
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67 |
December 31, 2012 | December 31, 2011 | |||||||||||||||||||||||
Qualified Retirement Plan |
PBOP | Total | Qualified Retirement Plan |
PBOP | Total | |||||||||||||||||||
Level 3Significant unobservable inputs |
||||||||||||||||||||||||
Commingled equity funds |
$ | 123,719 | $ | 3,748 | $ | 127,467 | $ | 97,295 | $ | 2,978 | $ | 100,273 | ||||||||||||
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Total Level 3 assets (3) |
$ | 123,719 | $ | 3,748 | $ | 127,467 | $ | 97,295 | $ | 2,978 | $ | 100,273 | ||||||||||||
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Total Plan assets at fair value |
$ | 607,810 | $ | 35,324 | $ | 643,134 | $ | 517,795 | $ | 29,954 | $ | 547,749 | ||||||||||||
Insurance company general account contracts (4) |
4,626 | | 4,626 | 4,952 | | 4,952 | ||||||||||||||||||
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Total Plan assets (5) |
$ | 612,436 | $ | 35,324 | $ | 647,760 | $ | 522,747 | $ | 29,954 | $ | 552,701 | ||||||||||||
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(1) | Common stock, Real Estate Investment Trusts, mutual funds, and U.S. Government securities listed or regularly traded on a national securities exchange are valued at quoted market prices as of the last business day of the calendar year. |
The mutual funds category above is an intermediate-term bond fund whose manager employs multiple concurrent strategies and takes only moderate risk in each, thereby reducing the risk of poor performance arising from any single source, and a balanced fund that invests in a diversified portfolio of common stocks, preferred stocks and fixed-income securities. Strategies utilized by the bond fund include duration management, yield curve or maturity structuring, sector rotation, and all bottom-up techniques including in-house credit and quantitative research. Strategies employed by the balanced fund include pursuit of regular income, conservation of principal, and an opportunity for long-term growth of principal and income.
(2) | The fair value of investments in debt securities with remaining maturities of one year or more is determined by dealers who make markets in such securities or by an independent pricing service, which considers yield or price of bonds of comparable quality, coupon, maturity, and type. |
The pooled funds and mutual funds are two collective short-term funds that invest in Treasury bills and money market funds. These funds are used as a temporary cash repository for the pension plans various investment managers.
(3) | Assets not considered Level 1 or Level 2 are valued using assumptions based on the best information available under the circumstances, such as investment manager pricing. |
The commingled equity funds include private equity funds that invest in international securities (predominately Level 1 assets) regularly traded on securities exchanges. These funds are shown in the above table at net asset value. Investment strategies employed by the funds include:
| Investing in various industries with growth and reasonable valuations, avoiding highly cyclical industries |
| Diversification by country, limiting exposure in any one country |
| Emerging markets |
68 |
The terms and conditions under which shares in the commingled equity funds may be redeemed vary among the funds; the notice required ranges from one day to 30 days prior to the valuation date (month end). One of the commingled equity funds requires the payment of an impact fee to be applied to redemptions and subscriptions of $5 million or greater.
(4) | The insurance company general account contracts are annuity insurance contracts used to pay the pensions of employees who retired prior to 1989. The balance of the account disclosed in the above table is the contract value, which is the result of deposits, withdrawals, and interest credits. |
(5) | The assets in the above table exceed the market value of plan assets shown in the funded status table by $2,760,000 (qualified retirement plan $2,685,000, PBOP $75,000) and $928,000 (qualified retirement plan $918,000, PBOP $10,000) for 2012 and 2011, respectively, which includes a payable for securities purchased, partially offset by receivables for interest, dividends, and securities sold. |
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Commingled Equity Funds |
||||
(Thousands of dollars): | ||||
Balance, December 31, 2010 |
$ | 97,469 | ||
Actual return on plan assets: |
||||
Relating to assets still held at the reporting date |
(8,442 | ) | ||
Relating to assets sold during the period |
246 | |||
Purchases |
12,000 | |||
Sales |
(1,000 | ) | ||
Settlements |
| |||
Transfers in and/or out of Level 3 |
| |||
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Balance, December 31, 2011 |
100,273 | |||
Actual return on plan assets: |
||||
Relating to assets still held at the reporting date |
21,552 | |||
Relating to assets sold during the period |
342 | |||
Purchases |
6,800 | |||
Sales |
(1,500 | ) | ||
Settlements |
| |||
Transfers in and/or out of Level 3 |
| |||
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Balance, December 31, 2012 |
$ | 127,467 | ||
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Note 11 Stock-Based Compensation
At December 31, 2012, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. Total stock-based compensation expense recognized in the consolidated statements of income is shown in the table below (in thousands):
2012 | 2011 | 2010 | ||||||||||
Stock-based compensation expense, net of related tax benefits |
$ | 7,396 | $ | 7,262 | $ | 5,874 | ||||||
Stock-based compensation related tax benefits |
4,533 | 4,451 | 3,600 |
69 |
Under the option plan, the Company previously granted options to purchase shares of common stock to key employees and outside directors. The last option grants were in 2006 and no future grants are anticipated. Each option has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years.
The following tables summarize Company stock option plan activity and related information (thousands of options):
2012 | 2011 | 2010 | ||||||||||||||||||||||
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 |
177 | $ | 27.28 | 369 | $ | 28.04 | 651 | $ | 27.49 | |||||||||||||||
Exercised during the year |
(52 | ) | 25.25 | (192 | ) | 28.75 | (273 | ) | 26.67 | |||||||||||||||
Forfeited or expired during the year |
| | | | (9 | ) | 29.51 | |||||||||||||||||
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Outstanding and exercisable at year end |
125 | $ | 28.13 | 177 | $ | 27.28 | 369 | $ | 28.04 | |||||||||||||||
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The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding and exercisable options, and options that were exercised, are presented in the table below (in thousands):
2012 | 2011 | 2010 | ||||||||||
Outstanding and exercisable |
$ | 1,788 | $ | 2,697 | $ | 3,186 | ||||||
Exercised |
928 | 1,949 | 1,689 |
December 31, 2012 | December 31, 2011 | December 31, 2010 | ||||||||||
Market value of Southwest Gas stock |
$ | 42.41 | $ | 42.49 | $ | 36.67 |
The weighted-average remaining contractual life for outstanding options was 2.7 years for 2012. All outstanding options are fully vested and exercisable. The following table summarizes information about stock options outstanding at December 31, 2012 (thousands of options):
Options Outstanding and Exercisable | ||||||
Range of Exercise Price |
Number outstanding | Weighted-average remaining contractual life |
Weighted-average exercise price | |||
$20.49 to $23.40 |
30 | 1.2 Years | $22.54 | |||
$25.00 to $26.10 |
34 | 2.5 Years | $25.74 | |||
$29.08 to $33.07 |
61 | 3.5 Years | $32.21 |
The Company received $1.4 million in cash from the exercise of options during 2012 and a corresponding tax benefit of $363,000 which was recorded in additional paid-in capital.
Under the performance share stock plan, the Company may issue performance shares to encourage key employees to remain in its employment and to achieve short-term and long-term performance goals. Plan
70 |
participants are eligible to receive a cash bonus (i.e., short-term incentive) and performance shares (i.e., long-term incentive). The performance shares vest three years after grant (and are subject to a final adjustment as determined by the Board of Directors) and are then issued as common stock.
The Company awards restricted stock/units under the restricted stock/unit plan to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/units vest 40% at the end of year one and 30% at the end of years two and three and are then issued as common stock. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. Vesting for grants to directors followed the vesting schedule for employees; however, beginning with grants in 2012, the directors restricted stock/units vest immediately upon grant. The issuance of common stock for directors occurs when their service on the Board ends.
The following table summarizes the activity of the performance share stock and restricted stock/unit plans as of December 31, 2012 (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 |
361 | $ | 30.66 | 176 | $ | 32.65 | ||||||||||
Granted |
105 | 41.34 | 94 | 41.34 | ||||||||||||
Dividends |
10 | 5 | ||||||||||||||
Forfeited or expired |
| | | | ||||||||||||
Vested and issued* |
(128 | ) | 25.68 | (68 | ) | 31.61 | ||||||||||
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Nonvested/unissued at December 31, 2012 |
348 | $ | 36.03 | 207 | $ | 37.18 | ||||||||||
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*Includes shares for retiree payouts and those converted for taxes.
The average grant date fair value of performance shares and restricted stock/units granted in 2011 and 2010 was $37.87 and $29.04, respectively.
As of December 31, 2012, total compensation cost related to nonvested performance shares and restricted stock/units not yet recognized is $3.8 million.
Note 12 Income Taxes
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is subject to examinations by the Internal Revenue Service for years after 2008, and is subject to examination by the various state taxing authorities for years after 2007.
The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):
2012 | 2011 | 2010 | ||||||||||
Tax-related interest income |
$ | 24 | $ | 100 | $ | 500 |
71 |
Tax-related interest receivable and payable included in the consolidated balance sheets are shown in the table below (in thousands):
2012 | 2011 | |||||||
Tax-related interest receivable (payable) |
$ | | $ | 6 |
The Company had no uncertain tax liabilities at December 31, 2012, or at any time during 2012. The Company expects no change in unrecognized tax benefits in the next twelve months.
A reconciliation of the beginning and ending amount of unrecognized tax benefits in 2011 is as follows (thousands of dollars):
2011 | ||||
Unrecognized tax benefits at beginning of year |
$ | 1,445 | ||
Gross increases tax positions in prior period |
| |||
Gross decreases tax positions in prior period |
| |||
Gross increases current period tax positions |
| |||
Gross decreases current period tax positions |
| |||
Settlements |
| |||
Lapse of statute of limitations |
(1,445 | ) | ||
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Unrecognized tax benefits at end of year |
$ | | ||
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Income tax expense (benefit) consists of the following (thousands of dollars):
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
Current: |
||||||||||||
Federal |
$ | 2,296 | $ | (265 | ) | $ | 4,204 | |||||
State |
5,744 | 2,122 | 4,442 | |||||||||
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8,040 | 1,857 | 8,646 | ||||||||||
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Deferred: |
||||||||||||
Federal |
65,551 | 58,584 | 44,778 | |||||||||
State |
1,685 | 2,862 | 1,501 | |||||||||
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67,236 | 61,446 | 46,279 | ||||||||||
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Total income tax expense |
$ | 75,276 | $ | 63,303 | $ | 54,925 | ||||||
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Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
Deferred federal and state: |
||||||||||||
Property-related items |
$ | 64,249 | $ | 51,710 | $ | 43,420 | ||||||
Purchased gas cost adjustments |
1,755 | (92 | ) | (315 | ) | |||||||
Employee benefits |
564 | 11,766 | 8,753 | |||||||||
All other deferred |
1,529 | (1,070 | ) | (4,711 | ) | |||||||
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Total deferred federal and state |
68,097 | 62,314 | 47,147 | |||||||||
Deferred ITC, net |
(861 | ) | (868 | ) | (868 | ) | ||||||
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Total deferred income tax expense |
$ | 67,236 | $ | 61,446 | $ | 46,279 | ||||||
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The consolidated effective income tax rate for the period ended December 31, 2012 and the two prior periods differ from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
Federal statutory income tax rate |
35.0 | % | 35.0 | % | 35.0 | % | ||||||
Net state taxes |
2.6 | 2.7 | 2.8 | |||||||||
Property-related items |
0.2 | 0.2 | 0.2 | |||||||||
Effect of income tax settlements |
| (0.9 | ) | (0.3 | ) | |||||||
Tax credits |
(0.4 | ) | (0.6 | ) | (0.5 | ) | ||||||
Company owned life insurance |
(1.3 | ) | (0.1 | ) | (2.3 | ) | ||||||
All other differences |
0.1 | (0.1 | ) | (0.2 | ) | |||||||
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Consolidated effective income tax rate |
36.2 | % | 36.2 | % | 34.7 | % | ||||||
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73 |
Deferred tax assets and liabilities consist of the following (thousands of dollars):
December 31, | 2012 | 2011 | ||||||
Deferred tax assets: |
||||||||
Deferred income taxes for future amortization of ITC |
$ | 3,211 | $ | 3,743 | ||||
Employee benefits |
27,097 | 24,605 | ||||||
Alternative minimum tax credit |
18,467 | 17,411 | ||||||
Net operating losses and credits |
36,206 | 59,096 | ||||||
Interest rate swap |
11,164 | 13,352 | ||||||
Other |
17,866 | 15,099 | ||||||
Valuation allowance |
(141 | ) | (142 | ) | ||||
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|
|||||
113,870 | 133,164 | |||||||
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|
|||||
Deferred tax liabilities: |
||||||||
Property-related items, including accelerated depreciation |
652,380 | 611,022 | ||||||
Regulatory balancing accounts |
2,498 | 743 | ||||||
Property-related items previously flowed through |
1,729 | 2,797 | ||||||
Unamortized ITC |
5,131 | 5,992 | ||||||
Debt-related costs |
4,602 | 4,379 | ||||||
Other |
16,626 | 11,914 | ||||||
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|
|
|||||
682,966 | 636,847 | |||||||
|
|
|
|
|||||
Net deferred tax liabilities |
$ | 569,096 | $ | 503,683 | ||||
|
|
|
|
|||||
Current |
$ | (47,088 | ) | $ | (53,435 | ) | ||
Noncurrent |
616,184 | 557,118 | ||||||
|
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|
|
|||||
Net deferred tax liabilities |
$ | 569,096 | $ | 503,683 | ||||
|
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At December 31, 2012, the Company has a federal net operating loss carryforward of $103 million and a federal general business credit carryforward of $306,000, both of which expire in 2031. The Company also has a net capital loss carryforward of $320,000, which expires in 2016. The Company also has charitable contribution carryforwards of $892,000 and $743,000, which expire in 2016 and 2017, respectively. On January 2, 2013, the American Taxpayer Relief Act of 2012 (Taxpayer Relief Act) was signed into law. The Taxpayer Relief Act extended the availability of the 50% bonus depreciation deduction through 2013. As a result, the Company will not utilize any of the current alternative minimum tax credit in 2013.
Note 13 Derivatives and Fair Value Measurements
Derivatives. In managing its natural gas supply portfolios, Southwest has historically entered into fixed- and variable-price contracts, which qualify as derivatives. Additionally, Southwest utilizes fixed-for-floating swap contracts (Swaps) to supplement its fixed-price contracts. The fixed-price contracts, firm commitments to purchase a fixed amount of gas in the future at a fixed price, qualify for the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business, and are exempt from fair value reporting. The variable-price contracts have no significant market value. The Swaps are recorded at fair value.
The fixed-price contracts and Swaps are utilized by Southwest under its volatility mitigation programs to effectively fix the price on a portion (currently ranging from 25% to 35%, depending on the jurisdiction) of its natural gas supply portfolios. The maturities of the Swaps highly correlate to forecasted purchases of natural gas, during time frames ranging from January 2013 through March 2015. Under such contracts,
74 |
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, 2012 | December 31, 2011 | |||||||
Contract notional amounts |
14,579 | 10,827 | ||||||
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|
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Southwest does not utilize derivative financial instruments for speculative purposes, nor does it have trading operations.
The following table sets forth the gains and (losses) recognized on the Companys Swaps (derivatives) for the years ended December 31, 2012, 2011, and 2010 and their location in the income statements (thousands of dollars):
Gains (losses) recognized in income for derivatives not designated as hedging instruments:
(Thousands of dollars)
Instrument | Location of Gain or (Loss) Recognized in Income on Derivative |
2012 | 2011 | 2010 | ||||||||||
Swaps |
Net cost of gas sold | $ | (4,854 | ) | $ | (18,201 | ) | $ | (27,690 | ) | ||||
Swaps |
Net cost of gas sold | 4,854 | * | 18,201 | * | 27,690 | * | |||||||
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Total |
$ | | $ | | $ | | ||||||||
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* Represents the impact of regulatory deferral accounting treatment under U.S. GAAP for rate-regulated entities.
In January 2010, Southwest entered into two FSIRS to hedge the risk of interest rate variability during the period leading up to the planned issuance of fixed-rate debt to replace $200 million of debt that matured in February 2011 and $200 million that matured in May 2012. The counterparties to each agreement were four major banking institutions. The first FSIRS was a designated cash flow hedge and terminated in December 2010 concurrent with the related issuance of $125 million 4.45% 10-year Senior Notes. The second FSIRS was also a designated cash flow hedge and had a notional amount of $100 million. It terminated in March 2012 concurrent with the related issuance of $250 million 3.875% 10-year Senior Notes. At settlement of the second FSIRS, Southwest paid an aggregate $21.8 million to the counterparties. No gain or loss was recognized in income (ineffective portion) for either FSIRS during any period, including the periods presented in the following table.
Gains (losses) recognized in other comprehensive income for derivatives designated as cash flow hedging instruments:
Year Ended December 31, 2012 |
Year Ended December 31, 2011 |
|||||||
(Thousands of dollars) | ||||||||
Amount of gain/(loss) realized/unrealized on FSIRS recognized in other comprehensive income on derivative |
$ | 2,959 | $ | (17,958 | ) | |||
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|
75 |
The following table sets forth the fair values of the Companys Swaps and FSIRS and their location in the balance sheets (thousands of dollars):
Fair values of derivatives not designated as hedging instruments:
December 31, 2012 Instrument |
Balance Sheet Location | Asset Derivatives |
Liability Derivatives |
Net Total |
||||||||||
Swaps |
Deferred charges and other assets | $ | 132 | $ | (126 | ) | $ | 6 | ||||||
Swaps |
Other current liabilities | 391 | (2,467 | ) | (2,076 | ) | ||||||||
Swaps |
Other deferred credits | 233 | (552 | ) | (319 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 756 | $ | (3,145 | ) | $ | (2,389 | ) | ||||||
|
|
|
|
|
|
|||||||||
December 31, 2011 Instrument |
Balance Sheet Location | Asset Derivatives |
Liability Derivatives |
Net Total |
||||||||||
Swaps |
Other current liabilities | $ | | $ | (11,122 | ) | $ | (11,122 | ) | |||||
Swaps |
Other deferred credits | | (621 | ) | (621 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | (11,743 | ) | $ | (11,743 | ) | ||||||
|
|
|
|
|
|
Fair values of derivatives designated as hedging instruments:
December 31, 2011 Instrument |
Balance Sheet Location | Asset Derivatives |
Liability Derivatives |
Net Total |
||||||||||
FSIRS |
Other current liabilities | $ | | $ | (24,713 | ) | $ | (24,713 | ) | |||||
|
|
|
|
|
|
As noted above, the FSIRS that remained at December 31, 2011 terminated in March 2012.
The estimated fair values of the natural gas derivatives were determined using future natural gas index prices (as more fully described below). The Company has master netting arrangements with each counterparty that provide for the net settlement of all contracts through a single payment. As applicable, the Company has elected to reflect the net amounts in its balance sheets.
Pursuant to regulatory deferral accounting treatment for rate-regulated entities, Southwest records the unrealized gains and losses in fair value of the Swaps as a regulatory asset and/or liability. When the Swaps mature, Southwest reverses any prior positions held and records the settled position as an increase or decrease of purchased gas under the related purchased gas adjustment (PGA) mechanism in determining its deferred PGA balances. Neither changes in fair value, nor settled amounts, of Swaps have a direct effect on earnings or other comprehensive income. The following table shows the amounts Southwest paid to and received from counterparties for settlements of matured Swaps.
Year ended December 31, 2012 |
Year ended December 31, 2011 |
Year ended December 31, 2010 |
||||||||||
(Thousands of dollars) | ||||||||||||
Paid to counterparties |
$ | 14,843 | $ | 17,283 | $ | 16,574 | ||||||
|
|
|
|
|
|
|||||||
Received from counterparties |
$ | 634 | $ | | $ | 831 | ||||||
|
|
|
|
|
|
76 |
The following table details the regulatory assets/(liabilities) offsetting the derivatives at fair value in the balance sheets (thousands of dollars).
December 31, 2012 Instrument |
Balance Sheet Location | Net Total | ||||
Swaps |
Other deferred credits | $ | (6 | ) | ||
Swaps |
Prepaids and other current assets | 2,076 | ||||
Swaps |
Deferred charges and other assets | 319 |
December 31, 2011 Instrument |
Balance Sheet Location | Net Total | ||||
Swaps |
Prepaids and other current assets | $ | 11,122 | |||
Swaps |
Deferred charges and other assets | 621 |
Fair Value Measurements. The estimated fair values of Southwests Swaps were determined at December 31, 2012 and 2011 using New York Mercantile Exchange (NYMEX) futures settlement prices for delivery of natural gas at Henry Hub adjusted by the price of NYMEX ClearPort basis Swaps, which reflect the difference between the price of natural gas at a given delivery basin and the Henry Hub pricing points. These Level 2 inputs (inputs, other than quoted prices, for similar assets or liabilities) are observable in the marketplace throughout the full term of the Swaps, but have been credit-risk adjusted with no significant impact to the overall fair value measure.
The estimated fair value of Southwests FSIRS at December 31, 2011 was determined using a discounted cash flow model that utilized forward interest rate curves. The inputs to the model were the terms of the FSIRS. These Level 2 inputs were observable in the marketplace throughout the full term of the FSIRS, but were credit-risk adjusted with no significant impact to the overall fair value measure. See Note 5 Other Comprehensive Income and Accumulated Other Comprehensive Income (AOCI) for more information on the FSIRS.
See Note 10 Pension and Other Postretirement Benefits for definitions of the levels of the fair value hierarchy. The following table sets forth, by level within the three-level fair value hierarchy that ranks the inputs used to measure fair value by their reliability, the Companys financial assets and liabilities that were accounted for at fair value:
Level 2 - Significant other observable inputs
December 31, 2012 | December 31, 2011 | |||||||
(Thousands of dollars) | ||||||||
Assets at fair value: |
||||||||
Deferred charges and other assets - Swaps |
$ | 6 | $ | | ||||
Liabilities at fair value: |
||||||||
Other current liabilities - Swaps |
(2,076 | ) | (11,122 | ) | ||||
Other deferred credits - Swaps |
(319 | ) | (621 | ) | ||||
Other current liabilities - FSIRS |
| (24,713 | ) | |||||
|
|
|
|
|||||
Net Assets (Liabilities) |
$ | (2,389 | ) | $ | (36,456 | ) | ||
|
|
|
|
No financial assets or liabilities accounted for at fair value fell within Level 1 or Level 3 of the fair value hierarchy.
77 |
Note 14 - Segment Information
Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, distributing, and transporting natural gas. Revenues are generated from the distribution and transportation of natural gas. The construction services segment is primarily engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
The accounting policies of the reported segments are the same as those described within Note 1 Summary of Significant Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices at contract inception. Accounts receivable for these services, which are not eliminated during consolidation, are presented in the table below (in thousands).
December 31, 2012 | December 31, 2011 | |||||||
Accounts receivable for NPL services |
$ | 8,179 | $ | 6,205 | ||||
|
|
|
|
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, 2012 is as follows (thousands of dollars):
2012 | Gas Operations |
Construction Services |
Total | |||||||||
Revenues from unaffiliated customers |
$ | 1,321,728 | $ | 522,676 | $ | 1,844,404 | ||||||
Intersegment sales |
| 83,374 | 83,374 | |||||||||
|
|
|
|
|
|
|||||||
Total |
$ | 1,321,728 | $ | 606,050 | $ | 1,927,778 | ||||||
|
|
|
|
|
|
|||||||
Interest revenue |
$ | 915 | $ | 9 | $ | 924 | ||||||
|
|
|
|
|
|
|||||||
Interest expense |
$ | 66,957 | $ | 1,063 | $ | 68,020 | ||||||
|
|
|
|
|
|
|||||||
Depreciation and amortization |
$ | 186,035 | $ | 37,387 | $ | 223,422 | ||||||
|
|
|
|
|
|
|||||||
Income tax expense |
$ | 64,973 | $ | 10,303 | $ | 75,276 | ||||||
|
|
|
|
|
|
|||||||
Segment net income |
$ | 116,619 | $ | 16,712 | $ | 133,331 | ||||||
|
|
|
|
|
|
|||||||
Segment assets |
$ | 4,204,948 | $ | 283,109 | $ | 4,488,057 | ||||||
|
|
|
|
|
|
|||||||
Capital expenditures |
$ | 308,951 | $ | 86,761 | $ | 395,712 | ||||||
|
|
|
|
|
|
2011 | Gas Operations |
Construction Services |
Total | |||||||||
Revenues from unaffiliated customers |
$ | 1,403,366 | $ | 391,701 | $ | 1,795,067 | ||||||
Intersegment sales |
| 92,121 | 92,121 | |||||||||
|
|
|
|
|
|
|||||||
Total |
$ | 1,403,366 | $ | 483,822 | $ | 1,887,188 | ||||||
|
|
|
|
|
|
|||||||
Interest revenue |
$ | 465 | $ | 20 | $ | 485 | ||||||
|
|
|
|
|
|
|||||||
Interest expense |
$ | 68,777 | $ | 825 | $ | 69,602 | ||||||
|
|
|
|
|
|
|||||||
Depreciation and amortization |
$ | 175,253 | $ | 25,216 | $ | 200,469 | ||||||
|
|
|
|
|
|
|||||||
Income tax expense |
$ | 49,576 | $ | 13,727 | $ | 63,303 | ||||||
|
|
|
|
|
|
|||||||
Segment net income |
$ | 91,420 | $ | 20,867 | $ | 112,287 | ||||||
|
|
|
|
|
|
|||||||
Segment assets |
$ | 4,048,613 | $ | 227,394 | $ | 4,276,007 | ||||||
|
|
|
|
|
|
|||||||
Capital expenditures |
$ | 305,542 | $ | 75,449 | $ | 380,991 | ||||||
|
|
|
|
|
|
78 |
2010 | Gas Operations |
Construction Services |
Total | |||||||||
Revenues from unaffiliated customers |
$ | 1,511,907 | $ | 257,213 | $ | 1,769,120 | ||||||
Intersegment sales |
| 61,251 | 61,251 | |||||||||
|
|
|
|
|
|
|||||||
Total |
$ | 1,511,907 | $ | 318,464 | $ | 1,830,371 | ||||||
|
|
|
|
|
|
|||||||
Interest revenue |
$ | 158 | $ | 36 | $ | 194 | ||||||
|
|
|
|
|
|
|||||||
Interest expense |
$ | 77,025 | $ | 564 | $ | 77,589 | ||||||
|
|
|
|
|
|
|||||||
Depreciation and amortization |
$ | 170,456 | $ | 20,007 | $ | 190,463 | ||||||
|
|
|
|
|
|
|||||||
Income tax expense |
$ | 47,073 | $ | 7,852 | $ | 54,925 | ||||||
|
|
|
|
|
|
|||||||
Segment net income |
$ | 91,382 | $ | 12,495 | $ | 103,877 | ||||||
|
|
|
|
|
|
|||||||
Segment assets |
$ | 3,845,111 | $ | 139,082 | $ | 3,984,193 | ||||||
|
|
|
|
|
|
|||||||
Capital expenditures |
$ | 188,379 | $ | 27,060 | $ | 215,439 | ||||||
|
|
|
|
|
|
Note 15 Quarterly Financial Data (Unaudited)
Quarter Ended | ||||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||||||
2012 |
||||||||||||||||
Operating revenues |
$ | 657,645 | $ | 409,768 | $ | 371,799 | $ | 488,566 | ||||||||
Operating income |
134,623 | 15,380 | 6,310 | 115,211 | ||||||||||||
Net income (loss) |
78,919 | (3,676 | ) | (4,305 | ) | 62,393 | ||||||||||
Basic earnings (loss) per common share* |
1.71 | (0.08 | ) | (0.09 | ) | 1.35 | ||||||||||
Diluted earnings (loss) per common share* |
1.70 | (0.08 | ) | (0.09 | ) | 1.34 | ||||||||||
2011 |
||||||||||||||||
Operating revenues |
$ | 628,440 | $ | 388,505 | $ | 352,592 | $ | 517,651 | ||||||||
Operating income |
126,335 | 20,568 | 1,253 | 101,924 | ||||||||||||
Net income (loss) |
68,549 | 4,055 | (15,641 | ) | 55,324 | |||||||||||
Basic earnings (loss) per common share* |
1.50 | 0.09 | (0.34 | ) | 1.20 | |||||||||||
Diluted earnings (loss) per common share* |
1.48 | 0.09 | (0.34 | ) | 1.19 | |||||||||||
2010 |
||||||||||||||||
Operating revenues |
$ | 668,751 | $ | 385,825 | $ | 307,683 | $ | 468,112 | ||||||||
Operating income |
121,732 | 24,031 | 184 | 86,170 | ||||||||||||
Net income (loss) |
64,648 | (933 | ) | (4,823 | ) | 44,985 | ||||||||||
Basic earnings (loss) per common share* |
1.43 | (0.02 | ) | (0.11 | ) | 0.99 | ||||||||||
Diluted earnings (loss) per common share* |
1.42 | (0.02 | ) | (0.11 | ) | 0.98 |
* | The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted-average number of common shares outstanding. |
The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for interim periods do not reliably reflect overall trends and changes in the operations of the Company. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Managements Discussion and Analysis for additional discussion of operating results.
79 |
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Companys evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2012. The effectiveness of the Companys internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.
February 27, 2013
80 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Southwest Gas Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of cash flows and of equity present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Companys 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 Managements Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Companys 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 companys 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 companys 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 companys 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 27, 2013
EXHIBIT 21.01
SOUTHWEST GAS CORPORATION
LIST OF SUBSIDIARIES OF THE REGISTRANT
AT DECEMBER 31, 2012
SUBSIDIARY NAME |
STATE OF INCORPORATION OR ORGANIZATION TYPE | |
Paiute Pipeline Company |
Nevada | |
NPL Construction Co. |
Nevada | |
Southwest Gas Transmission Company |
Limited partnership between Southwest Gas Corporation and Utility Financial Corp. | |
Southwest Gas Capital II, III, IV |
Delaware | |
Utility Financial Corp. |
Nevada | |
The Southwest Companies |
Nevada |
Exhibit 23.01
Consent of Independent Registered Public Accounting Firm
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-180045) and Form S-8 (Nos. 333-185354, 333-168731, 333-147952, 333-155581, and 333-106762) of Southwest Gas Corporation of our report dated February 27, 2013 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K.
/s/ PricewaterhouseCoopers LLP
Las Vegas, Nevada
February 27, 2013
Exhibit 31.01
Certification
I, Jeffrey W. Shaw, 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 registrants 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 registrants 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 registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants 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 registrants 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 registrants internal control over financial reporting. |
Date: February 27, 2013
/S/ JEFFREY W. SHAW |
Jeffrey W. Shaw |
President and Chief Executive Officer |
Southwest Gas Corporation |
Certification
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 registrants 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 registrants 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 registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants 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 registrants 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 registrants internal control over financial reporting. |
Date: February 27, 2013
/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, 2012 as filed with the Securities and Exchange Commission (the Report), I, Jeffrey W. Shaw, 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 27, 2013
/s/ Jeffrey W. Shaw |
Jeffrey W. Shaw 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, 2012 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 27, 2013
/s/ Roy R. Centrella |
Roy R. Centrella Senior Vice President/Chief Financial Officer |
Summary of Significant Accounting Policies - Schedule of Accumulated Removal Costs (Detail) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
---|---|---|
Accumulated removal costs | $ 256,000 | $ 233,000 |
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, 2012
|
|
Schedule Of Related Tax Effects Allocated To Each Component Of Other Comprehensive Income Loss [Line Items] | |
Other comprehensive income loss, effective income tax Rate | 38.00% |
Receivables and Related Allowances - Schedule of Accounts Receivable (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended |
---|---|
Dec. 31, 2012
|
|
Receivables And Related Allowances [Line Items] | |
Gas utility customer accounts receivable balance | $ 94,695 |
Pension and Other Postretirement Benefits - Schedule of Assumptions Used (Detail)
|
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.25% | 5.00% |
Weighted-average rate of compensation increase | 2.75% | 3.00% |
Asset return assumption | 8.00% | 8.00% |
Other Comprehensive Income and Accumulated Other Comprehensive Income ("AOCI") - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
---|---|
Amount of FSIRS existing AOCI losses expected to reclassified income in next 12 months | $ 2.1 |
Pension and Other Postretirement Benefits - Schedule of Effect of Significant Unobservable Inputs (Detail) (Commingled equity funds [Member], Level 3-Significant unobservable inputs [Member], USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Commingled equity funds [Member] | Level 3-Significant unobservable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning balance | $ 100,273 | $ 97,469 |
Actual return on plan assets, Relating to assets still held at the reporting date | 21,552 | (8,442) |
Actual return on plan assets, Relating to assets sold during the period | 342 | 246 |
Purchases | 6,800 | 12,000 |
Sales | (1,500) | (1,000) |
Settlements | ||
Transfers in and/or out of Level 3 | ||
Ending balance | $ 127,467 | $ 100,273 |
Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) (USD $)
In Thousands, except Per Share data, unless otherwise specified |
3 Months Ended | 12 Months Ended | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2012
|
Sep. 30, 2012
|
Jun. 30, 2012
|
Mar. 31, 2012
|
Dec. 31, 2011
|
Sep. 30, 2011
|
Jun. 30, 2011
|
Mar. 31, 2011
|
Dec. 31, 2010
|
Sep. 30, 2010
|
Jun. 30, 2010
|
Mar. 31, 2010
|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Schedule Of Quarterly Financial Information [Line Items] | |||||||||||||||
Operating revenues | $ 488,566 | $ 371,799 | $ 409,768 | $ 657,645 | $ 517,651 | $ 352,592 | $ 388,505 | $ 628,440 | $ 468,112 | $ 307,683 | $ 385,825 | $ 668,751 | $ 1,927,778 | $ 1,887,188 | $ 1,830,371 |
Operating income | 115,211 | 6,310 | 15,380 | 134,623 | 101,924 | 1,253 | 20,568 | 126,335 | 86,170 | 184 | 24,031 | 121,732 | 271,524 | 250,080 | 232,117 |
Net income (loss) | $ 62,393 | $ (4,305) | $ (3,676) | $ 78,919 | $ 55,324 | $ (15,641) | $ 4,055 | $ 68,549 | $ 44,985 | $ (4,823) | $ (933) | $ 64,648 | $ 133,331 | $ 112,287 | $ 103,877 |
Basic earnings (loss) per common share | $ 1.35 | $ (0.09) | $ (0.08) | $ 1.71 | $ 1.20 | $ (0.34) | $ 0.09 | $ 1.50 | $ 0.99 | $ (0.11) | $ (0.02) | $ 1.43 | $ 2.89 | $ 2.45 | $ 2.29 |
Diluted earnings (loss) per common share | $ 1.34 | $ (0.09) | $ (0.08) | $ 1.70 | $ 1.19 | $ (0.34) | $ 0.09 | $ 1.48 | $ 0.98 | $ (0.11) | $ (0.02) | $ 1.42 | $ 2.86 | $ 2.43 | $ 2.27 |
Utility Plant - Schedule of Rental Payments for Operating Leases (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Public Utility, Property, Plant and Equipment [Line Items] | |||
Consolidated rental payments/lease expense | $ 31,816 | $ 26,829 | $ 19,365 |
Southwest Gas [Member]
|
|||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Consolidated rental payments/lease expense | 7,762 | 7,812 | 7,585 |
NPL services [Member]
|
|||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Consolidated rental payments/lease expense | $ 24,054 | $ 19,017 | $ 11,780 |
Income Taxes (Tables)
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2012
|
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Summary of Tax-Related Interest Income | Tax-related interest income included in income tax expense in the consolidated statements of income is shown in the table below (in thousands):
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax-Related Interest Receivable and Payable | Tax-related interest receivable and payable included in the consolidated balance sheets are shown in the table below (in thousands):
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits in 2011 is as follows (thousands of dollars):
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Income Tax Expense (Benefit) | Income tax expense (benefit) consists of the following (thousands of dollars):
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Components of Deferred Income Tax Expense (Benefit) | Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars):
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidated Effective Income Tax Rate | The sources of these differences and the effect of each are summarized as follows:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Tax Assets and Liabilities | Deferred tax assets and liabilities consist of the following (thousands of dollars):
|
Stock-Based Compensation - Schedule of Stock-Based Compensation Expense (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense, net of related tax benefits | $ 7,396 | $ 7,262 | $ 5,874 |
Stock-based compensation related tax benefits | $ 4,533 | $ 4,451 | $ 3,600 |
Pension and Other Postretirement Benefits - Schedule of Expected Benefit Payments (Detail) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
---|---|
Pension [Member]
|
|
Defined Benefit Plan Disclosure [Line Items] | |
2013 | $ 33.2 |
2014 | 34.9 |
2015 | 36.7 |
2016 | 38.5 |
2017 | 40.6 |
2018-2022 | 234.4 |
PBOP [Member]
|
|
Defined Benefit Plan Disclosure [Line Items] | |
2013 | 2.6 |
2014 | 2.8 |
2015 | 3.0 |
2016 | 3.2 |
2017 | 3.3 |
2018-2022 | 17.4 |
SERP [Member]
|
|
Defined Benefit Plan Disclosure [Line Items] | |
2013 | 2.5 |
2014 | 2.5 |
2015 | 2.5 |
2016 | 2.5 |
2017 | 2.5 |
2018-2022 | $ 12.0 |
Income Taxes - Summary of Income Tax Expense (Benefit) (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Income Taxes [Line Items] | |||
Federal | $ 2,296 | $ (265) | $ 4,204 |
State | 5,744 | 2,122 | 4,442 |
Income tax expense (benefit), current | 8,040 | 1,857 | 8,646 |
Federal | 65,551 | 58,584 | 44,778 |
State | 1,685 | 2,862 | 1,501 |
Total deferred income tax expense | 67,236 | 61,446 | 46,279 |
Total income tax expense | $ 75,276 | $ 63,303 | $ 54,925 |
Pension and Other Postretirement Benefits - Schedule of Changes in Fair Value of Plan Assets (Detail) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
---|---|---|
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets, including investment contracts | $ 647,760 | $ 552,701 |
Derivative [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 643,134 | 547,749 |
Insurance company general account contracts (Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,626 | 4,952 |
Level 1-Quoted prices in active markets for identical financial assets [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 377,294 | 317,209 |
Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 21 | |
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 | 3,616 | 4,465 |
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 | 6,945 | 7,652 |
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 | 50,739 | 42,055 |
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 | 40,649 | 40,276 |
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 | 29,735 | 24,537 |
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 | 30,512 | 26,868 |
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 | 31,459 | 29,941 |
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 | 26,083 | 17,950 |
Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 25,093 | 16,755 |
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 | 20,913 | 23,161 |
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 | 6,771 | 5,956 |
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 | 85,551 | 71,666 |
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 | 19,228 | 5,902 |
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 | 4 | |
Level 2-Significant other observable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 138,373 | 130,267 |
Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 654 | |
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 | 44,299 | 43,658 |
Level 2-Significant other observable inputs [Member] | Asset-backed and mortgage-backed [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 17,141 | 17,488 |
Level 2-Significant other observable inputs [Member] | Banking [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 18,510 | 16,688 |
Level 2-Significant other observable inputs [Member] | Utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,231 | 5,219 |
Level 2-Significant other observable inputs [Member] | Other [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 29,801 | 26,558 |
Level 2-Significant other observable inputs [Member] | Pooled funds and mutual funds [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 22,425 | 19,691 |
Level 2-Significant other observable inputs [Member] | State and local obligations [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 1,312 | 965 |
Level 3-Significant unobservable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 127,467 | 100,273 |
Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 127,467 | 100,273 |
Qualified retirement plan [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets, including investment contracts | 612,436 | 522,747 |
Qualified retirement plan [Member] | Derivative [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 607,810 | 517,795 |
Qualified retirement plan [Member] | Insurance company general account contracts (Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,626 | 4,952 |
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 | 350,915 | 295,762 |
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 20 | |
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 | 3,510 | 4,332 |
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 | 6,741 | 7,425 |
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 | 49,247 | 40,806 |
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 | 39,454 | 39,080 |
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 | 28,861 | 23,808 |
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 | 29,615 | 26,070 |
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 | 30,534 | 29,052 |
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 | 25,316 | 17,417 |
Qualified retirement plan [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 24,355 | 16,257 |
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 | 20,298 | 22,473 |
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 | 6,572 | 5,779 |
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 | 67,749 | 57,512 |
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 | 18,663 | 5,727 |
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 | 4 | |
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 133,176 | 124,738 |
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 635 | |
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 | 42,997 | 42,361 |
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 | 16,637 | 16,969 |
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Banking [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 17,966 | 16,192 |
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,107 | 5,064 |
Qualified retirement plan [Member] | Level 2-Significant other observable inputs [Member] | Other [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 28,925 | 25,769 |
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 | 20,636 | 17,447 |
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 | 1,273 | 936 |
Qualified retirement plan [Member] | Level 3-Significant unobservable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 123,719 | 97,295 |
Qualified retirement plan [Member] | Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 123,719 | 97,295 |
PBOP [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets, including investment contracts | 35,324 | 29,954 |
PBOP [Member] | Derivative [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 35,324 | 29,954 |
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 | 26,379 | 21,447 |
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Cash equivalents [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 1 | |
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 | 106 | 133 |
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 | 204 | 227 |
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 | 1,492 | 1,249 |
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 | 1,195 | 1,196 |
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 | 874 | 729 |
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 | 897 | 798 |
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 | 925 | 889 |
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 | 767 | 533 |
PBOP [Member] | Level 1-Quoted prices in active markets for identical financial assets [Member] | Telecommunications/utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 738 | 498 |
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 | 615 | 688 |
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 | 199 | 177 |
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 | 17,802 | 14,154 |
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 | 565 | 175 |
PBOP [Member] | Level 2-Significant other observable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 5,197 | 5,529 |
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Commercial Paper [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 19 | |
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 | 1,302 | 1,297 |
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 | 504 | 519 |
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Banking [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 544 | 496 |
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Utilities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 124 | 155 |
PBOP [Member] | Level 2-Significant other observable inputs [Member] | Other [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 876 | 789 |
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 | 1,789 | 2,244 |
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 | 39 | 29 |
PBOP [Member] | Level 3-Significant unobservable inputs [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 3,748 | 2,978 |
PBOP [Member] | Level 3-Significant unobservable inputs [Member] | Commingled equity funds [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | $ 3,748 | $ 2,978 |
Income Taxes - Summary of Tax-Related Interest Income (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Income Taxes [Line Items] | |||
Tax-related interest income | $ 24 | $ 100 | $ 500 |
Stock-Based Compensation - Schedule of Stock Options Activity (Detail) (USD $)
In Thousands, except Per Share data, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding number of options, Beginning balance | 177 | 369 | 651 |
Number of options, Exercised during the year | (52) | (192) | (273) |
Number of options, Forfeited or expired during the year | (9) | ||
Outstanding number of options, Ending balance | 125 | 177 | 369 |
Weighted-average exercise price, Beginning balance | $ 27.28 | $ 28.04 | $ 27.49 |
Weighted-average exercise price, Exercised during the year | $ 25.25 | $ 28.75 | $ 26.67 |
Weighted-average exercise price, Forfeited or expired during the year | $ 29.51 | ||
Weighted-average exercise price, Ending balance | $ 28.13 | $ 27.28 | $ 28.04 |
Income Taxes - Tax-Related Interest Receivable and Payable (Detail) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
---|---|---|
Income Taxes [Line Items] | ||
Tax-related interest receivable (payable) | $ 6 |
Pension and Other Postretirement Benefits - Schedule of Changes in Fair Value of Plan Assets (Parenthetical) (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Defined Benefit Plan Disclosure [Line Items] | ||
Amounts not included in funded status table | $ 2,760,000 | $ 928,000 |
Qualified retirement plan [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Amounts not included in funded status table | 2,685,000 | 918,000 |
PBOP [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Amounts not included in funded status table | $ 75,000 | $ 10,000 |
Summary of Significant Accounting Policies (Tables)
|
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2012
|
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Schedule of Other Property and Investments | Other property and investments includes (millions of dollars):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Removal Costs | The reclassified amounts are presented in the table below (thousands of dollars):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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.
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | Net income was the same for Basic and Diluted EPS calculations.
|
Receivables and Related Allowances - Schedule of Allowance for Uncollectibles (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Beginning Balance | $ 3,182 | $ 3,194 | $ 3,953 |
Additions charged to expense | 2,471 | 2,678 | 2,646 |
Accounts written off, less recoveries | (3,149) | (2,690) | (3,405) |
Ending Balance | $ 2,504 | $ 3,182 | $ 3,194 |
Summary of Significant Accounting Policies - Schedule of Earnings Per Share, Basic and Diluted (Detail)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Average basic shares | 46,115 | 45,858 | 45,405 |
Stock options | 42 | 52 | 56 |
Performance shares | 254 | 271 | 260 |
Restricted stock units | 144 | 110 | 102 |
Average diluted shares | 46,555 | 46,291 | 45,823 |
Derivatives and Fair Values Measurements - Gains (Losses) Recognized in other Comprehensive Income for Derivatives as Cash Flow Hedging Instruments (Detail) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of gain/(loss)realized/unrealized on FSIRS recognized in other comprehensive income on derivative | $ 2,959 | $ (17,958) |
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)
|
3 Months Ended | 6 Months Ended | 12 Months Ended | |
---|---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2012
|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
NPL ownership in ICE percentage | 65.00% | 65.00% | 65.00% | |
Prepaids and other current assets | $ 107,910,000 | $ 107,910,000 | $ 107,910,000 | $ 96,598,000 |
Customer advances applied as contributions offsetting construction expenditures | 20,000,000 | 20,000,000 | 20,000,000 | |
Recognized pretax losses, after tax earnings per share impacts | $ 0.24 | $ 0.20 | ||
NPL Construction Co [Member]
|
||||
Recognized pretax profit/losses | 18,000,000 | 15,000,000 | 5,000,000 | |
Percentage of contract completion | 95.00% | |||
Recognized cumulative pretax losses on contract to date basis | 10,000,000 | |||
Plant materials and operating supplies [Member]
|
||||
Prepaids and other current assets | $ 25,000,000 | $ 25,000,000 | $ 25,000,000 | $ 21,000,000 |
Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Parenthetical) (Detail) (Swaps [Member], USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
---|---|---|
Deferred charges and other assets [Member]
|
||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets and liabilities offsetting derivatives at fair value | $ 319 | $ 621 |
Prepaids and other current assets [Member]
|
||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets and liabilities offsetting derivatives at fair value | 2,076 | 11,122 |
Other deferred credits [Member]
|
||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets and liabilities offsetting derivatives at fair value | $ (6) |
Long-Term Debt - Schedule of Estimated Fair Values of Long-Term Debt (Parenthetical) (Detail)
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jan. 31, 2012
6.10% 1999 Series A, due 2038 [Member]
|
Dec. 31, 2012
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
|
Dec. 31, 2012
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 7.625%, due 2012 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 7.625%, due 2012 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 7.625%, due 2012 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 7.625%, due 2012 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 4.45%, due 2020 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 4.45%, due 2020 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 4.45%, due 2020 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 4.45%, due 2020 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 6.1%, due 2041[Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 6.1%, due 2041[Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 6.1%, due 2041[Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 6.1%, due 2041[Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 3.875%, due 2022 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 3.875%, due 2022 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Notes, 3.875%, due 2022 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Notes, 3.875%, due 2022 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
8% Series, due 2026 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
8% Series, due 2026 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
8% Series, due 2026 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
8% Series, due 2026 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.59% Series, due 2017 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.59% Series, due 2017 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.59% Series, due 2017 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.59% Series, due 2017 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.78% Series, Due 2022 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.78% Series, Due 2022 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.78% Series, Due 2022 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.78% Series, Due 2022 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.92% Series, Due 2027 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.92% Series, Due 2027 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 7.92% Series, Due 2027 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 7.92% Series, Due 2027 [Member]
Market Value [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 6.76% Series, Due 2027 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 6.76% Series, Due 2027 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Debentures [Member]
Medium-term notes, 6.76% Series, Due 2027 [Member]
Market Value [Member]
|
Dec. 31, 2011
Debentures [Member]
Medium-term notes, 6.76% Series, Due 2027 [Member]
Market Value [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
Tax-exempt Series A, Due 2028 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
Tax-exempt Series A, Due 2028 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
Tax-exempt Series A, Due 2028 [Member]
Market Value [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
Tax-exempt Series A, Due 2028 [Member]
Market Value [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2003 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2003 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2003 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2003 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2008 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2008 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2008 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2008 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2009 Series A, due 2039 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2009 Series A, due 2039 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Variable-rate bonds [Member]
2009 Series A, due 2039 [Member]
Market Value [Member]
|
Dec. 31, 2011
Variable-rate bonds [Member]
2009 Series A, due 2039 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
6.10% 1999 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
6.10% 1999 Series A, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
6.10% 1999 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
6.10% 1999 Series A, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.95% 1999 Series C, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.95% 1999 Series C, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.95% 1999 Series C, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.95% 1999 Series C, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.55% 1999 Series D, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.55% 1999 Series D, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.55% 1999 Series D, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.55% 1999 Series D, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.25% 2003 Series D, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.25% 2003 Series D, due 2038 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.25% 2003 Series D, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.25% 2003 Series D, due 2038 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.25% 2004 Series A, due 2034 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.25% 2004 Series A, due 2034 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.25% 2004 Series A, due 2034 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.25% 2004 Series A, due 2034 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.00% 2004 Series B, due 2033 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.00% 2004 Series B, due 2033 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
5.00% 2004 Series B, due 2033 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
5.00% 2004 Series B, due 2033 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
4.85% 2005 Series A, due 2035 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
4.85% 2005 Series A, due 2035 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
4.85% 2005 Series A, due 2035 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
4.85% 2005 Series A, due 2035 [Member]
Market Value [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
4.75% 2006 Series A, due 2036 [Member]
Carrying Amount [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
4.75% 2006 Series A, due 2036 [Member]
Carrying Amount [Member]
|
Dec. 31, 2012
Fixed-rate bonds [Member]
4.75% 2006 Series A, due 2036 [Member]
Market Value [Member]
|
Dec. 31, 2011
Fixed-rate bonds [Member]
4.75% 2006 Series A, due 2036 [Member]
Market Value [Member]
|
|
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt instrument interest rate | 6.10% | 5.45% | 5.80% | 7.625% | 7.625% | 7.625% | 7.625% | 4.45% | 4.45% | 4.45% | 4.45% | 6.10% | 6.10% | 6.10% | 6.10% | 3.875% | 3.875% | 3.875% | 3.875% | 8.00% | 8.00% | 8.00% | 8.00% | 7.59% | 7.59% | 7.59% | 7.59% | 7.78% | 7.78% | 7.78% | 7.78% | 7.92% | 7.92% | 7.92% | 7.92% | 6.76% | 6.76% | 6.76% | 6.76% | 6.10% | 6.10% | 6.10% | 6.10% | 5.95% | 5.95% | 5.95% | 5.95% | 5.55% | 5.55% | 5.55% | 5.55% | 5.45% | 5.45% | 5.45% | 5.45% | 5.25% | 5.25% | 5.25% | 5.25% | 5.80% | 5.80% | 5.80% | 5.80% | 5.25% | 5.25% | 5.25% | 5.25% | 5.00% | 5.00% | 5.00% | 5.00% | 4.85% | 4.85% | 4.85% | 4.85% | 4.75% | 4.75% | 4.75% | 4.75% | ||||||||||||||||
Debt instrument due date | 2012 | 2012 | 2012 | 2012 | 2020 | 2020 | 2020 | 2020 | 2041 | 2041 | 2041 | 2041 | 2022 | 2022 | 2022 | 2022 | 2026 | 2026 | 2026 | 2026 | 2017 | 2017 | 2017 | 2017 | 2022 | 2022 | 2022 | 2022 | 2027 | 2027 | 2027 | 2027 | 2027 | 2027 | 2027 | 2027 | 2028 | 2028 | 2028 | 2028 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2039 | 2039 | 2039 | 2039 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2038 | 2034 | 2034 | 2034 | 2034 | 2033 | 2033 | 2033 | 2033 | 2035 | 2035 | 2035 | 2035 | 2036 | 2036 | 2036 | 2036 | |||
Debt instrument rate reset | March 2,013 | March 2,013 | March 2,013 | March 2,013 | March 2,013 | March 2,013 | March 2,013 | March 2,013 |
Utility Plant - Schedule of Future Minimum Lease Payments for Operating Leases (Detail) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2012
|
---|---|
2013 | $ 6,757 |
2014 | 4,304 |
2015 | 3,181 |
2016 | 2,510 |
2017 | 1,238 |
Thereafter | 61 |
Total minimum lease payments | $ 18,051 |
Summary of Significant Accounting Policies
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12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2012
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Summary of Significant Accounting Policies | Note 1 – Summary of Significant Accounting Policies Nature of Operations. Southwest Gas Corporation and its subsidiaries (the “Company”) consist of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing, and transporting natural gas for customers in portions of Arizona, Nevada, and California. Public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. NPL Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that primarily provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. In November 2009, NPL entered into a venture to market natural gas engine-driven heating, ventilating, and air conditioning (“HVAC”) technology and products. NPL has a 65% interest in the entity (IntelliChoice Energy, “ICE”) and consolidates ICE as a majority-owned subsidiary. Basis of Presentation. The Company follows generally accepted accounting principles in the United States (“U.S. GAAP”) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with U.S. GAAP as applied to regulated companies and as prescribed by federal agencies and commissions of the various states in which the utility operates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries. All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with accounting treatment for rate-regulated entities. Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction, less contributions in aid of construction. Other Property and Investments. Other property and investments includes (millions 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 plant materials and operating supplies of $25 million in 2012 and $21 million in 2011. Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. For regulatory and financial reporting purposes, investment tax credits (“ITC”) related to gas utility operations are deferred and amortized over the life of related fixed assets. Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less. 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. During 2012, approximately $20 million of customer advances, upon contract expiration, were applied as contributions offsetting construction expenditures as a non-cash investing activity. Accumulated Removal Costs. Approved regulatory practices allow Southwest to include in depreciation expense a component to recover removal costs associated with utility plant retirements. In accordance with the Securities and Exchange Commission’s (“SEC”) position on presentation of these amounts, management has reclassified estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheets. The reclassified amounts are presented in the table below (thousands of dollars):
Gas Operating Revenues. Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs and state and local laws, regulations, and agreements. An estimate of the margin associated with natural gas service provided, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized as accrued utility revenue. Revenues also include the net impacts of margin tracker/decoupling accruals. The Company acts as an agent for state and local taxing authorities in the collection and remission of a variety of taxes, including sales and use taxes and surcharges. These taxes are not included in gas operating revenues. The Company uses the net classification method to report taxes collected from customers to be remitted to governmental authorities. Construction Revenues. The majority of NPL contracts are performed under unit-price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two weeks or less. Revenues are recorded as installations are completed. Long-term fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized 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 the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements. Some unit-price contracts contain caps, that if encroached, trigger revenue and loss recognition similar to a fixed-price contract model. In 2011, NPL recorded $5 million in estimated pretax profit associated with a large fixed-price contract. In connection with significant changes in estimated costs to complete the fixed-price contract, NPL results reflect pretax losses (with after-tax earnings per share impacts) of $15 million ($0.20 per share) for the year ended December 31, 2012, including $18 million ($0.24 per share) in the first half of 2012. The estimated cost changes that resulted in the losses recognized included reductions in projected productivity and higher costs of restoration work. Change orders approved during the fourth quarter of 2012 helped to reduce losses overall on the contract. On a contract-to-date basis the cumulative loss is $10 million. At December 31, 2012, work on this sizeable contract is over 95% complete. Construction Expenses. The construction expenses classification in the income statement includes payroll expenses, job-related equipment costs, direct construction costs, gains and losses on equipment sales, general and administrative expenses, and office-related fixed costs of NPL. Net Cost of Gas Sold. Components of net cost of gas sold include natural gas commodity costs (fixed-price and variable-rate), pipeline capacity/transportation costs, and actual settled costs of natural gas derivative instruments. Also included are the net impacts of PGA deferrals and recoveries. Operations and Maintenance Expense. For financial reporting purposes, operations and maintenance expense includes Southwest’s operating and maintenance costs associated with serving utility customers, uncollectible expense, administrative and general salaries and expense, employee benefits expense, and legal expense (including injuries and damages). Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for removal costs (net of salvage value), and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Other regulatory assets, including acquisition adjustments, are amortized when appropriate, over time periods authorized by regulators. Nonutility and construction services-related property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. Costs and gains related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues and become a component of interest expense. Allowance for Funds Used During Construction (“AFUDC”). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.
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 Southwest to indemnify itself against the loss of talent, expertise, and knowledge, as well as to provide indirect funding for certain nonqualified benefit plans. Current tax regulations provide for tax-free treatment of life insurance (death benefit) proceeds. Therefore, the change in the cash surrender value components of COLI policies, as they progress towards the ultimate death benefits, is also recorded without tax consequences. Pipe replacement costs include amounts associated with certain Arizona non-recoverable pipe replacement work. The replacement program work subject to non-recoverability was completed in 2012. Earnings Per Share. Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of additional weighted-average common stock equivalents (stock options, performance shares, and restricted stock units). Unless otherwise noted, the term “Earnings Per Share” refers to Basic EPS. A reconciliation of the shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.
Recently Issued Accounting Standards Updates. In October 2012, the Financial Accounting Standards Board (“FASB”) issued the update “Technical Corrections and Improvements” which clarifies or corrects unintended application of accounting guidance. Many of these changes are not expected to have a significant effect on current accounting practice but some improvements are more substantive and are not technical corrections. Amendments included in the update without transition guidance were effective upon issuance. Amendments subject to transition guidance were effective for the Company on January 1, 2013 for interim and annual reporting periods. The adoption of the update is not expected to have a material impact on the Company’s disclosures, financial position, or results of operations. In July 2012, the FASB issued the update “Intangibles – Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment,” which provides that an entity has the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that an indefinite-lived intangible asset is impaired. If, in electing the qualitative evaluation step, there is no indication of impairment, quantitative impairment testing would not be required to be performed. The update would provide consistency in evaluation for goodwill and indefinite-lived intangibles other than goodwill. The Company adopted this update, as required, on January 1, 2013. The adoption of the update is not expected to have a material impact on the financial position or results of operations of the Company. In December 2011, the FASB issued the update “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” The update requires an entity to disclose information about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement. This information is intended to enable users of an entity’s financial statements to understand the effect of those arrangements on the entity’s financial position. In January 2013, the FASB issued the update “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“Clarification”) that clarifies the scope of the “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” update. The amendments included in the Clarification apply to entities that have derivatives, repurchase agreements and reverse repurchase agreements, and certain securities borrowing and securities lending transactions that are offset, or subject to a master netting or similar agreement. Entities with other types of financial assets and financial liabilities subject to a master netting or similar agreements would no longer be subject to the disclosure requirements in the initial update. All disclosures are required to be provided retrospectively for all periods presented. The Company adopted both updates, as required, on January 1, 2013 for interim and annual reporting periods. These updates are not expected to have a material impact on the Company’s disclosures. Subsequent Events. Management of the Company monitors events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued or disclosures to be made, and has reflected them where appropriate. |
Long-Term Debt - Additional Information (Detail) (USD $)
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1 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||||||
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Nov. 30, 2012
|
Dec. 31, 2012
|
Dec. 31, 2012
Short-term credit facility [Member]
|
Dec. 31, 2011
Short-term credit facility [Member]
|
Dec. 31, 2012
Revolving credit facility expire in June 2013 [Member]
|
Jun. 30, 2012
Revolving credit facility expire in June 2013 [Member]
|
Dec. 31, 2012
Revolving credit facility expire in June 2015 [Member]
|
Jun. 30, 2012
Revolving credit facility expire in June 2015 [Member]
Minimum [Member]
|
Jun. 30, 2012
Revolving credit facility expire in June 2015 [Member]
Maximum [Member]
|
Dec. 31, 2012
May 2012 [Member]
|
Dec. 31, 2012
March 2017 [Member]
|
Dec. 31, 2012
LIBOR [Member]
Southwest Gas Credit Facility [Member]
|
Dec. 31, 2012
Alternative base rate [Member]
Southwest Gas Credit Facility [Member]
|
Dec. 31, 2012
Three Point Eight Seven Five Percent Senior Unsecured Notes Due In Two Thousand And Twenty Two [Member]
|
Dec. 31, 2012
Seven Point Six Two Five Percentage Senior Notes Due Two Thousand Twelve [Member]
|
Jan. 31, 2012
6.10% 1999 Series A, due 2038 [Member]
|
Dec. 31, 2012
Commercial paper program [Member]
|
Nov. 30, 2012
Commercial paper program [Member]
|
Dec. 31, 2012
IDRBs [Member]
|
Dec. 31, 2012
5.45% 2003 Series C, due 2038 (rate resets in March 2013) [Member]
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Dec. 31, 2012
5.80% 2003 Series E, due 2038 (rate resets in March 2013) [Member]
|
Dec. 31, 2012
NPL credit facility [Member]
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Jun. 30, 2012
NPL credit facility [Member]
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Debt Instrument [Line Items] | |||||||||||||||||||||||
Senior notes | $ 12,400,000 | ||||||||||||||||||||||
Debt instrument interest rate | 3.875% | 7.625% | 6.10% | 5.45% | 5.80% | ||||||||||||||||||
Senior Notes issued | 250,000,000 | ||||||||||||||||||||||
Senior Notes issued maturity date | April 1, 2022 | May 2012 | |||||||||||||||||||||
Senior debt repayment | 200,000,000 | ||||||||||||||||||||||
Discount on issuance of debt | 0.034% | ||||||||||||||||||||||
Credit facility maximum borrowing capacity | 300,000,000 | 30,000,000 | 75,000,000 | 85,000,000 | 300,000,000 | 300,000,000 | 50,000,000 | ||||||||||||||||
Credit facility expiration date | May 01, 2012 | Jun. 01, 2013 | Jun. 01, 2015 | May 01, 2012 | Mar. 01, 2017 | ||||||||||||||||||
Applicable margin | 1.125% | 0.125% | |||||||||||||||||||||
Line of credit designated as long term debt | 150,000,000 | ||||||||||||||||||||||
Line of credit designated for working capital purposes | 150,000,000 | ||||||||||||||||||||||
Credit facility outstanding | 91,000,000 | 0 | 0 | 20,000,000 | 41,600,000 | ||||||||||||||||||
Current borrowing capacity | 0 | ||||||||||||||||||||||
Maximum current borrowing usage | 130,000,000 | ||||||||||||||||||||||
Credit facility interest rate | 1.43% | ||||||||||||||||||||||
Effective interest rate | 0.84% | 0.97% | |||||||||||||||||||||
IDRBs to be redeemed | 45,000,000 | ||||||||||||||||||||||
Interest rate of LIBOR | 1.00% | ||||||||||||||||||||||
Interest rate of base | 0.75% | ||||||||||||||||||||||
Issuance of additional debt | 1,700,000,000 | ||||||||||||||||||||||
Minimum net worth | $ 700,000,000 |