Exhibit 13.01
2007
CONSOLIDATEDSELECTEDFINANCIALSTATISTICS
Year Ended December 31, | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||||||||||
Operating revenues | $ | 2,152,088 | $ | 2,024,758 | $ | 1,714,283 | $ | 1,477,060 | $ | 1,231,004 | ||||||||||
Operating expenses | 1,931,501 | 1,815,576 | 1,563,635 | 1,307,293 | 1,095,899 | |||||||||||||||
Operating income | $ | 220,587 | $ | 209,182 | $ | 150,648 | $ | 169,767 | $ | 135,105 | ||||||||||
Net income | $ | 83,246 | $ | 83,860 | $ | 43,823 | $ | 56,775 | $ | 38,502 | ||||||||||
Total assets at year end | $ | 3,670,188 | $ | 3,484,965 | $ | 3,228,426 | $ | 2,938,116 | $ | 2,608,106 | ||||||||||
Capitalization at year end | ||||||||||||||||||||
Common equity | $ | 983,673 | $ | 901,425 | $ | 751,135 | $ | 705,676 | $ | 630,467 | ||||||||||
Subordinated debentures | 100,000 | 100,000 | 100,000 | 100,000 | 100,000 | |||||||||||||||
Long-term debt | 1,266,067 | 1,286,354 | 1,224,898 | 1,162,936 | 1,121,164 | |||||||||||||||
$ | 2,349,740 | $ | 2,287,779 | $ | 2,076,033 | $ | 1,968,612 | $ | 1,851,631 | |||||||||||
Common stock data | ||||||||||||||||||||
Common equity percentage of capitalization | 41.9 | % | 39.4 | % | 36.2 | % | 35.8 | % | 34.0 | % | ||||||||||
Return on average common equity | 8.8 | % | 10.3 | % | 5.9 | % | 8.5 | % | 6.3 | % | ||||||||||
Basic earnings per share | $ | 1.97 | $ | 2.07 | $ | 1.15 | $ | 1.61 | $ | 1.14 | ||||||||||
Diluted earnings per share | $ | 1.95 | $ | 2.05 | $ | 1.14 | $ | 1.60 | $ | 1.13 | ||||||||||
Dividends declared per share | $ | 0.86 | $ | 0.82 | $ | 0.82 | $ | 0.82 | $ | 0.82 | ||||||||||
Payout ratio | 44 | % | 40 | % | 71 | % | 51 | % | 72 | % | ||||||||||
Book value per share at year end | $ | 22.98 | $ | 21.58 | $ | 19.10 | $ | 19.18 | $ | 18.42 | ||||||||||
Market value per share at year end | $ | 29.77 | $ | 38.37 | $ | 26.40 | $ | 25.40 | $ | 22.45 | ||||||||||
Market value per share to book value per share | 130 | % | 178 | % | 138 | % | 132 | % | 122 | % | ||||||||||
Common shares outstanding at year end (000) | 42,806 | 41,770 | 39,328 | 36,794 | 34,232 | |||||||||||||||
Number of common shareholders at year end | 22,664 | 23,610 | 23,571 | 23,743 | 22,616 | |||||||||||||||
Ratio of earnings to fixed charges | 2.25 | 2.25 | 1.70 | 1.93 | 1.60 |
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2007
NATURALGASOPERATIONS
Year Ended December 31, | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||
Sales | $ | 1,754,913 | $ | 1,671,093 | $ | 1,401,329 | $ | 1,211,019 | $ | 984,966 | ||||||||||
Transportation | 59,853 | 56,301 | 53,928 | 51,033 | 49,387 | |||||||||||||||
Operating revenue | 1,814,766 | 1,727,394 | 1,455,257 | 1,262,052 | 1,034,353 | |||||||||||||||
Net cost of gas sold | 1,086,194 | 1,033,988 | 828,131 | 645,766 | 482,503 | |||||||||||||||
Operating margin | 728,572 | 693,406 | 627,126 | 616,286 | 551,850 | |||||||||||||||
Expenses | ||||||||||||||||||||
Operations and maintenance | 331,208 | 320,803 | 314,437 | 290,800 | 266,862 | |||||||||||||||
Depreciation and amortization | 157,090 | 146,654 | 137,981 | 130,515 | 120,791 | |||||||||||||||
Taxes other than income taxes | 37,553 | 34,994 | 39,040 | 37,669 | 35,910 | |||||||||||||||
Operating income | $ | 202,721 | $ | 190,955 | $ | 135,668 | $ | 157,302 | $ | 128,287 | ||||||||||
Contribution to consolidated net income | $ | 72,494 | $ | 71,473 | $ | 33,670 | $ | 48,354 | $ | 34,211 | ||||||||||
Total assets at year end | $ | 3,518,304 | $ | 3,352,074 | $ | 3,103,804 | $ | 2,843,199 | $ | 2,528,332 | ||||||||||
Net gas plant at year end | $ | 2,845,300 | $ | 2,668,104 | $ | 2,489,147 | $ | 2,335,992 | $ | 2,175,736 | ||||||||||
Construction expenditures and property additions | $ | 312,412 | $ | 305,914 | $ | 258,547 | $ | 274,748 | $ | 228,288 | ||||||||||
Cash flow, net | ||||||||||||||||||||
From operating activities | $ | 317,270 | $ | 248,884 | $ | 214,036 | $ | 124,135 | $ | 187,122 | ||||||||||
From investing activities | (306,396 | ) | (277,980 | ) | (254,120 | ) | (272,458 | ) | (249,300 | ) | ||||||||||
From financing activities | (2,023 | ) | 20,350 | 57,763 | 143,086 | 60,815 | ||||||||||||||
Net change in cash | $ | 8,851 | $ | (8,746 | ) | $ | 17,679 | $ | (5,237 | ) | $ | (1,363 | ) | |||||||
Total throughput (thousands of therms) | ||||||||||||||||||||
Residential | 698,063 | 677,605 | 650,465 | 667,174 | 593,048 | |||||||||||||||
Small commercial | 310,666 | 309,856 | 300,072 | 303,844 | 279,154 | |||||||||||||||
Large commercial | 127,561 | 128,255 | 111,839 | 104,899 | 100,422 | |||||||||||||||
Industrial/Other | 103,525 | 149,243 | 156,542 | 163,856 | 157,305 | |||||||||||||||
Transportation | 1,128,422 | 1,175,238 | 1,273,964 | 1,258,265 | 1,336,901 | |||||||||||||||
Total throughput | 2,368,237 | 2,440,197 | 2,492,882 | 2,498,038 | 2,466,830 | |||||||||||||||
Weighted average cost of gas purchased ($/therm) | $ | 0.81 | $ | 0.79 | $ | 0.71 | $ | 0.57 | $ | 0.46 | ||||||||||
Customers at year end | 1,813,000 | 1,784,000 | 1,713,000 | 1,613,000 | 1,531,000 | |||||||||||||||
Employees at year end | 2,538 | 2,525 | 2,590 | 2,548 | 2,550 | |||||||||||||||
Customer to employee ratio | 714 | 706 | 661 | 633 | 600 | |||||||||||||||
Degree days—actual | 1,850 | 1,826 | 1,735 | 1,953 | 1,772 | |||||||||||||||
Degree days—ten-year average | 1,936 | 1,961 | 1,956 | 1,913 | 1,931 |
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2007
MANAGEMENT’SDISCUSSIONANDANALYSISOFFINANCIALCONDITION
ANDRESULTSOFOPERATIONS
About Southwest Gas Corporation
Southwest Gas Corporation and subsidiaries (the “Company”) consists of two business segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services.
Southwest is engaged in the business of purchasing, distributing, and transporting natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.
As of December 31, 2007, Southwest had 1,813,000 residential, commercial, industrial, and other natural gas customers, of which 980,000 customers were located in Arizona, 655,000 in Nevada, and 178,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2007, 55 percent of operating margin was earned in Arizona, 35 percent in Nevada, and 10 percent in California. During this same period, Southwest earned 86 percent of operating margin from residential and small commercial customers, 5 percent from other sales customers, and 9 percent from transportation customers. These general patterns are expected to continue.
Southwest recognizes operating revenues from the distribution and transportation of natural gas (and related services) to customers. Operating margin is the measure of gas operating revenues less the net cost of gas sold. Management uses operating margin as a main benchmark in comparing operating results from period to period. The three principal factors affecting operating margin are general rate relief, weather, and customer growth. Of these three, weather is the primary reason for volatility in margin. Variances in temperatures from normal levels, especially in Arizona where rates remain leveraged, have a significant impact on the margin and associated net income of the Company.
Northern Pipeline Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems. NPL operates in approximately 19 major markets nationwide. Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including the housing market, interest rates, employment levels, job growth, the equipment resale market, and local and federal tax rates.
Executive Summary
The items discussed in this Executive Summary are intended to provide an overview of the results of the Company’s operations and are covered in greater detail in later sections of management’s discussion and analysis.The natural gas operations segment accounted for an average of 84 percent of consolidated net income over the past three years. As such, management’s discussion and analysis is primarily focused on that segment.
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Summary Operating Results
Year ended December 31, | 2007 | 2006 | 2005 | ||||||
(Thousands of dollars, except per share amounts) | |||||||||
Contribution to net income | |||||||||
Natural gas operations | $ | 72,494 | $ | 71,473 | $ | 33,670 | |||
Construction services | 10,752 | 12,387 | 10,153 | ||||||
Consolidated | $ | 83,246 | $ | 83,860 | $ | 43,823 | |||
Basic earnings per share | |||||||||
Natural gas operations | $ | 1.71 | $ | 1.76 | $ | 0.88 | |||
Construction services | 0.26 | 0.31 | 0.27 | ||||||
Consolidated | $ | 1.97 | $ | 2.07 | $ | 1.15 | |||
Natural Gas Operations | |||||||||
Operating margin | $ | 728,572 | $ | 693,406 | $ | 627,126 | |||
2007 Overview
Consolidated operating results for 2007 were the Company’s second best earnings performance in 15 years as a moderate improvement in the gas segment contribution was offset by a lower contribution from construction services. EPS declined $0.10 per share primarily due to an increase in average shares outstanding. Prior-year results included a nonrecurring benefit of $0.07 per share related to a property tax settlement.
Gas operations highlights included the following:
• | Operating margin increased $35 million from 2006 to 2007 |
• | Rate relief accounted for $18 million of the operating margin increase |
• | Growth-related margin was $14 million as Southwest’s growth level moderated in the face of a downturn in the housing market |
• | Weather was not a significant factor between years ($3 million increase), however both 2007 and 2006 experienced warmer-than-normal weather |
• | Strong cash flows were experienced as a result of earnings, PGA recoveries, and customer advances taken |
• | Southwest’s project to expand its use of meter reading technology continued to progress and is ahead of schedule |
• | Arizona and California general rate cases were filed and are progressing. Rate design and margin stability efforts will again be a focus in the Arizona rate case |
Construction services highlights included the following (seeResults of Construction Services for details):
• | Record-setting revenues in 2007 ($40 million higher than 2006) |
• | Contribution to consolidated net income declined compared to 2006, but 2007 was still its second best year ever |
Moderating Customer Growth
During 2007, Southwest completed 58,700 first-time meter sets. These meter sets led to 29,000 additional active meters from year-end 2006 through year-end 2007 (15,000 in Arizona, 12,000 in Nevada and 2,000 in California). The difference between first-time meter sets and incremental active meters is normally very small, reflecting the lag between the time a new house is constructed and ready for occupancy and the time it takes for a new customer to move in and begin taking service. The sizeable difference experienced in 2007
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indicates an unprecedented inventory of unoccupied homes. The risks/costs associated with having non-performing assets are mitigated by Southwest’s practice of taking construction advances from builders. These advances are not returned until new homes are occupied. Once housing supply and demand come back into balance, Southwest expects to experience a correction in which customer additions exceed first-time meter sets. Although management cannot predict the timing of the turn around, it is likely to occur over an extended (multi-year) time horizon. Until then, it is anticipated that net customer growth will be in the range of 1.5 percent to 3 percent.
Meter Reading Project
In 2006, Southwest initiated a project to expand its use of electronic meter reading technology. The efficiencies to be gained from this project more than offset the investment in infrastructure. This technology eliminates the need to gain physical access to meters in order to obtain monthly meter readings, thereby reducing the time associated with each meter read while improving their accuracy. By the end of 2007, approximately 1.5 million (over 80 percent) of Southwest customers’ meters were being read electronically. The electronic meter reading conversion project (at a total project cost of $65 million) is expected to be completed in 2008, ahead of its originally expected completion date in 2009. The project is not expected to have an adverse impact on existing employees, although some experienced employees have been redeployed to expand service and construction capabilities.
Results of Natural Gas Operations
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
(Thousands of dollars) | |||||||||
Gas operating revenues | $ | 1,814,766 | $ | 1,727,394 | $ | 1,455,257 | |||
Net cost of gas sold | 1,086,194 | 1,033,988 | 828,131 | ||||||
Operating margin | 728,572 | 693,406 | 627,126 | ||||||
Operations and maintenance expense | 331,208 | 320,803 | 314,437 | ||||||
Depreciation and amortization | 157,090 | 146,654 | 137,981 | ||||||
Taxes other than income taxes | 37,553 | 34,994 | 39,040 | ||||||
Operating income | 202,721 | 190,955 | 135,668 | ||||||
Other income (expense) | 4,850 | 10,049 | 5,087 | ||||||
Net interest deductions | 86,436 | 85,567 | 81,595 | ||||||
Net interest deductions on subordinated debentures | 7,727 | 7,724 | 7,723 | ||||||
Income before income taxes | 113,408 | 107,713 | 51,437 | ||||||
Income tax expense | 40,914 | 36,240 | 17,767 | ||||||
Contribution to consolidated net income | $ | 72,494 | $ | 71,473 | $ | 33,670 | |||
2007 vs. 2006
Contribution to consolidated net income from natural gas operations increased $1 million in 2007 compared to 2006. The improvement in contribution resulted from higher operating margin, partially offset by increased operating expenses and a reduction in other income.
Operating margin increased $35 million between 2006 and 2007. The rate relief component of the increase was $18 million ($15 million in Arizona and $3 million in California). Customer growth contributed $14 million toward the operating margin increase as the Company added a net 29,000 customers during 2007, an increase of about two percent. Differences in heating demand, caused primarily by weather variations, accounted for the remaining $3 million increase in operating margin as warmer-than-normal temperatures were experienced during both years (during 2007 the estimated negative weather-related impact was about $12 million, while the negative impact during 2006 was approximately $15 million). Of note were significantly warmer-than-normal temperatures throughout Southwest service territories in November 2007, with Arizona experiencing its warmest November on record (during the past 113 years).
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Operations and maintenance expense increased $10.4 million, or three percent, between years reflecting general cost increases and incremental operating costs associated with serving additional customers. Higher uncollectible expenses also contributed to the increase.
Depreciation expense increased $10.4 million, or seven percent, as a result of additional plant in service. Average gas plant in service for 2007 increased $284 million, or eight percent, compared to 2006. This was attributable to the upgrade of existing operating facilities and the expansion of the system to accommodate customer growth.
General taxes increased $2.6 million primarily as a result of a favorable nonrecurring property tax settlement recognized in April 2006. In addition, on average, property tax rates declined between years, largely offsetting the higher property tax base resulting from plant additions.
Other income decreased $5.2 million as compared to 2006 primarily as a result of a reduction in interest income due to the collection of previously deferred purchased gas costs and reduced returns on long-term investments. The prior year also included $1 million of interest income on the favorable nonrecurring property tax settlement referred to above.
Net financing costs increased $872,000, or one percent, between years primarily due to interest expense associated with deferred PGA balance payables and higher rates on variable-rate debt, partially offset by lower average debt outstanding.
Income tax expense in 2006 included a nonrecurring $1.7 million state income tax benefit.
2006 vs. 2005
Contribution from natural gas operations increased $37.8 million in 2006 compared to 2005. The improvement in contribution was primarily due to higher operating margin resulting from the Arizona general rate increase, a nonrecurring property tax settlement, and improved other income, partially offset by increased operating expenses and financing costs.
Operating margin increased $66 million in 2006 as compared to 2005. During 2006, the Company added 71,000 customers, an increase of four percent. New customers coupled with additional amounts from existing transportation and non-weather sensitive sales customers contributed $26 million in incremental operating margin. Rate relief in Arizona and California added $37 million. Differences in heating demand caused primarily by weather variations between years resulted in a $3 million operating margin increase as warmer-than-normal temperatures were experienced during both years.
Operations and maintenance expense increased $6.4 million, or two percent, between years reflecting general cost increases and incremental operating costs associated with serving additional customers. Factors contributing to the increase included insurance premiums, uncollectible expenses, employee-related costs, and incremental stock-based compensation costs. Operations and maintenance expense for 2005 included a $10 million nonrecurring provision for an injuries and damages case.
Depreciation expense increased $8.7 million, or six percent, as a result of construction activities. Average gas plant in service for 2006 increased $238 million, or seven percent, compared to 2005. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.
General taxes decreased $4 million, or 10 percent, primarily as a result of a nonrecurring property tax settlement and Arizona legislation signed in June 2006 that reduced property tax rates, retroactive to January 2006.
Other income (expense) increased $5 million compared to 2005. The current period includes a $2 million net increase in interest income primarily associated with the unrecovered balance of deferred purchased gas costs and $1 million of interest income on the property tax settlement discussed above.
Net financing costs increased $4 million primarily due to higher rates on variable-rate debt and an increase in average debt outstanding to help finance growth.
Income tax expense in 2006 included a nonrecurring $1.7 million state income tax benefit.
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Rates and Regulatory Proceedings
General Rate Relief and Rate Design
Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest. Management continues to work with its regulatory commissions in designing rate structures that strive to provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors. Such a rate structure is in place in California and progress has been made in Nevada. Southwest continues to pursue rate design changes in Arizona.
Arizona General Rate Case.Southwest filed a general rate application with the ACC in the third quarter of 2007 requesting an increase in authorized operating revenues of $50.2 million. The request is due to increases in Southwest’s operating costs (including inflationary increases to labor and benefits), investments in infrastructure to serve new customers, and the increased costs of capital to fund those investments. The Company is requesting a return on rate base of 9.45 percent and a return on equity of 11.25 percent.
In addition, declining average residential usage has hindered the Company’s ability to earn the returns previously authorized by the ACC. A rate structure that would encourage energy efficiency and also shield the Company and its customers from weather-related volatility has also been proposed. Included in the new rate design proposal are a revenue decoupling mechanism that would separate the recovery of fixed costs from volumetric usage and a weather normalization mechanism that would protect customers from higher bills in extreme cold weather and protect the Company from cost under-recoveries in unseasonably warmer weather. The Company also requested an increase of $3.10 in the monthly residential basic service charge. Southwest requested the new rates become effective October 2008. Hearings are scheduled to be held in June 2008. Management cannot predict the amount or timing of rate relief ultimately granted, or whether the ACC will adopt the new rate design proposals. The last general rate increase received in Arizona was effective in March 2006.
California Attrition Filings.In the fourth quarter of 2006, the CPUC approved a $2.7 million increase in operating margin related to the Company’s 2007 annual California attrition filing. The increase in customer rates was effective January 2007. In connection with this filing, the methodology of recording margin under the margin tracker mechanism was changed to be recognized in equal monthly amounts throughout the year, rather than on a seasonally adjusted basis. This change did not impact the total amount of margin recognized annually; however, it affected the comparability of 2007 versus 2006 quarterly amounts.
In October 2007, Southwest made its 2008 annual attrition filing with the CPUC requesting a $2 million increase in operating margin. The increase in customer rates was approved and became effective January 2008.
California General Rate Cases. Southwest filed general rate applications with the CPUC in December 2007 requesting an increase in authorized operating revenues of $9.1 million in the Company’s southern California, northern California and South Lake Tahoe rate jurisdictions with a proposed effective date of January 2009. The request is due to increases in Southwest’s operating costs, investments in infrastructure to serve new customers, and the increased costs of capital to fund those investments. As part of the filing, Southwest is also requesting that the authorized levels of margin revert to being recognized on a seasonally adjusted basis rather than in equal monthly amounts throughout the year to better reflect the seasonal nature of Southwest’s revenue stream. In addition to the margin balancing mechanism that has been in place since the last general rate case, this filing proposes a Post Test Year (“PTY”) ratemaking mechanism for the period 2010 through 2013. The PTY mechanism is designed to recognize the effects of inflation, certain capital expenditures and customer growth between general rate cases. Hearings were proposed to begin in August 2008.
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PGA Filings
The rate schedules in all of Southwest’s service territories contain provisions that permit adjustments to rates as the cost of purchased gas changes. These deferred energy provisions and purchased gas adjustment clauses are collectively referred to as “PGA” clauses. Differences between gas costs recovered from customers and amounts paid for gas costs by Southwest result in over and under-collections. At December 31, 2007, over-collections in Nevada and California resulted in a liability of $46 million and under-collections in Arizona resulted in an asset of $33.9 million on the Company’s balance sheet. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions and Other income (deductions). In addition, since Southwest is permitted to accrue interest on PGA balances, the cost of incremental PGA-related short-term borrowings will be largely offset and there should be no material negative impact to earnings.
Southwest had the following outstanding PGA balances receivable/(payable) at the end of its two most recent fiscal years (millions of dollars):
2007 | 2006 | ||||||
Arizona | $ | 33.9 | $ | 68.4 | |||
Northern Nevada | (9.2 | ) | 1.1 | ||||
Southern Nevada | (36.7 | ) | 4.1 | ||||
California | (0.1 | ) | 3.4 | ||||
$ | (12.1 | ) | $ | 77.0 | |||
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 surcharge has also been in place since February 2006 to help accelerate the recovery of the under-collected balance. The PGA balance in Arizona has been steadily declining since reaching a peak of $95.8 million in April 2006.
California Gas Cost Filings.In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments are designed to provide a more timely recovery of gas costs and to send appropriate pricing signals to customers.
Nevada Deferred Energy Adjustment Filings. In Nevada, a quarterly gas cost adjustment based on a twelve-month rolling average is utilized. Adjustments are subject to an annual prudence review and audit of the natural gas costs incurred.
Gas Price Volatility Mitigation
Over the past five years the weighted-average delivered cost of natural gas has ranged from a low of $4.60 per dekatherm in 2003 to a high of $8.10 per dekatherm in 2007. Price volatility is expected to continue throughout 2008. Regulators in Southwest’s service territories have encouraged Southwest to take proactive steps to mitigate price volatility on its customers. To accomplish this, Southwest periodically enters into fixed-price term contracts for about half of its annual normal weather supply needs. For the 2007/2008 heating season, fixed-price contracts range in price from approximately $6 to $10 per dekatherm. Natural gas purchases not covered by fixed-price contracts are made under variable-price contracts with firm quantities and on the spot market. Prices for these contracts are not known until the month of purchase. Southwest does not currently utilize stand-alone derivative financial instruments in its volatility mitigation program, however, during 2008, Southwest intends to supplement its use of fixed-price contracts with stand-alone derivative instruments. The combination of fixed-price contracts and derivative instruments should increase flexibility for Southwest and increase supplier diversification. The costs of such derivative financial instruments are expected to be recovered from customers through the PGA mechanism.
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Capital Resources and Liquidity
The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.
2007 Construction Expenditures
Southwest continues to experience customer growth, albeit at a slower pace than in the recent past. This growth has required significant capital outlays for new transmission and distribution plant, to keep up with consumer demand. During the three-year period ended December 31, 2007, total gas plant increased from $3.3 billion to $4 billion, or at an annual rate of seven percent. Customer growth was the primary reason for the plant increase as Southwest added 200,000 net new customers during the three-year period.
During 2007, construction expenditures for the natural gas operations segment were $312 million. Approximately 76 percent of these expenditures represented new construction and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant. Cash flows from operating activities of Southwest (net of dividends) provided $281 million (representing 90 percent) of the required capital resources pertaining to total capital expenditures in 2007. The remainder was provided from refundable construction advances, external financing activities, and existing credit facilities.
2007 Financing Activity
External financing requirements during 2007 were minimized as a result of earnings, strong recoveries of PGA balances, and collections of construction advances and contributions. During 2007, the Company issued approximately 1 million additional shares of common stock through the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”), Employee Investment Plan, Management Incentive Plan, and Stock Incentive Plan, raising approximately $35 million. Additionally in 2007, Southwest partially offset capital outlays by collecting approximately $41 million in net advances and contributions from third-party contractors. At December 31, 2007, the balance of refundable construction advances was approximately $86 million. No incremental debt offerings were required during 2007.
2008 Construction Expenditures and Financing
Southwest estimates construction expenditures during the three-year period ending December 31, 2010 will be approximately $850 million. Of this amount, approximately $302 million are expected to be incurred in 2008. During the three-year period, cash flow from operating activities of Southwest (net of dividends) is estimated to fund over 80 percent of the gas operations’ total construction expenditures. Southwest also has $25 million in long-term debt maturities over the three-year period. During this time frame, the Company expects to raise $70 million to $80 million from its various common stock programs. Any remaining cash requirements are expected to be provided by refundable construction advances, existing credit facilities, and/or other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.
The Company has a universal shelf registration statement providing for the issuance and sale of registered securities, which may consist of secured debt, unsecured debt, preferred stock, or common stock. At December 31, 2007, the Company had $95 million of availability under the universal shelf registration statement.
In 2006, the Company entered into a Sales Agency Financing Agreement with BNY Capital Markets, Inc. relating to the issuance and sale of up to $45 million aggregate amount of the Company’s common stock, from time to time over a three-year period (“Equity Shelf Program”). While no shares were issued through the Equity Shelf Program in 2007, the Company has $16.7 million of remaining capacity under the Equity Shelf Program at December 31, 2007.
In February 2008, the Economic Stimulus Act of 2008 (“Act”) was signed into law. This Act provides a 50 percent bonus tax depreciation deduction for qualified property acquired or constructed and placed in service in 2008. Based on forecasted qualifying construction expenditures, Southwest estimates the bonus depreciation deduction will defer the payment of approximately $30 million of federal income taxes during 2008.
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Liquidity
Liquidity refers to the ability of an enterprise to generate adequate amounts of cash to meet its cash requirements. Several general factors that could significantly affect liquidity in future years include inflation, growth in Southwest’s service territories, changes in the ratemaking policies of regulatory commissions, interest rates, variability of natural gas prices, changes in income tax laws, and the level of Company earnings. Of these factors natural gas prices and related gas cost recovery rates have had the most significant impact on Company liquidity.
The rate schedules in Southwest’s service territories contain PGA clauses which permit adjustments to rates as the cost of purchased gas changes. The PGA mechanism allows Southwest to request to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service.
On an interim basis, Southwest generally defers over- or under-collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2007, the combined balances in PGA accounts totaled an over-collection of $12.1 million versus an under-collection of $77 million at December 31, 2006. SeePGA Filingsfor more information on recent regulatory filings. Southwest has the ability to draw on its credit facility to temporarily finance under-collected PGA balances. This facility expires in April 2012. Southwest has designated $150 million of the $300 million facility as long-term debt and the remaining $150 million for working capital purposes. Southwest currently believes the $150 million designated for working capital purposes is adequate to meet liquidity needs. At December 31, 2007, $150 million was outstanding on the long-term portion and $9 million was outstanding on the short-term portion of the credit facility.
Securities Ratings
The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., the better the rating, the lower the cost to borrow funds).
The Company’s unsecured long-term debt rating from Moody’s Investors Service, Inc. (“Moody’s”) is Baa3. Moody’s applies a Baa rating to obligations which are considered medium grade obligations with adequate security. A numerical modifier of 1 (high end of the category) through 3 (low end of the category) is included with the Baa to indicate the approximate rank of a company within the range.
The Company’s unsecured long-term debt rating from Fitch, Inc. (“Fitch”) is BBB, which Fitch affirmed in February 2008. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB indicates a credit quality that is considered prudent for investment.
The Company’s unsecured long-term debt rating from Standard and Poor’s Ratings Services (“S&P”) is BBB-. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB- indicates 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 which are not within the Company’s control, are considered by the ratings agencies in connection with assigning securities ratings.
43
Inflation
Results of operations are impacted by inflation. Natural gas, labor, consulting, and construction costs are the categories most significantly impacted by inflation. Changes to cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor is a component 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. SeeRates 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 inNote 2—Utility Plant of the Notes to Consolidated Financial Statements. 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.
IDRB Supporting Credit Arrangements
The Company utilizes letters of credit to provide credit support for $100 million of variable-rate IDRBs. A $55.3 million letter of credit supports the City of Big Bear $50 million tax-exempt Series A IDRBs and a $50.1 million letter of credit supports the Clark County, Nevada $50 million IDRBs 2003 Series A.
Insurance policies support approximately $400 million of the fixed and variable-rate IDRBs. Of this amount, approximately $350 million is fixed to maturity and any change in bond rating of the bond insurers will not impose any additional costs on the Company. The remaining $50 million in IDRBs, which is the 2003 Series B, carries a AAA rating supported by insurance from Ambac Assurance Corporation (“Ambac”). The 2003 Series B are repriced weekly in an auction market. Credit rating agencies have been reassessing bond insurers for their ability to absorb potential losses from their subprime-related exposure to residential mortgage-backed securities and collateralized debt obligations. In January 2008, Moody’s Investors Service and Standard & Poor’s, the two largest ratings companies, placed Ambac on watch for a possible downgrade of their AAA rating. The Company cannot predict whether Moody’s and/or S&P will downgrade Ambac, thereby affecting the outstanding AAA rating of the 2003 Series B. If the weekly auction interest rate reset fails, then the rate on the 2003 Series B will be set at the predetermined maximum auction rate as set forth below, based on the prevailing rating of the 2003 Series B in effect on the business day immediately preceding the auction date:
Prevailing Rating | Maximum Auction Rate | |
AAA/Aaa | 175% of one-month LIBOR | |
AA/Aa | 200% of one-month LIBOR | |
A/A | 250% of one-month LIBOR | |
BBB/Baa | 275% of one-month LIBOR | |
Below BBB/Baa | 300% of one-month LIBOR |
In February 2008, the 2003 Series B experienced its initial auction failure. As a result of the failed auction, the Company was required to price the Series B at the predetermined maximum auction rate of 175 percent of the one-month LIBOR rate. The Company has the ability to convert the 2003 Series B to a fixed-rate mode or obtain incremental credit support. The Company will remain watchful as to the developments in the auction rate market and the outcome of the rating agencies reviews, and take appropriate actions to minimize the related interest cost of the facility.
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Contractual Obligations
The Company has various contractual obligations such as long-term purchase contracts, significant non-cancelable operating leases, gas purchase obligations, and long-term debt agreements. The Company has classified these contractual obligations as either operating activities or financing activities, which mirrors their presentation in the Consolidated Statement of Cash Flows. No contractual obligations for investing activities exist at this time. The table below summarizes the Company’s contractual obligations at December 31, 2007 (millions of dollars):
Payments due by period | |||||||||||||||
Contractual Obligations | Total | 2008 | 2009-2010 | 2011-2012 | Thereafter | ||||||||||
Operating activities: | |||||||||||||||
Operating leases (Note 2) | $ | 32 | $ | 7 | $ | 9 | $ | 5 | $ | 11 | |||||
Gas purchase obligations | 629 | 483 | 146 | — | — | ||||||||||
Pipeline capacity | 548 | 103 | 194 | 110 | 141 | ||||||||||
Other commitments | 13 | 6 | 5 | 2 | — | ||||||||||
Financing activities: | |||||||||||||||
Subordinated debentures to Southwest | |||||||||||||||
Gas Capital II (Note 5) | 103 | — | — | — | 103 | ||||||||||
Long-term debt (Note 6) | 1,304 | 38 | 16 | 553 | 697 | ||||||||||
Other | 25 | — | — | 1 | 24 | ||||||||||
Total | $ | 2,654 | $ | 637 | $ | 370 | $ | 671 | $ | 976 | |||||
Obligations for Operating Activities: The table provides a summary of the Company’s obligations associated with operating activities. Operating leases represent multi-year obligations for office rent and certain equipment. Gas purchase obligations include fixed-price and variable-rate gas purchase contracts covering approximately 124 million dekatherms. Fixed-price contracts range in price from approximately $6 to $10 per dekatherm. Variable-price contracts reflect minimum contractual obligations.
Southwest has pipeline capacity contracts for firm transportation service, both on a short- and long-term basis, with several companies for all of its service territories. 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 payments over the life of the debt.
Other: Estimated funding for pension and other postretirement benefits during calendar year 2008 is $29 million. The Company has an insignificant amount of liabilities in connection with the adoption of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”
45
Results of Construction Services
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
(Thousands of dollars) | |||||||||
Construction revenues | $ | 337,322 | $ | 297,364 | $ | 259,026 | |||
Cost of construction | 310,848 | 271,743 | 237,356 | ||||||
Gross profit | 26,474 | 25,621 | 21,670 | ||||||
General and administrative expenses | 8,590 | 7,377 | 6,672 | ||||||
Operating income | 17,884 | 18,244 | 14,998 | ||||||
Other income (expense) | 1,768 | 4,086 | 3,009 | ||||||
Interest expense | 2,036 | 1,686 | 1,009 | ||||||
Income before income taxes | 17,616 | 20,644 | 16,998 | ||||||
Income tax expense | 6,864 | 8,257 | 6,845 | ||||||
Contribution to consolidated net income | $ | 10,752 | $ | 12,387 | $ | 10,153 | |||
2007 vs. 2006
The 2007 contribution to consolidated net income from construction services decreased $1.6 million from 2006. The decrease reflects higher general and administrative expenses, interest expense, and lower gains on sales of equipment. Unfavorable working conditions due to poor weather during the first quarter of 2007 also contributed to the decrease.
Revenues increased $40 million due primarily to several new contracts and an improvement in the amount and profitability of new bid work. Gross profit increased approximately $853,000, or three percent, as a direct result of the increase in revenues, partially offset by a decrease in profit margins on blanket contracts. The construction revenues above include NPL contracts with Southwest totaling $71.4 million in 2007 and $80.6 million in 2006. NPL accounts for the services provided to Southwest at contractual (market) prices.
General and administrative costs increased $1.2 million due primarily to incremental costs associated with revenue growth including labor and other administrative expenses. Other income decreased $2.3 million as a result of a reduction in gains on sales of equipment. Interest expense increased $350,000 due to additional long-term borrowings for purchases of new equipment.
Construction activity is cyclical and can be significantly impacted by changes in general and local economic conditions, including interest rates, employment levels, job growth, and local and federal tax rates. The continued slow-down in construction activities observed in regional and national markets at the end of 2007, if sustained, could negatively impact the amount of work received under existing blanket contracts, the amount of bid work, and the equipment resale market in 2008.
2006 vs. 2005
The 2006 contribution to consolidated net income from construction services increased $2.2 million from 2005. The factors that drove the favorable results included a 15 percent increase in revenues, an improvement in the number of profitable bid jobs, and a favorable equipment resale market.
Revenues increased $38 million due primarily to an increased workload under several existing contracts and an improvement in the amount and profitability of new bid work. Gross profit increased approximately $4 million, or 18 percent, as a direct result of the increase in revenues. The construction revenues above include NPL contracts with Southwest totaling $80.6 million in 2006 and $71.8 million in 2005.
General and administrative costs increased $705,000 due primarily to incremental costs associated with growth including labor and other administrative expenses. Other income increased $1.1 million as a result of an increase in gains on sales of equipment. Interest expense increased $677,000 due to additional long-term borrowing for the purchase of new equipment and higher interest rates.
46
Recently Issued Accounting Pronouncements
Below is a listing of recently issued accounting pronouncements by the Financial Accounting Standards Board (“FASB”). SeeNote 1—Summary of Significant Accounting Policies for more information regarding these accounting pronouncements and their potential impact on the Company’s financial position and results of operations.
Title | Month of Issue | Effective Date | ||||
SFAS No. 157, | “Fair Value Measurements.” | September 2006 | January 2008 | |||
SFAS No. 141 (R), | “Business Combinations.” | December 2007 | January 2009 | |||
SFAS No. 160, | “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” | December 2007 | January 2009 |
Application of Critical Accounting Policies
A critical accounting policy is one which is very important to the portrayal of the financial condition and results of a company, and requires the most difficult, subjective, or complex judgments of management. The need to make estimates about the effect of items that are uncertain is what makes these judgments difficult, subjective, and/or complex. Management makes subjective judgments about the accounting and regulatory treatment of many items and bases its estimates on historical experience and on various other assumptions that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. The following are accounting policies that are critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, seeNote 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 enterprises (including SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”) 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 toNote 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, revenues for natural gas that has been delivered but not yet billed are accrued. This accrued utility revenue is estimated each month based on daily sales volumes, applicable rates, analyses reflecting significant historical trends, weather, and experience. In periods of extreme weather conditions, the interplay of these assumptions could impact the variability of the accrued utility revenue estimates.
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Accounting for Income Taxes
The income tax calculations of the Company require estimates due to known future tax rate changes, book to tax differences, and uncertainty with respect to regulatory treatment of certain property items. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recoverable from or refunded to customers in future rates. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The Company regularly assesses financial statement tax provisions to identify any change in the regulatory treatment or tax-related estimates, assumptions, or enacted tax rates that could have a material impact on cash flows, financial position, and/or results of operations of the Company.
Accounting for Pensions and Other Postretirement Benefits
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. In addition, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The Company’s pension obligations and costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension obligations and costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions (particularly the discount rate) may significantly affect pension obligations and costs for these plans.
Due to an increase in market interest rates for high-quality debt instruments, the Company raised the discount rate to 6.50% at December 31, 2007 from 6.00% at December 31, 2006. The weighted-average rate of compensation increase was raised to 4.00% from 3.75%. The asset return assumption was decreased to 8.00% from 8.50%. These offsetting changes will not result in a significant change in pension expense for 2008. Should interest rates rise in 2008, future pension expense and projected benefit obligations could decrease. Conversely, declining interest rates would put upward pressure on future pension expense and projected benefit obligations.
Management believes that regulation and the effects of regulatory accounting have the most significant impact on the financial statements. When Southwest files rate cases, capital assets, costs, and gas purchasing practices are subject to review, and disallowances can occur. Regulatory disallowances in the past have not been frequent but have on occasion been significant to the operating results of the Company.
Certifications
The SEC requires the Company to file certifications of its Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) regarding reporting accuracy, disclosure controls and procedures, and internal control over financial reporting as exhibits to the Company’s periodic filings. The CEO and CFO certifications for the period ended December 31, 2007 were included as exhibits to the 2007 Annual Report on Form 10-K which was filed with the SEC. The Company is also required to file an annual CEO certification regarding corporate governance listing standards compliance with the New York Stock Exchange (“NYSE”). The most recent annual CEO certification, dated May 3, 2007, was filed with the NYSE in May 2007.
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Forward-Looking Statements
This annual report contains statements which constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. For example, statements regarding customer growth, estimated future construction expenditures, forecasted operating cash flows, sufficiency of working capital, ability to raise funds and receive external financing, the amount of any such financing, and statements regarding future gas prices, gas purchase contracts and derivative financial instruments, the recovery of under-recovered PGA balances, and the timing and results of future rate approvals are forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.
A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, conditions in the housing market, our ability to recover costs through our PGA mechanisms, the effects of regulation/deregulation, the timing and amount of rate relief, changes in rate design, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, renewal of franchises, easements and rights-of-way, changes in operations and maintenance expenses, effects of accounting changes, future liability claims, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition, and our ability to raise capital in external financings. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing, operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, seeItem 1A. Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.
All forward-looking statements in this annual report are made as of the date hereof, based on information available to the Company as of the date hereof, and the Company assumes no obligation to update or revise any of its forward-looking statements even if experience or future changes show that the indicated results or events will not be realized.We caution you not to unduly rely on any forward-looking statement(s).
Common Stock Price and Dividend Information
2007 | 2006 | Dividends Declared | ||||||||||||||||
High | Low | High | Low | 2007 | 2006 | |||||||||||||
First quarter | $ | 39.95 | $ | 35.30 | $ | 29.04 | $ | 26.09 | $ | 0.215 | $ | 0.205 | ||||||
Second quarter | 39.77 | 33.10 | 31.43 | 26.46 | 0.215 | 0.205 | ||||||||||||
Third quarter | 34.22 | 26.45 | 34.19 | 30.70 | 0.215 | 0.205 | ||||||||||||
Fourth quarter | 30.97 | 26.61 | 39.37 | 32.80 | 0.215 | 0.205 | ||||||||||||
$ | 0.860 | $ | 0.820 | |||||||||||||||
The principal market on which the common stock of the Company is traded is the New York Stock Exchange. At February 15, 2008, there were 22,910 holders of record of common stock, and the market price of the common stock was $27.99.
The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend declared was 20.5 cents per share throughout 2006 and 21.5 cents per share throughout 2007. In February 2008, the Board of Directors increased the quarterly dividend payout to 22.5 cents per share, to be effective with the June 2008 payment.
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2007
SOUTHWESTGASCORPORATION
CONSOLIDATEDBALANCESHEETS
December 31, | ||||||||
2007 | 2006 | |||||||
(Thousands of dollars, except par value) | ||||||||
ASSETS | ||||||||
Utility plant: | ||||||||
Gas plant | $ | 4,043,936 | $ | 3,763,310 | ||||
Less: accumulated depreciation | (1,261,867 | ) | (1,175,600 | ) | ||||
Acquisition adjustments, net | 1,812 | 1,992 | ||||||
Construction work in progress | 61,419 | 78,402 | ||||||
Net utility plant (Note 2) | 2,845,300 | 2,668,104 | ||||||
Other property and investments | 143,097 | 136,242 | ||||||
Current assets: | ||||||||
Cash and cash equivalents | 31,991 | 18,786 | ||||||
Accounts receivable, net of allowances (Note 3) | 203,660 | 225,928 | ||||||
Accrued utility revenue | 74,900 | 73,300 | ||||||
Income taxes receivable, net | 14,286 | 571 | ||||||
Deferred income taxes (Note 11) | 6,965 | — | ||||||
Deferred purchased gas costs (Note 4) | 33,946 | 77,007 | ||||||
Prepaids and other current assets (Notes 2 and 4) | 136,711 | 106,032 | ||||||
Total current assets | 502,459 | 501,624 | ||||||
Deferred charges and other assets (Note 4) | 179,332 | 178,995 | ||||||
Total assets | $ | 3,670,188 | $ | 3,484,965 | ||||
CAPITALIZATION AND LIABILITIES | ||||||||
Capitalization: | ||||||||
Common stock, $1 par (authorized—60,000,000 shares; issued and outstanding—42,805,706 and 41,770,291 shares) (Note 10) | $ | 44,436 | $ | 43,400 | ||||
Additional paid-in capital | 732,319 | 698,258 | ||||||
Accumulated other comprehensive income (loss), net (Note 9) | (12,850 | ) | (13,666 | ) | ||||
Retained earnings | 219,768 | 173,433 | ||||||
Total equity | 983,673 | 901,425 | ||||||
Subordinated debentures due to Southwest Gas Capital II (Note 5) | 100,000 | 100,000 | ||||||
Long-term debt, less current maturities (Note 6) | 1,266,067 | 1,286,354 | ||||||
Total capitalization | 2,349,740 | 2,287,779 | ||||||
Commitments and contingencies (Note 8) | ||||||||
Current liabilities: | ||||||||
Current maturities of long-term debt (Note 6) | 38,079 | 27,545 | ||||||
Short-term debt (Note 7) | 9,000 | — | ||||||
Accounts payable | 220,731 | 265,739 | ||||||
Customer deposits | 75,019 | 64,151 | ||||||
Accrued general taxes | 44,637 | 45,895 | ||||||
Accrued interest | 21,290 | 21,362 | ||||||
Deferred income taxes (Note 11) | — | 15,471 | ||||||
Deferred purchased gas costs (Note 4) | 46,088 | — | ||||||
Other current liabilities (Note 4) | 73,088 | 55,901 | ||||||
Total current liabilities | 527,932 | 496,064 | ||||||
Deferred income taxes and other credits: | ||||||||
Deferred income taxes and investment tax credits (Note 11) | 347,497 | 308,493 | ||||||
Taxes payable | 4,387 | 5,951 | ||||||
Accumulated removal costs (Note 4) | 146,000 | 125,000 | ||||||
Other deferred credits (Notes 4 and 9) | 294,632 | 261,678 | ||||||
Total deferred income taxes and other credits | 792,516 | 701,122 | ||||||
Total capitalization and liabilities | $ | 3,670,188 | $ | 3,484,965 | ||||
The accompanying notes are an integral part of these statements.
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2007
SOUTHWESTGASCORPORATION
CONSOLIDATEDSTATEMENTSOFINCOME
Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Operating revenues: | ||||||||||||
Gas operating revenues | $ | 1,814,766 | $ | 1,727,394 | $ | 1,455,257 | ||||||
Construction revenues | 337,322 | 297,364 | 259,026 | |||||||||
Total operating revenues | 2,152,088 | 2,024,758 | 1,714,283 | |||||||||
Operating expenses: | ||||||||||||
Net cost of gas sold | 1,086,194 | 1,033,988 | 828,131 | |||||||||
Operations and maintenance | 331,208 | 320,803 | 314,437 | |||||||||
Depreciation and amortization | 182,514 | 168,964 | 156,253 | |||||||||
Taxes other than income taxes | 37,553 | 34,994 | 39,040 | |||||||||
Construction expenses | 294,032 | 256,827 | 225,774 | |||||||||
Total operating expenses | 1,931,501 | 1,815,576 | 1,563,635 | |||||||||
Operating income | 220,587 | 209,182 | 150,648 | |||||||||
Other income and (expenses): | ||||||||||||
Net interest deductions (Notes 6 and 7) | (88,472 | ) | (87,253 | ) | (82,604 | ) | ||||||
Net interest deductions on subordinated debentures (Note 5) | (7,727 | ) | (7,724 | ) | (7,723 | ) | ||||||
Other income (deductions) | 6,636 | 14,152 | 8,114 | |||||||||
Total other income and (expenses) | (89,563 | ) | (80,825 | ) | (82,213 | ) | ||||||
Income before income taxes | 131,024 | 128,357 | 68,435 | |||||||||
Income tax expense (Note 11) | 47,778 | 44,497 | 24,612 | |||||||||
Net income | $ | 83,246 | $ | 83,860 | $ | 43,823 | ||||||
Basic earnings per share (Note 13) | $ | 1.97 | $ | 2.07 | $ | 1.15 | ||||||
Diluted earnings per share (Note 13) | $ | 1.95 | $ | 2.05 | $ | 1.14 | ||||||
Average number of common shares outstanding | 42,336 | 40,566 | 38,132 | |||||||||
Average shares outstanding (assuming dilution) | 42,714 | 40,975 | 38,467 |
The accompanying notes are an integral part of these statements.
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2007
SOUTHWESTGASCORPORATION
CONSOLIDATEDSTATEMENTSOFCASHFLOWS
Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(Thousands of dollars) | ||||||||||||
CASH FLOW FROM OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 83,246 | $ | 83,860 | $ | 43,823 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 182,514 | 168,964 | 156,253 | |||||||||
Deferred income taxes | 16,068 | 3,909 | (5,514 | ) | ||||||||
Changes in current assets and liabilities: | ||||||||||||
Accounts receivable, net of allowances | 22,268 | (27,847 | ) | (20,216 | ) | |||||||
Accrued utility revenue | (1,600 | ) | (4,900 | ) | 982 | |||||||
Deferred purchased gas costs | 89,149 | 32,408 | (25,865 | ) | ||||||||
Accounts payable | (45,008 | ) | 6,263 | 92,021 | ||||||||
Accrued taxes | (16,537 | ) | 3,198 | 5,716 | ||||||||
Other current assets and liabilities | 24,972 | 24,156 | (23,000 | ) | ||||||||
Other | (7,261 | ) | (8,657 | ) | 13,424 | |||||||
Net cash provided by operating activities | 347,811 | 281,354 | 237,624 | |||||||||
CASH FLOW FROM INVESTING ACTIVITIES: | ||||||||||||
Construction expenditures and property additions | (340,875 | ) | (345,325 | ) | (294,369 | ) | ||||||
Other | 8,940 | 33,199 | 1,985 | |||||||||
Net cash used in investing activities | (331,935 | ) | (312,126 | ) | (292,384 | ) | ||||||
CASH FLOW FROM FINANCING ACTIVITIES: | ||||||||||||
Issuance of common stock, net | 35,097 | 72,452 | 64,136 | |||||||||
Dividends paid | (36,271 | ) | (33,500 | ) | (31,228 | ) | ||||||
Issuance of long-term debt, net | 128,594 | 92,400 | 145,256 | |||||||||
Retirement of long-term debt | (142,091 | ) | (84,397 | ) | (31,442 | ) | ||||||
Change in long-term portion of credit facility | 3,000 | (3,000 | ) | — | ||||||||
Change in short-term debt | 9,000 | (24,000 | ) | (76,000 | ) | |||||||
Net cash provided by (used in) financing activities | (2,671 | ) | 19,955 | 70,722 | ||||||||
Change in cash and cash equivalents | 13,205 | (10,817 | ) | 15,962 | ||||||||
Cash at beginning of period | 18,786 | 29,603 | 13,641 | |||||||||
Cash at end of period | $ | 31,991 | $ | 18,786 | $ | 29,603 | ||||||
Supplemental information: | ||||||||||||
Interest paid, net of amounts capitalized | $ | 93,335 | $ | 92,533 | $ | 86,465 | ||||||
Income taxes paid (received), net | $ | 45,025 | $ | 39,682 | $ | 5,977 | ||||||
The accompanying notes are an integral part of these statements.
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2007
SOUTHWESTGASCORPORATION
CONSOLIDATEDSTATEMENTSOFSTOCKHOLDERS’EQUITYANDCOMPREHENSIVEINCOME
Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Total | Comprehensive Income (Loss) | ||||||||||||||||||||
Shares | Amount | ||||||||||||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||||||||||
DECEMBER 31, 2004 | 36,794 | $ | 38,424 | $ | 566,646 | $ | (10,892 | ) | $ | 111,498 | $ | 705,676 | |||||||||||||
Common stock issuances | 2,534 | 2,534 | 61,602 | 64,136 | |||||||||||||||||||||
Net income | 43,823 | 43,823 | $ | 43,823 | |||||||||||||||||||||
Additional minimum pension liability adjustment, net of $19 million of tax (Note 9) | (30,753 | ) | (30,753 | ) | (30,753 | ) | |||||||||||||||||||
Dividends declared | |||||||||||||||||||||||||
Common: $0.82 per share | (31,747 | ) | (31,747 | ) | |||||||||||||||||||||
2005 Comprehensive Income | $ | 13,070 | |||||||||||||||||||||||
DECEMBER 31, 2005 | 39,328 | 40,958 | 628,248 | (41,645 | ) | 123,574 | 751,135 | ||||||||||||||||||
Common stock issuances | 2,442 | 2,442 | 70,010 | 72,452 | |||||||||||||||||||||
Net income | 83,860 | 83,860 | $ | 83,860 | |||||||||||||||||||||
Additional minimum pension liability adjustment, net of $20.3 million of tax (Note 9) | 33,047 | 33,047 | 33,047 | ||||||||||||||||||||||
Net adjustment to adopt SFAS No. 158, net of $3.1 million of tax (Note 9) | (5,068 | ) | (5,068 | ) | |||||||||||||||||||||
Dividends declared | |||||||||||||||||||||||||
Common: $0.82 per share | (34,001 | ) | (34,001 | ) | |||||||||||||||||||||
2006 Comprehensive Income | $ | 116,907 | |||||||||||||||||||||||
DECEMBER 31, 2006 | 41,770 | 43,400 | 698,258 | (13,666 | ) | 173,433 | 901,425 | ||||||||||||||||||
Common stock issuances | 1,036 | 1,036 | 34,061 | 35,097 | |||||||||||||||||||||
Net income | 83,246 | 83,246 | $ | 83,246 | |||||||||||||||||||||
Net actuarial gain arising during the period, less amortization of unamortized benefit plan cost, net of $500,000 of tax (Note 9) | 816 | 816 | 816 | ||||||||||||||||||||||
Dividends declared | |||||||||||||||||||||||||
Common: $0.86 per share | (36,911 | ) | (36,911 | ) | |||||||||||||||||||||
2007 Comprehensive Income | $ | 84,062 | |||||||||||||||||||||||
DECEMBER 31, 2007 | 42,806 | * | $ | 44,436 | $ | 732,319 | $ | (12,850 | ) | $ | 219,768 | $ | 983,673 |
* | At December 31, 2007, 2.1 million common shares were registered and available for issuance under provisions of the Company’s various stock issuance plans. In addition, approximately 800,000 common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 10). During 2007, no shares were issued in at-the-market offerings through the Equity Shelf Program. |
The accompanying notes are an integral part of these statements.
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2007
NOTESTOCONSOLIDATEDFINANCIALSTATEMENTS
Note 1—Summary of Significant Accounting Policies
Nature of Operations. Southwest Gas Corporation (the “Company”) is composed of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, distributing and transporting natural gas to customers in portions of Arizona, Nevada, and California. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Northern Pipeline Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
Basis of Presentation. The Company follows generally accepted accounting principles (“GAAP”) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with GAAP as applied to regulated companies and as prescribed by federal agencies and the commissions of the various states in which the utility operates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries, except for Southwest Gas Capital II (see Note 5). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.”
Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction, less contributions in aid of construction.
Deferred Purchased Gas Costs. The various regulatory commissions have established procedures to enable Southwest to adjust its billing rates for changes in the cost of natural gas purchased. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred. Generally, these deferred amounts are recovered or refunded within one year.
Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date.
For regulatory and financial reporting purposes, investment tax credits (“ITC”) related to gas utility operations are deferred and amortized over the life of related fixed assets.
Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a purchase-date maturity of three months or less.
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 $146 million and $125 million, as of December 31, 2007 and 2006, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs within the liabilities section of the balance sheet.
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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 amount of natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized as accrued utility revenue.
The Company acts as an agent for state and local taxing authorities in the collection and remission of a variety of taxes, including franchise fees, sales and use taxes, and surcharges. These taxes are not included in gas operating revenues, except for certain franchise fees in California operating jurisdictions which are not significant. The Company uses the net classification method to report taxes collected from customers to be remitted to governmental authorities.
Construction Revenues. The majority of NPL contracts are performed under unit price contracts. Generally, these contracts state prices per unit of installation. Typical installations are accomplished in two weeks or less. Revenues are recorded as installations are completed. Long-term fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements.
Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for salvage value, removal costs, and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Costs related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues. 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.
Allowance for Funds Used During Construction (“AFUDC”). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The Company capitalized $1.3 million in 2007 $2.8 million in 2006, and $2 million in 2005 of AFUDC related to natural gas utility operations. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. The debt portion of AFUDC was $619,000, $1.4 million, and $1.1 million for 2007, 2006 and 2005, respectively. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.
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.
2007 | 2006 | 2005 | ||||
(In thousands) | ||||||
Average basic shares | 42,336 | 40,566 | 38,132 | |||
Effect of dilutive securities: | ||||||
Stock options | 147 | 195 | 146 | |||
Performance shares | 210 | 214 | 189 | |||
Restricted stock units | 21 | — | — | |||
Average diluted shares | 42,714 | 40,975 | 38,467 | |||
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Derivatives.The Company does not utilize derivative financial instruments for speculative purposes, nor does the Company have trading operations. In managing its gas supply portfolios, Southwest uses variable-rate and fixed-price arrangements which qualify as derivative instruments as defined under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS No. 133”). However, variable-price contracts have no significant market value and fixed-price contracts qualify for the normal purchases and normal sales exception under SFAS No. 133. This exception applies to physical sales and purchases of natural gas where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and documentation requirements are met.
In November 2007, temperatures in Arizona reached record levels for the month, exceeding averages for any of the preceding 100 years. As a result of the warm weather and pipeline constraints during the same time period, the Company did not take delivery of natural gas under three fixed-price contracts for several days during the month. This resulted in a financial settlement of these quantities based on the difference between the contract price and the daily spot market price during those days. Once weather conditions returned to normal, the Company resumed receiving natural gas under the fixed-price contracts involved. The Company expects to take physical delivery of gas for the remaining term of the contracts and to continue to apply the normal purchases and sales exception.
Common Stock. In May 2007, shareholders of the Company approved an increase in the number of authorized shares of common stock from 45,000,000 shares to 60,000,000 shares. The increase had no effect on the par value of common stock.
Reclassifications. Certain reclassifications have been made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation.
Recently Issued Accounting Pronouncements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. The provisions of SFAS No. 157 are effective for the Company beginning January 1, 2008. The adoption of the standard is not expected to have a material impact on the financial position or results of operations of the Company.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations.” SFAS No. 141 (revised 2007) provides guidelines for the presentation and measurement of assets and liabilities acquired in a business combination and requires the disclosure of all information necessary to evaluate the nature and financial effect of a business combination. The provisions of SFAS No. 141 (revised 2007) are effective for the Company for acquisitions that occur on or after January 1, 2009. The Company is evaluating what impact, if any, this standard might have on its financial position or results of operations.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” SFAS No. 160 requires all entities to report minority interests in subsidiaries as equity in the consolidated financial statements. The provisions of SFAS No. 160 are effective for the Company beginning January 1, 2009. The Company is evaluating what impact, if any, this standard might have on its financial position or results of operations.
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Note 2—Utility Plant
Net utility plant as of December 31, 2007 and 2006 was as follows (thousands of dollars):
December 31, | 2007 | 2006 | ||||||
Gas plant: | ||||||||
Storage | $ | 17,403 | $ | 17,545 | ||||
Transmission | 256,696 | 243,989 | ||||||
Distribution | 3,419,799 | 3,153,399 | ||||||
General | 219,126 | 219,527 | ||||||
Other | 130,912 | 128,850 | ||||||
4,043,936 | 3,763,310 | |||||||
Less: accumulated depreciation | (1,261,867 | ) | (1,175,600 | ) | ||||
Acquisition adjustments, net | 1,812 | 1,992 | ||||||
Construction work in progress | 61,419 | 78,402 | ||||||
Net utility plant | $ | 2,845,300 | $ | 2,668,104 | ||||
Depreciation and amortization expense on gas plant was $155 million in 2007, $145 million in 2006, and $137 million in 2005.
In October 2007, the Company sold its Southern Nevada Division operations facility for $35 million. Of the proceeds, $28 million is held by JP Morgan Property Exchange, Inc. (and reflected in Prepaids and other current assets on Southwest’s balance sheet) to facilitate like-kind exchange tax treatment for the new land and facilities to be developed. The gain on the sale (approximately $20 million) was deferred and recorded as a regulatory liability to be included in a future rate case. The Company plans to build two separate facilities to better serve the expanding customer base in Las Vegas. During construction of the new facilities, the Company will lease back the operations facility (see details below). The Company’s corporate headquarters complex is not affected by these transactions.
Operating Leases and Rentals. Southwest leases a portion of its corporate headquarters office complex in Las Vegas, the southern Nevada operations facility, and its administrative offices in Phoenix. The leases provide for current terms which expire in 2017, 2009, and 2009, respectively, with optional renewal terms available at the expiration dates. The rental payments for the corporate headquarters office complex are $2 million in each of the years 2008 through 2012 and $10.1 million cumulatively thereafter. The rental payments for the southern Nevada operations facility are $1.5 million in 2008 and $875,000 in 2009 when the lease expires. The rental payments for the Phoenix administrative offices are $1.5 million for 2008 and $1 million in 2009 when the lease expires. In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. Rentals included in operating expenses for all operating leases were $23.9 million in 2007, $19.2 million in 2006, and $19 million in 2005. These amounts include NPL lease expenses of approximately $15.9 million in 2007, $11.5 million in 2006, and $11.5 million in 2005, for various short-term operating leases of equipment and temporary office sites.
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, 2007 (thousands of dollars):
Year Ending December 31, | |||
2008 | $ | 6,965 | |
2009 | 5,543 | ||
2010 | 2,863 | ||
2011 | 2,640 | ||
2012 | 2,641 | ||
Thereafter | 10,972 | ||
Total minimum lease payments | $ | 31,624 | |
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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. At December 31, 2007, the gas utility customer accounts receivable balance was $157 million. Approximately 54 percent of the gas utility customers were in Arizona, 36 percent in Nevada, and 10 percent in California. Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Provisions for uncollectible accounts are recorded monthly, as needed, and are included in the ratemaking process as a cost of service. Activity in the allowance for uncollectibles is summarized as follows (thousands of dollars):
Allowance for Uncollectibles | ||||
Balance, December 31, 2004 | $ | 1,972 | ||
Additions charged to expense | 3,787 | |||
Accounts written off, less recoveries | (3,458 | ) | ||
Balance, December 31, 2005 | 2,301 | |||
Additions charged to expense | 5,805 | |||
Accounts written off, less recoveries | (5,085 | ) | ||
Balance, December 31, 2006 | 3,021 | |||
Additions charged to expense | 7,178 | |||
Accounts written off, less recoveries | (7,252 | ) | ||
Balance, December 31, 2007 | $ | 2,947 | ||
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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 generally accepted accounting principles applicable to rate-regulated enterprises, principally SFAS No. 71, and reflect the effects of the ratemaking process. SFAS No. 71 allows for the deferral as regulatory assets, costs that otherwise would be expensed if it is probable future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write-off the related regulatory asset. Regulatory liabilities are recorded if it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.
The following table represents existing regulatory assets and liabilities (thousands of dollars):
December 31, | 2007 | 2006 | ||||||
Regulatory assets: | ||||||||
Accrued pension and other postretirement benefit costs * (Note 9) | $ | 92,655 | $ | 101,402 | ||||
Deferred purchased gas costs | 33,946 | 77,007 | ||||||
Accrued purchased gas costs ** | 40,100 | 40,500 | ||||||
SFAS No. 109—income taxes, net * | 1,286 | 1,846 | ||||||
Unamortized premium on reacquired debt * | 17,215 | 17,676 | ||||||
Other | 32,734 | 30,099 | ||||||
217,936 | 268,530 | |||||||
Regulatory liabilities: | ||||||||
Deferred purchased gas costs | (46,088 | ) | — | |||||
Accumulated removal costs | (146,000 | ) | (125,000 | ) | ||||
Deferred gain on southern Nevada division operations facility **** | (20,522 | ) | — | |||||
Rate refunds due customers*** | (12,474 | ) | — | |||||
Other **** | (1,401 | ) | (1,111 | ) | ||||
Net regulatory assets (liabilities) | $ | (8,549 | ) | $ | 142,419 | |||
* | Included in Deferred charges and other assets on the Consolidated Balance Sheet. |
** | Included in Prepaids and other current assets on the Consolidated Balance Sheet. |
*** | Included in Other current liabilities on the Consolidated Balance Sheet. |
**** | Included in Other deferred credits on the Consolidated Balance Sheet. |
Other regulatory assets include deferred costs associated with rate cases, regulatory studies, margin and interest-tracking accounts, and state mandated public purpose programs (including low income and conservation programs), as well as amounts associated with accrued absence time and deferred post-retirement benefits other than pensions.
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Note 5—Preferred Trust Securities and Subordinated Debentures
In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the distribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures are redeemable at the option of the Company after August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest. In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Trust Securities. As of December 31, 2007, 4.1 million Preferred Trust Securities were outstanding.
The Company has the right to defer payments of interest on the Subordinated Debentures by extending the interest payment period at any time for up to 20 consecutive quarters (each, an “Extension Period”). If interest payments are so deferred, distributions to Preferred Trust Securities holders will also be deferred. During such Extension Period, distributions will continue to accrue with interest thereon (to the extent permitted by applicable law) at an annual rate of 7.70% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Debentures. If the Company exercises the right to extend an interest payment period, the Company shall not during such Extension Period (i) declare or pay dividends on, or make a distribution with respect to, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, or (ii) make any payment of interest, principal, or premium, if any, on or repay, repurchase, or redeem any debt securities issued by the Company that rank equal with or junior to the Subordinated Debentures; provided, however, that restriction (i) above does not apply to any stock dividends paid by the Company where the dividend stock is the same as that on which the dividend is being paid. The Company has no present intention of exercising its right to extend the interest payment period on the Subordinated Debentures.
Although the Company owns 100 percent of the common voting securities of Trust II, under Interpretation No. 46 “Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51”, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. As a result, the $103.1 million Subordinated Debentures are shown on the balance sheet of the Company, net of the $3.1 million Common Securities, as Subordinated debentures due to Southwest Gas Capital II. Payments and amortizations associated with the Subordinated Debentures are classified on the consolidated statements of income as Net interest deductions on subordinated debentures.
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Note 6—Long-Term Debt
December 31, | 2007 | 2006 | ||||||||||||
Carrying Amount | Market Value | Carrying Amount | Market Value | |||||||||||
(Thousands of dollars) | ||||||||||||||
Debentures: | ||||||||||||||
Notes, 8.375%, due 2011 | $ | 200,000 | $ | 216,872 | $ | 200,000 | $ | 221,200 | ||||||
Notes, 7.625%, due 2012 | 200,000 | 214,172 | 200,000 | 217,600 | ||||||||||
8% Series, due 2026 | 75,000 | 82,274 | 75,000 | 88,748 | ||||||||||
Medium-term notes, 6.89% series, due 2007 | — | — | 17,500 | 17,654 | ||||||||||
Medium-term notes, 6.27% series, due 2008 | 25,000 | 25,152 | 25,000 | 25,263 | ||||||||||
Medium-term notes, 7.59% series, due 2017 | 25,000 | 26,946 | 25,000 | 28,155 | ||||||||||
Medium-term notes, 7.78% series, due 2022 | 25,000 | 27,486 | 25,000 | 28,645 | ||||||||||
Medium-term notes, 7.92% series, due 2027 | 25,000 | 26,975 | 25,000 | 29,398 | ||||||||||
Medium-term notes, 6.76% series, due 2027 | 7,500 | 7,183 | 7,500 | 7,832 | ||||||||||
Unamortized discount | (3,443 | ) | — | (4,021 | ) | — | ||||||||
579,057 | 595,979 | |||||||||||||
Revolving credit facility and commercial paper | 150,000 | 150,000 | 147,000 | 147,000 | ||||||||||
Industrial development revenue bonds: | ||||||||||||||
Variable-rate bonds: | ||||||||||||||
Tax-exempt Series A, due 2028 | 50,000 | 50,000 | 50,000 | 50,000 | ||||||||||
2003 Series A, due 2038 | 50,000 | 50,000 | 50,000 | 50,000 | ||||||||||
2003 Series B, due 2038 | 50,000 | 50,000 | 50,000 | 50,000 | ||||||||||
Fixed-rate bonds: | ||||||||||||||
6.10% 1999 Series A, due 2038 | 12,410 | 12,519 | 12,410 | 13,093 | ||||||||||
5.95% 1999 Series C, due 2038 | 14,320 | 14,353 | 14,320 | 15,136 | ||||||||||
5.55% 1999 Series D, due 2038 | 8,270 | 8,116 | 8,270 | 8,696 | ||||||||||
5.45% 2003 Series C, due 2038 | 30,000 | 28,955 | 30,000 | 30,705 | ||||||||||
5.25% 2003 Series D, due 2038 | 20,000 | 18,691 | 20,000 | 20,836 | ||||||||||
5.80% 2003 Series E, due 2038 | 15,000 | 14,481 | 15,000 | 15,629 | ||||||||||
5.25% 2004 Series A, due 2034 | 65,000 | 60,588 | 65,000 | 67,210 | ||||||||||
5.00% 2004 Series B, due 2033 | 75,000 | 68,616 | 75,000 | 76,688 | ||||||||||
4.85% 2005 Series A, due 2035 | 100,000 | 90,925 | 100,000 | 101,050 | ||||||||||
4.75% 2006 Series A, due 2036 | 56,000 | 49,243 | 56,000 | 56,213 | ||||||||||
Unamortized discount | (4,531 | ) | — | (4,697 | ) | — | ||||||||
541,469 | 541,303 | |||||||||||||
Other | 33,620 | 33,998 | 29,617 | |||||||||||
1,304,146 | 1,313,899 | |||||||||||||
Less: current maturities | (38,079 | ) | (27,545 | ) | ||||||||||
Long-term debt, less current maturities | $ | 1,266,067 | $ | 1,286,354 | ||||||||||
In April 2007, the Company amended its $300 million credit facility. The facility was originally scheduled to expire in April 2011 and was extended to April 2012. The Company will continue to use $150 million of the $300 million as long-term debt and the remaining $150 million for working capital purposes. Interest rates for the facility are calculated at either the London Interbank Offering Rate plus
61
an applicable margin, or the greater of the prime rate or one-half of one percent plus the Federal Funds rate. The applicable margin, unused commitment fee, and utilization fee associated with the amended credit facility are lower than those of the previous facility. At December 31, 2007, $9 million in borrowings were outstanding on the short-term portion of the credit facility and $150 million was outstanding on the long-term portion.
The Company’s Revolving Credit Facility, letters of credit, and certain bond insurance policies contain financial covenants, the most restrictive of which require a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $475 million adjusted for equity issuances after May 10, 2002. If the Company was not in compliance with these covenants, an event of default would occur, which if not cured could cause the amounts outstanding to become due and payable. This would also trigger cross-default provisions in substantially all other outstanding indebtedness of the Company. At December 31, 2007, the Company was in compliance with the applicable covenants.
The effective interest rates on the 2003 Series A and B variable-rate IDRBs were 4.51 percent and 4.79 percent, respectively, at December 31, 2007 and 5.14 percent and 4.09 percent, respectively, at December 31, 2006. The effective interest rates on the tax-exempt Series A variable-rate IDRBs were 4.46 percent and 5.03 percent at December 31, 2007 and 2006, respectively.
The fair value of the revolving credit facility and the variable-rate IDRBs approximates carrying value. Market values for the debentures, fixed-rate IDRBs, and other indebtedness were determined based on dealer quotes using trading records for December 31, 2007 and 2006, as applicable, and other secondary sources which are customarily consulted for data of this kind.
Estimated maturities of long-term debt for the next five years are $38.1 million, $10.4 million, $5.4 million, $202.6 million, and $350.1 million, respectively.
Note 7—Short-Term Debt
As discussed in Note 6, Southwest has a $300 million credit facility that expires in April 2012, of which $150 million has been designated by management for working capital purposes (and related outstanding amounts are designated as short-term debt). Southwest had $9 million in short-term borrowings outstanding on the credit facility at December 31, 2007 and none at December 31, 2006. The weighted-average interest rate on these borrowings was 5.66 percent at December 31, 2007.
Note 8—Commitments and Contingencies
The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is subject will have a material adverse impact on its financial position or results of operations.
Note 9—Pension and Other Postretirement Benefits
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.
In 2006, the FASB issued SFAS No. 158, which required employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in their balance sheets. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards 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. SFAS No. 158 did not change how net periodic pension and postretirement costs are accounted for and reported in the income statement. The Company adopted the provisions of SFAS No. 158 effective December 31, 2006.
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In accordance with SFAS No. 71, 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.
The table below discloses net amounts recognized in accumulated other comprehensive income as a result of adopting the provisions of SFAS No. 158 (as impacted by SFAS No. 71) as of December 31, 2006. Tax amounts are calculated using a 38 percent rate.
Total | Qualified Retirement Plan | SERP | PBOP | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
Adjustments to adopt SFAS No. 158: | ||||||||||||||||
Net actuarial loss, net of $44.9 million of tax | $ | (73,323 | ) | $ | (62,464 | ) | $ | (8,045 | ) | $ | (2,814 | ) | ||||
Net transition obligation, net of $2 million of tax | (3,225 | ) | — | — | (3,225 | ) | ||||||||||
Prior service credit, net of $9,000 of tax | 14 | 14 | — | — | ||||||||||||
Reversal of additional minimum pension liability, net of $14.4 million of tax | 23,551 | 16,432 | 7,119 | — | ||||||||||||
Estimated amounts recoverable through rates, net of $29.4 million of tax | 47,915 | 41,876 | — | 6,039 | ||||||||||||
Total amounts recognized in accumulated other comprehensive income | $ | (5,068 | ) | $ | (4,142 | ) | $ | (926 | ) | $ | — | |||||
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 preserve 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. Rate of 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 | 58 to 70 | |
Debt securities | 32 to 38 | |
Other | up to 5 |
The Company’s pension costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, discount rates, and by employee demographics, including age, compensation, and length of service. Changes made to the provisions of the plans may also impact current and future pension costs. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions about future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Relatively small changes in these assumptions, particularly the discount rate, may significantly affect pension costs and plan obligations for the qualified retirement plan.
SFAS No. 87 “Employer’s Accounting for Pensions” 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 currently available and expected to be available during the period to maturity of the pension benefits. In determining the discount rate, the Company matches the plan’s projected cash flows to a spot-rate yield curve based on highly rated corporate bonds. Changes to the discount rate from year-to-year, if any, are made in increments of 25 basis points.
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Due to an increase in market interest rates for high-quality debt instruments, the Company raised the discount rate to 6.50% at December 31, 2007 from 6.00% at December 31, 2006. The weighted-average rate of compensation increase was raised to 4.00% from 3.75%. The asset return assumption was decreased to 8.00% from 8.50%. These offsetting changes will not result in a significant change in pension expense for 2008.
The following tables set forth the retirement plan, SERP, and PBOP funded status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.
2007 | ||||||||||||
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) | $ | 495,803 | $ | 33,657 | $ | 39,107 | ||||||
Service cost | 16,491 | 153 | 811 | |||||||||
Interest cost | 29,244 | 1,948 | 2,304 | |||||||||
Actuarial loss (gain) | (14,648 | ) | (810 | ) | (4,647 | ) | ||||||
Benefits paid | (17,028 | ) | (2,343 | ) | (1,071 | ) | ||||||
Benefit obligation at end of year (PBO/PBO/APBO) | 509,862 | 32,605 | 36,504 | |||||||||
Change in plan assets | ||||||||||||
Market value of plan assets at beginning of year | 388,706 | — | 24,828 | |||||||||
Actual return on plan assets | 17,230 | — | 854 | |||||||||
Employer contributions | 26,355 | 2,343 | 791 | |||||||||
Benefits paid | (17,028 | ) | (2,343 | ) | — | |||||||
Market value of plan assets at end of year | 415,263 | — | 26,473 | |||||||||
Funded status at year end | $ | (94,599 | ) | $ | (32,605 | ) | $ | (10,031 | ) | |||
Weighted-average assumptions (benefit obligation) | ||||||||||||
Discount rate | 6.50 | % | 6.50 | % | 6.50 | % | ||||||
Weighted-average rate of compensation increase | 4.00 | % | 4.00 | % | 4.00 | % | ||||||
Asset Allocation | ||||||||||||
Equity securities | 60 | % | 76 | % | ||||||||
Debt securities | 35 | % | 17 | % | ||||||||
Other | 5 | % | 7 | % | ||||||||
Total | 100 | % | N/A | 100 | % | |||||||
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2006 | ||||||||||||
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) | $ | 473,418 | $ | 34,123 | $ | 37,553 | ||||||
Service cost | 16,284 | 211 | 854 | |||||||||
Interest cost | 26,805 | 1,893 | 2,118 | |||||||||
Actuarial loss (gain) | (4,806 | ) | (207 | ) | (297 | ) | ||||||
Benefits paid | (15,898 | ) | (2,363 | ) | (1,121 | ) | ||||||
Benefit obligation at end of year (PBO/PBO/APBO) | 495,803 | 33,657 | 39,107 | |||||||||
Change in plan assets | ||||||||||||
Market value of plan assets at beginning of year | 338,618 | — | 20,979 | |||||||||
Actual return on plan assets | 42,733 | — | 2,742 | |||||||||
Employer contributions | 23,253 | 2,363 | 1,107 | |||||||||
Benefits paid | (15,898 | ) | (2,363 | ) | — | |||||||
Market value of plan assets at end of year | 388,706 | — | 24,828 | |||||||||
Funded status at year end | $ | (107,097 | ) | $ | (33,657 | ) | $ | (14,279 | ) | |||
Weighted-average assumptions (benefit obligation) | ||||||||||||
Discount rate | 6.00 | % | 6.00 | % | 6.00 | % | ||||||
Weighted-average rate of compensation increase | 3.75 | % | 3.75 | % | 3.75 | % | ||||||
Asset Allocation | ||||||||||||
Equity securities | 63 | % | 77 | % | ||||||||
Debt securities | 32 | % | 16 | % | ||||||||
Other | 5 | % | 7 | % | ||||||||
Total | 100 | % | N/A | 100 | % | |||||||
Estimated funding for the plans above during calendar year 2008 is approximately $29 million. The accumulated benefit obligation for the retirement plan was $442 million and $422 million, and for the SERP was $31 million and $32.2 million at December 31, 2007 and 2006, respectively.
Pension benefits expected to be paid for each of the next five years beginning with 2008 are the following: $20 million, $21 million, $22 million, $24 million, and $25 million. Pension benefits expected to be paid during 2013 to 2017 total $155 million. Retiree welfare benefits expected to be paid for each of the next five years beginning with 2008 are the following: $1.5 million, $1.6 million, $1.7 million, $1.8 million, and $1.9 million. Retiree welfare benefits expected to be paid during 2013 to 2017 total $13 million. SERP benefits expected to be paid for each of the next five years beginning with 2008 are approximately $2.5 million. SERP benefits expected to be paid during 2013 to 2017 total $12 million. No assurance can be made that actual funding and benefits paid will match our estimates.
For PBOP measurement purposes, the per capita cost of covered health care benefits is assumed to increase five percent annually. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. The assumed annual rate of increase noted above applies to the benefit obligations of pre-1989 retirees only.
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Qualified Retirement Plan | SERP | PBOP | ||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||||||||||||||
Components of net periodic benefit cost: |
| |||||||||||||||||||||||||||||||||||
Service cost | $ | 16,491 | $ | 16,284 | $ | 15,787 | $ | 153 | $ | 211 | $ | 223 | $ | 811 | $ | 854 | $ | 837 | ||||||||||||||||||
Interest cost | 29,244 | 26,805 | 25,327 | 1,948 | 1,893 | 1,811 | 2,304 | 2,118 | 2,115 | |||||||||||||||||||||||||||
Expected return on plan assets | (33,030 | ) | (30,608 | ) | (29,553 | ) | — | — | — | (2,144 | ) | (1,817 | ) | (1,675 | ) | |||||||||||||||||||||
Amortization of prior service costs (credits) | (11 | ) | (11 | ) | (11 | ) | — | 9 | 116 | — | — | — | ||||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | — | — | 867 | 867 | 867 | |||||||||||||||||||||||||||
Amortization of net actuarial loss | 5,007 | 5,352 | 2,453 | 1,131 | 1,244 | 912 | 57 | 168 | 136 | |||||||||||||||||||||||||||
Net periodic benefit cost | $ | 17,701 | $ | 17,822 | $ | 14,003 | $ | 3,232 | $ | 3,357 | $ | 3,062 | $ | 1,895 | $ | 2,190 | $ | 2,280 | ||||||||||||||||||
Weighted-average assumptions (net benefit cost) |
| |||||||||||||||||||||||||||||||||||
Discount rate | 6.00 | % | 5.75 | % | 6.00 | % | 6.00 | % | 5.75 | % | 6.00 | % | 6.00 | % | 5.75 | % | 6.00 | % | ||||||||||||||||||
Expected return on plan assets | 8.50 | % | 8.50 | % | 8.75 | % | 8.50 | % | 8.50 | % | 8.75 | % | 8.50 | % | 8.50 | % | 8.75 | % | ||||||||||||||||||
Weighted-average rate of compensation increase | 3.75 | % | 3.30 | % | 4.00 | % | 3.75 | % | 3.30 | % | 4.00 | % | 3.75 | % | 3.30 | % | 4.00 | % |
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
2007 | ||||||||||||||||
Total | Qualified Retirement Plan | SERP | PBOP | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
Net actuarial loss (gain) (a) | $ | (3,012 | ) | $ | 1,155 | $ | (809 | ) | $ | (3,358 | ) | |||||
Amortization of prior service credit (b) | 11 | 11 | — | — | ||||||||||||
Amortization of transition obligation (b) | (867 | ) | — | — | (867 | ) | ||||||||||
Amortization of net actuarial loss (b) | (6,195 | ) | (5,007 | ) | (1,131 | ) | (57 | ) | ||||||||
Regulatory adjustment | 8,747 | 4,465 | — | 4,282 | ||||||||||||
Recognized in other comprehensive (income) loss | $ | (1,316 | ) | $ | 624 | $ | (1,940 | ) | $ | — | ||||||
Total of amount recognized in net periodic benefit cost and other comprehensive (income) loss | $ | 21,512 | $ | 18,325 | $ | 1,292 | $ | 1,895 | ||||||||
The table above discloses the net gain or loss, prior service cost, and transition amount recognized in other comprehensive income, separated into (a) amounts initially recognized in other comprehensive income, and (b) amounts subsequently recognized as adjustments to other comprehensive income as those amounts are amortized as components of net periodic benefit cost.
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Related Tax Effects Allocated to Each Component of Other Comprehensive Income
2007 | ||||||||||||
Before- Tax Amount | Tax (Expense) or Benefit (a) | Net-of- Tax Amount | ||||||||||
(Thousands of dollars) | ||||||||||||
Defined benefit pension plans: | ||||||||||||
Net loss (gain) | $ | (3,012 | ) | $ | 1,145 | $ | (1,867 | ) | ||||
Amortization of prior service credit | 11 | (4 | ) | 7 | ||||||||
Amortization of transition obligation | (867 | ) | 329 | (538 | ) | |||||||
Amortization of net loss | (6,195 | ) | 2,354 | (3,841 | ) | |||||||
Regulatory adjustment | 8,747 | (3,324 | ) | 5,423 | ||||||||
Other comprehensive (income) loss | $ | (1,316 | ) | $ | 500 | $ | (816 | ) | ||||
(a) | Tax amounts are calculated using a 38 percent rate. |
The estimated net loss that will be amortized from accumulated other comprehensive income or regulatory assets into net periodic benefit cost over the next year is $3.1 million for the qualified retirement plan and $1 million for the SERP. The estimated transition obligation for the PBOP that will be amortized from regulatory assets into net periodic benefit cost over the next year is $870,000. The estimated prior service costs (credits) for the qualified retirement plan and SERP and the estimated net loss for the PBOP that will be amortized over the next year are not significant.
The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches up to one-half of amounts deferred. The maximum matching contribution is three percent of an employee’s annual compensation. Beginning January 2008, the maximum matching contribution will be three and one-half percent of an employee’s annual compensation. The cost of the plan was $3.8 million in 2007, $3.6 million in 2006, and $3.5 million in 2005. NPL has a separate plan, the cost and liability for which are not significant.
Southwest has a deferred compensation plan for all officers and a separate deferred compensation plan for members of the Board of Directors. The plans provide the opportunity to defer up to 100 percent of annual cash compensation. Southwest matches one-half of amounts deferred by officers. The maximum matching contribution is three percent of an officer’s annual base salary. Beginning March 2008, the maximum matching contribution will be three and one-half percent of an officer’s annual base salary. Upon retirement, payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150 percent of Moody’s Seasoned Corporate Bond Rate Index.
Note 10—Stock-Based Compensation
At December 31, 2007, the Company had three stock-based compensation plans: a stock option plan, a performance share stock plan, and a restricted stock/unit plan. The stock option plan and the performance share stock plan were both in existence prior to January 1, 2006 and were accounted for in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payment” using the modified prospective transition method. Under the modified prospective transition method, expense is recognized for any new awards granted after the effective date and for the unvested portion of awards granted prior to the effective date. Accordingly, financial information for 2005 disclosed in the following tables was not restated.
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Under the option plan, the Company 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. 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 options vest 40 percent at the end of year one and 30 percent at the end of years two and three. The grant date fair value of the options was estimated using the Black-Scholes option pricing model. The following assumptions were used in the valuation calculation:
2006 | 2005 | |||||
Dividend yield | 2.48 to 2.82 | % | 3.14 to 3.28 | % | ||
Risk-free interest rate range | 4.91 to 5.06 | % | 3.88 to 4.09 | % | ||
Expected volatility range | 15 | % | 18 | % | ||
Expected life | 6 years | 6 years |
The following tables summarize Company stock option plan activity and related information (thousands of options):
2007 | 2006 | 2005 | ||||||||||||||||
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 | 957 | $ | 26.26 | 1,475 | $ | 23.70 | 1,646 | $ | 22.46 | |||||||||
Granted during the year | — | — | 252 | 32.60 | 347 | 26.00 | ||||||||||||
Exercised during the year | (158 | ) | 23.24 | (749 | ) | 23.30 | (510 | ) | 21.28 | |||||||||
Forfeited during the year | (1 | ) | 33.07 | (6 | ) | 26.81 | (8 | ) | 22.41 | |||||||||
Expired during the year | — | — | (15 | ) | 28.09 | — | — | |||||||||||
Outstanding at year end | 798 | $ | 26.85 | 957 | $ | 26.26 | 1,475 | $ | 23.70 | |||||||||
Exercisable at year end | 561 | $ | 25.50 | 413 | $ | 23.31 | 813 | $ | 23.06 | |||||||||
The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of outstanding options was $3.1 million, $11.6 million, and $4.3 million at December 31, 2007, December 31, 2006, and December 31, 2005, respectively. The aggregate intrinsic value of exercisable options was $2.7 million, $6.2 million, and $3 million at December 31, 2007, December 31, 2006, and December 31, 2005, respectively. The aggregate intrinsic value of exercised options was $1 million, $11.3 million, and $2.6 million during 2007, 2006, and 2005, respectively. The market value of Southwest Gas stock was $29.77, $38.37, and $26.40 at December 31, 2007, December 31, 2006, and December 31, 2005, respectively.
The weighted-average remaining contractual life for outstanding options was 6.9 years for 2007. The weighted-average remaining contractual life for exercisable options was 6.4 years for 2007. No options were granted in 2007; the weighted-average grant-date fair value of options granted was $5.92 for 2006 and $4.18 for 2005. The following table summarizes information about stock options outstanding at December 31, 2007 (thousands of options):
Options Outstanding | Options Exercisable | |||||||||||
Range of Exercise Price | Number outstanding | Weighted- average remaining contractual life | Weighted- average exercise price | Number exercisable | Weighted- average exercise price | |||||||
$17.94 to $23.40 | 294 | 5.5 Years | $ | 22.62 | 294 | $ | 22.62 | |||||
$24.50 to $26.10 | 240 | 7.4 Years | $ | 25.92 | 148 | $ | 25.87 | |||||
$28.75 to $33.07 | 264 | 8.1 Years | $ | 32.41 | 119 | $ | 32.14 |
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As of December 31, 2007, there was $658,000 of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a period of 2 years. The total fair value of options vested was $1.2 million, $1 million, and $609,000 during 2007, 2006, and 2005, respectively. The Company received $3.7 million in cash from the exercise of options during 2007 and a corresponding tax benefit of $625,000 which was recorded in additional paid-in capital.
The following table summarizes the status of the Company’s nonvested options as of December 31, 2007 (thousands of options):
Number of options | Weighted- average grant date fair value | |||||
Nonvested at the beginning of the year | 544 | $ | 4.47 | |||
Granted | — | $ | — | |||
Vested | (306 | ) | $ | 3.87 | ||
Forfeited | (1 | ) | $ | 6.03 | ||
Nonvested at December 31, 2007 | 237 | $ | 5.25 | |||
Under the performance share stock plan, the Company may issue performance shares to encourage key employees to remain in its employment and to achieve short-term and long-term performance goals. Plan participants are eligible to receive a cash bonus (i.e., short-term incentive) and performance shares (i.e., long-term incentive). The performance shares vest three years after grant (and are subject to a final adjustment as determined by the Board of Directors) and are then issued as common stock. The following table summarizes the activity of this plan (thousands of shares):
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||||
Nonvested performance shares at beginning of year | 319 | 357 | 316 | |||||||||
Performance shares granted (including dividends) | 95 | 95 | 143 | |||||||||
Performance shares forfeited | — | — | (6 | ) | ||||||||
Shares vested and issued* | (122 | ) | (133 | ) | (96 | ) | ||||||
Nonvested performance shares at end of year | 292 | 319 | 357 | |||||||||
Average grant date fair value of awards granted this year | $ | 38.21 | $ | 26.97 | $ | 24.71 | ||||||
* | Includes shares converted for taxes and retiree payouts. |
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In 2007, the Company instituted a restricted stock/unit plan to award restricted stock and restricted stock/units to attract, motivate, retain, and reward key employees with an incentive to attain high levels of individual performance and improved financial performance of the Company. The restricted stock/unit plan was also established to attract, motivate, and retain experienced and knowledgeable independent directors. The restricted stock/units vest 40 percent at the end of year one and 30 percent at the end of years two and three. The following table summarizes the activity of this plan (thousands of shares):
Year Ended December 31, | 2007 | |||
Nonvested restricted stock/units at beginning of year | — | |||
Restricted stock/units granted (including dividends) | 50 | |||
Restricted stock/units forfeited | — | |||
Shares vested and issued* | (1 | ) | ||
Nonvested restricted stock/units at end of year | 49 | |||
Average grant date fair value of awards granted this year | $ | 38.48 | ||
* | Includes shares converted for taxes and retiree payouts. |
Note 11—Income Taxes
The Company adopted the provisions of FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes,” on January 1, 2007. The adoption of the standard had no impact on the Company’s financial position or results of operations. In connection with the adoption, the Company identified $1.4 million in liabilities related to unrecognized tax benefits, which, if recognized, would favorably impact the effective tax rate. The Company also identified $1.3 million of accrued net interest ($2 million gross interest) related to uncertain tax positions. Both the liabilities related to the unrecognized tax benefits and interest, were recorded as of December 31, 2006. In the second quarter of 2007, the Company made income tax payments to the IRS for tax and accrued interest related to the uncertain tax positions. There was no change to the balance of unrecognized tax benefits during 2007 and the Company does not expect a material change in the next twelve months. The Company recognizes interest expense and income and penalties related to income tax matters in income tax expense. A total of $1 million of tax-related interest income was recognized in 2007 in the statement of operations. A total of $1 million of interest receivable is recorded on the statement of financial position at December 31, 2007.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various states. The Company is no longer subject to U.S. federal examinations by tax authorities for years before 2001, and is no longer subject to state examinations for years before 2002. In the fourth quarter of 2006, the Internal Revenue Service (“IRS”) completed its examination of the Company’s federal income tax returns for 2001 through 2004. As of December 31, 2007, the IRS had proposed certain timing-related adjustments to the Company’s tax returns as filed. Management appealed the proposed assessment but has not resolved the issues as of December 31, 2007. The Company does not anticipate the adjustments would result in a material change to its financial position or results of operations.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (thousands of dollars):
Unrecognized tax benefits at December 31, 2006 | $ | 1,445 | |
Gross increases—tax positions in prior period | — | ||
Gross decreases—tax positions in prior period | — | ||
Gross increases—current period tax positions | — | ||
Gross decreases—current period tax positions | — | ||
Settlements | — | ||
Lapse of statute of limitations | — | ||
Unrecognized tax benefits at December 31, 2007 | $ | 1,445 | |
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Income tax expense (benefit) consists of the following (thousands of dollars):
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||||
Current: | ||||||||||||
Federal | $ | 37,668 | $ | 29,916 | $ | 553 | ||||||
State | 6,989 | 4,830 | 2,218 | |||||||||
44,657 | 34,746 | 2,771 | ||||||||||
Deferred: | ||||||||||||
Federal | 2,813 | 9,385 | 21,301 | |||||||||
State | 308 | 366 | 540 | |||||||||
3,121 | 9,751 | 21,841 | ||||||||||
Total income tax expense | $ | 47,778 | $ | 44,497 | $ | 24,612 | ||||||
Deferred income tax expense (benefit) consists of the following significant components (thousands of dollars): |
| |||||||||||
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||||
Deferred federal and state: | ||||||||||||
Property-related items | $ | 26,300 | $ | 28,372 | $ | (3,143 | ) | |||||
Purchased gas cost adjustments | (24,972 | ) | (22,188 | ) | 28,094 | |||||||
Employee benefits | 2,263 | (3,223 | ) | 2,232 | ||||||||
Injuries and damages reserves | 85 | 4,543 | (4,072 | ) | ||||||||
All other deferred | 313 | 3,115 | (402 | ) | ||||||||
Total deferred federal and state | 3,989 | 10,619 | 22,709 | |||||||||
Deferred ITC, net | (868 | ) | (868 | ) | (868 | ) | ||||||
Total deferred income tax expense | $ | 3,121 | $ | 9,751 | $ | 21,841 | ||||||
The consolidated effective income tax rate for the period ended December 31, 2007 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, | 2007 | 2006 | 2005 | ||||||
Federal statutory income tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
Net state taxes | 2.7 | 2.5 | 2.7 | ||||||
Property-related items | 0.4 | 0.6 | 1.1 | ||||||
Effect of income tax settlements | (0.4 | ) | (1.3 | ) | — | ||||
Tax credits | (0.7 | ) | (0.7 | ) | (1.3 | ) | |||
Corporate owned life insurance | (0.5 | ) | (0.9 | ) | (1.6 | ) | |||
All other differences | — | (0.5 | ) | 0.1 | |||||
Consolidated effective income tax rate | 36.5 | % | 34.7 | % | 36.0 | % | |||
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Deferred tax assets and liabilities consist of the following (thousands of dollars):
December 31, | 2007 | 2006 | |||||
Deferred tax assets: | |||||||
Deferred income taxes for future amortization of ITC | $ | 5,890 | $ | 6,427 | |||
Employee benefits | 33,779 | 36,542 | |||||
Alternative minimum tax credit | 22,518 | 36,820 | |||||
Other | 5,267 | 4,549 | |||||
Valuation allowance | — | — | |||||
67,454 | 84,338 | ||||||
Deferred tax liabilities: | |||||||
Property-related items, including accelerated depreciation | 356,609 | 330,308 | |||||
Regulatory balancing accounts | 21,235 | 46,207 | |||||
Property-related items previously flowed through | 7,176 | 8,272 | |||||
Unamortized ITC | 9,463 | 10,330 | |||||
Debt-related costs | 5,291 | 5,681 | |||||
Other | 8,212 | 7,504 | |||||
407,986 | 408,302 | ||||||
Net deferred tax liabilities | $ | 340,532 | $ | 323,964 | |||
Current | $ | (6,965 | ) | $ | 15,471 | ||
Noncurrent | 347,497 | 308,493 | |||||
Net deferred tax liabilities | $ | 340,532 | $ | 323,964 | |||
Note 12—Segment Information
Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, transporting, and distributing natural gas. Revenues are generated from the sale and transportation of natural gas. The construction services segment is engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
The accounting policies of the reported segments are the same as those described withinNote 1—Summary of Significant Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2007 and 2006, accounts receivable for these services totaled $6.1 million and $9.2 million, respectively, which were not eliminated during consolidation.
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The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2007 is as follows (thousands of dollars):
2007 | Gas Operations | Construction Services | Adjustments (a) | Total | |||||||||
Revenues from unaffiliated customers | $ | 1,814,766 | $ | 265,937 | $ | 2,080,703 | |||||||
Intersegment sales | — | 71,385 | 71,385 | ||||||||||
Total | $ | 1,814,766 | $ | 337,322 | $ | 2,152,088 | |||||||
Interest expense | $ | 94,163 | $ | 2,036 | $ | 96,199 | |||||||
Depreciation and amortization | $ | 157,090 | $ | 25,424 | $ | 182,514 | |||||||
Income tax expense | $ | 40,914 | $ | 6,864 | $ | 47,778 | |||||||
Segment income | $ | 72,494 | $ | 10,752 | $ | 83,246 | |||||||
Segment assets | $ | 3,518,304 | $ | 152,096 | $ | (212 | ) | $ | 3,670,188 | ||||
Capital expenditures | $ | 312,412 | $ | 28,463 | $ | 340,875 | |||||||
2006 | Gas Operations | Construction Services | Adjustments (a) | Total | |||||||||
Revenues from unaffiliated customers | $ | 1,727,394 | $ | 216,753 | $ | 1,944,147 | |||||||
Intersegment sales | — | 80,611 | 80,611 | ||||||||||
Total | $ | 1,727,394 | $ | 297,364 | $ | 2,024,758 | |||||||
Interest expense | $ | 93,291 | $ | 1,686 | $ | 94,977 | |||||||
Depreciation and amortization | $ | 146,654 | $ | 22,310 | $ | 168,964 | |||||||
Income tax expense | $ | 36,240 | $ | 8,257 | $ | 44,497 | |||||||
Segment income | $ | 71,473 | $ | 12,387 | $ | 83,860 | |||||||
Segment assets | $ | 3,352,074 | $ | 136,654 | $ | (3,763 | ) | $ | 3,484,965 | ||||
Capital expenditures | $ | 305,914 | $ | 39,411 | $ | 345,325 | |||||||
2005 | Gas Operations | Construction Services | Adjustments (a) | Total | |||||||||
Revenues from unaffiliated customers | $ | 1,455,257 | $ | 187,249 | $ | 1,642,506 | |||||||
Intersegment sales | — | 71,777 | 71,777 | ||||||||||
Total | $ | 1,455,257 | $ | 259,026 | $ | 1,714,283 | |||||||
Interest expense | $ | 89,318 | $ | 1,009 | $ | 90,327 | |||||||
Depreciation and amortization | $ | 137,981 | $ | 18,272 | $ | 156,253 | |||||||
Income tax expense | $ | 17,767 | $ | 6,845 | $ | 24,612 | |||||||
Segment income | $ | 33,670 | $ | 10,153 | $ | 43,823 | |||||||
Segment assets | $ | 3,103,804 | $ | 128,181 | $ | (3,559 | ) | $ | 3,228,426 | ||||
Capital expenditures | $ | 258,547 | $ | 35,822 | $ | 294,369 | |||||||
(a) | Construction services segment assets include income taxes payable of $212,000 in 2007, which was netted against gas operations segment income taxes receivable, net during consolidation. Construction services segment assets include deferred tax assets of $3 million and income taxes payable of $758,000 in 2006, which were netted against gas operations segment deferred tax liabilities and income taxes receivable, net during consolidation. Construction services segment assets include deferred tax assets of $3.6 million in 2005 which were netted against gas operations segment deferred tax liabilities during consolidation. |
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Note 13—Quarterly Financial Data (Unaudited)
Quarter Ended | ||||||||||||||
March 31 | June 30 | September 30 | December 31 | |||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||||
2007 | ||||||||||||||
Operating revenues | $ | 793,716 | $ | 426,537 | $ | 371,524 | $ | 560,311 | ||||||
Operating income | 100,888 | 17,645 | 8,456 | 93,598 | ||||||||||
Net income (loss) | 49,764 | (337 | ) | (9,318 | ) | 43,137 | ||||||||
Basic earnings (loss) per common share* | 1.19 | (0.01 | ) | (0.22 | ) | 1.01 | ||||||||
Diluted earnings (loss) per common share* | 1.17 | (0.01 | ) | (0.22 | ) | 1.00 | ||||||||
2006 | ||||||||||||||
Operating revenues | $ | 676,941 | $ | 430,902 | $ | 351,800 | $ | 565,115 | ||||||
Operating income | 89,325 | 25,236 | 3,197 | 91,424 | ||||||||||
Net income (loss) | 44,180 | 3,709 | (10,736 | ) | 46,707 | |||||||||
Basic earnings (loss) per common share* | 1.12 | 0.09 | (0.26 | ) | 1.12 | |||||||||
Diluted earnings (loss) per common share* | 1.11 | 0.09 | (0.26 | ) | 1.11 | |||||||||
2005 | ||||||||||||||
Operating revenues | $ | 542,880 | $ | 361,130 | $ | 313,278 | $ | 496,995 | ||||||
Operating income (loss) | 72,849 | 14,935 | (5,459 | ) | 68,323 | |||||||||
Net income (loss) | 32,829 | (2,817 | ) | (16,444 | ) | 30,255 | ||||||||
Basic earnings (loss) per common share* | 0.88 | (0.07 | ) | (0.43 | ) | 0.77 | ||||||||
Diluted earnings (loss) per common share* | 0.88 | (0.07 | ) | (0.43 | ) | 0.76 |
* | The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted-average number of common shares outstanding. |
The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for the interim periods do not reliably reflect overall trends and changes in the operations of the Company. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.
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2007
MANAGEMENT’SREPORTONINTERNALCONTROLOVERFINANCIALREPORTING
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Company management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the“Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon the Company’s evaluation under such framework, Company management concluded that the internal control over financial reporting was effective as of December 31, 2007. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which is included herein.
February 28, 2008
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2007
REPORTOFINDEPENDENTREGISTEREDPUBLICACCOUNTINGFIRM
To the Board of Directors and Stockholders of Southwest Gas Corporation
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of stockholders’ equity and comprehensive income present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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, 2007, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 9 and Note 10 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit postretirement plans and share-based compensation in 2006.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 28, 2008
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