10-K405/A 1 a2067882z10-k405a.txt FORM 10-K405/A =============================================================================== SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A Amendment No. One (Mark One) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____ TO _____. Commission File No. 1-8796 QUESTAR CORPORATION -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) State of Utah 87-0407509 -------------------------------------------------------------------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433 -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (801) 324-5000 ---------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Common Stock, Without Par Value, with New York Stock Exchange Common Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/ The aggregate market value of the registrant's common stock, without par value, held by nonaffiliates on March 1, 2001, was $2,167,204,320 (based on the closing price of such stock). On March 1, 2001, 80,647,952 shares of the registrant's common stock, without par value, were outstanding. DOCUMENTS INCORPORATED BY REFERENCE. Portions of the definitive Proxy Statement for the 2001 Annual Meeting of Stockholders are incorporated by reference into Part III. The sections of the Proxy Statement labeled "Committee Report on Executive Compensation" and "Cumulative Total Shareholder Return" are expressly not incorporated into this document. TABLE OF CONTENTS
HEADING PAGE PART II Item 6. SELECTED FINANCIAL DATA................................................................................. 2 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION............................................................................................... 3 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK............................................. 14 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K................................................................................ 17 SIGNATURES....................................................................................................... 55
ITEM 6. SELECTED FINANCIAL DATA (RESTATED)
2000 1999 1998 1997 1996 ----------------------------------------------------------------- (In Thousands, Except Per Share Amounts) Revenues $1,266,153 $924,219 $906,256 $936,337 $817,981 Operating expenses Cost of natural gas and other products sold 562,229 352,554 367,932 399,941 314,271 Operating and maintenance 251,477 221,082 208,190 205,723 196,389 Depreciation, depletion and amortization 142,491 132,164 118,745 113,063 93,827 Other expenses 61,989 45,580 57,998 61,170 36,390 ----------------------------------------------------------------- Total operating expenses 1,018,186 751,380 752,865 779,897 640,877 ----------------------------------------------------------------- Operating income $247,967 $172,839 $153,391 $156,440 $177,104 ================================================================= Interest and other income $39,463 $78,700 $17,021 $22,481 $11,109 Write-down of investment in partnership (49,700) Net income $149,477 $96,852 $89,310 $98,630 $100,014 Basic earnings per common share $1.86 $1.17 $1.08 $1.20 $1.22 Diluted earnings per common share $1.85 $1.17 $1.08 $1.19 $1.21 Dividends per share $0.685 $0.67 $0.6525 $0.62 $0.60 Book value per common share $11.79 $10.99 $10.27 $9.79 $8.97 Total assets $2,472,027 $2,184,734 $2,111,540 $1,874,974 $1,757,116 Net cash provided from operating activities 252,067 207,331 278,005 197,596 177,175 Capital expenditures 315,142 261,983 455,477 208,359 289,314 Capitalization Long-term debt, less current portion $714,537 $735,043 $615,770 $541,986 $555,509 Redeemable cumulative preferred stock 4,828 Common stock 952,632 894,516 848,752 803,858 736,341 ----------------------------------------------------------------- Total capitalization $1,667,169 $1,629,559 $1,464,522 $1,345,844 $1,296,678 =================================================================
2 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SUMMARY On July 1, 2001, Questar Market Resources (QMR) elected to change its accounting method for gas and oil properties from the full cost method to the successful efforts method. The change was prompted by an acquisition of a company that uses successful efforts. A subsidiary, Wexpro, has always employed the successful efforts method. Management believes that the successful efforts method is preferable and will more accurately present the results of operations of the Company's exploration, development and production activities, minimizes asset write-downs caused by temporary declines in gas and oil prices and reflects impairment of the carrying value of the Company's gas and oil properties only when there has been an other-than-temporary decline in their fair value. Prior years financial statements have been retroactively restated to reflect this change in accounting method. As a result of the change in accounting method, previously reported earnings decreased $7.2 million ($.09 per share) and $2.0 million ($.03 per share) for the years ended December 31, 2000 and 1999, respectively, and increased $9.4 million ($.15 per share) for the year ended December 31, 1998. Questar Corporation earned $149.5 million in 2000, representing a 54% improvement over net income reported for 1999. Following is a year to year comparison of net income by line of business.
2000 1999 Change Percentage ------------------------------------------------------- (Dollars in thousands) Questar Market Resources (Restated) $77,808 $43,888 $33,920 77% Questar Regulated Services 54,332 11,079 43,253 390% Corporate and other operations 17,337 41,885 (24,548) -59% --------------------------------------- $149,477 $96,852 $52,625 54% ======================================= Earnings per diluted common share $1.85 $1.17 $0.68 58%
Questar Market Resources' net income rose 77% in 2000 compared with 1999 due primarily to higher energy prices, a 10% increase in natural gas production and increased investment by Wexpro in gas-development properties. Net income of Questar Regulated Services increased 390% in 2000. In 1999, Questar Pipeline recorded a write-down of its investment in the TransColorado partnership and ongoing operating losses from the TransColorado partnership. Questar Gas received a $13.5 million general rate increase effective August 11, 2000, including $7.1 million of interim rate relief beginning January 1, 2000. Net income of corporate and other operations decreased 59% in 2000 primarily as the result of reduced sales of securities. Corporate and other operations recorded after tax gains from selling securities of $13.8 million in 2000 compared with $36.9 million in 1999. Repurchase of 3.2 million shares of Questar common stock beginning in April 1999 and continuing through August 2000 increased earnings per share by $.04 in 2000. 3 RESULTS OF OPERATIONS QUESTAR MARKET RESOURCES (Market Resources) conducts Questar's exploration and production, gas development, gathering, processing and marketing activities. Following is a restated summary of financial results and operating information.
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------- (IN THOUSANDS) OPERATING INCOME Revenues Natural gas sales $193,359 $125,245 $98,767 Oil and natural gas liquids sales 59,901 41,521 36,722 Cost-of-service gas operations 74,492 61,705 61,448 Energy marketing 379,760 243,296 234,565 Gas gathering and processing 29,278 22,341 21,954 Other 5,263 4,203 4,816 ------------------------------------------- Total revenues 742,053 498,311 458,272 Operating expenses Energy purchases 369,752 239,201 230,462 Operating and maintenance 106,761 79,719 73,460 Exploration 7,917 5,321 6,069 Depreciation, depletion and amortization 85,025 73,028 64,965 Abandonment and impairment of oil and gas properties 3,418 7,535 15,137 Other taxes 36,262 21,516 24,988 Wexpro settlement agreement - oil income sharing 4,758 2,292 1,053 ------------------------------------------- Total operating expenses 613,893 428,612 416,134 ------------------------------------------- Operating income $128,160 $69,699 $42,138 =========================================== OPERATING STATISTICS Production volumes Natural gas (in MMcf) 68,963 62,712 51,309 Oil and natural gas liquids (in Mbbl) Questar Exploration & Production 2,225 2,311 2,340 Wexpro 521 555 554 Production revenue Natural gas (per Mcf) $2.80 $2.00 $1.92 Oil and natural gas liquids (per bbl) Questar Exploration & Production $20.50 $13.92 $12.70 Wexpro $27.43 $16.84 $12.64 Wexpro investment base, net of deferred income taxes (in millions) $124.8 $108.9 $97.6 Energy-marketing volumes (in thousands of equivalent dth) 105,632 112,982 113,513 Natural gas-gathering volumes (in Mdth) For unaffiliated customers 92,969 84,961 72,908 For Questar Gas 36,791 32,050 29,893 For other affiliated customers 25,068 19,659 17,720 ------------------------------------------- Total gathering 154,828 136,670 120,521 =========================================== Gathering revenue (per dth) $0.13 $0.15 $0.16
4 REVENUES Revenues were 49% higher in 2000 when compared with 1999 because of higher prices for natural gas, oil and NGL and increased natural gas production. Natural gas production rose 10% to 69 Bcf and the average selling price increased 40%. U. S. gas production increased 3% to 61.7 Bcf, while Canadian production rose 152% to 7.3 Bcf. Questar acquired Canadian reserves and producing properties in January 2000. Approximately 53% of gas production in 2000 was hedged at an average price of $2.16 per Mcf, net to the well. Hedging activities reduced revenues from gas sales by $33.7 million in 2000 but had an insignificant impact in 1999 and 1998. Selling prices of oil and NGL for nonregulated operations increased 47% to a combined average of $20.50 per barrel and more than offset a 4% decrease in production volumes. Approximately 73% of the nonregulated oil production was hedged at an average price of $17.36 per barrel. Hedging activities reduced revenues from oil sales by $15.5 million in 2000, but had an insignificant impact in 1999 and 1998. Production declined in 2000 as a result of selling nonstrategic properties in the fourth quarter of 1999. For 2001, Questar has used swaps, costless collars and fixed-price contracts to hedge approximately 55% of estimated gas production based on December 2000 reserves. The average hedged price is $2.90 per Mcf (net to the well) assuming floor prices on collars. The average hedged price increases to $3.15 per Mcf (net to the well) if collar ceiling prices are assumed. Approximately 62% of 2001 estimated oil production, based on December 2000 reserves, is hedged at an average price of $17.20 per barrel, net to the well. Quantities of hedged production in any given month range between 49% and 66% for gas and 56% and 70% for oil. Revenues from cost-of-service operations were 21% higher in 2000 compared with 1999. Wexpro manages and develops oil and natural gas properties on behalf of Questar Gas and receives a return on its investment in successful wells. The natural gas production is delivered to Questar Gas at cost of service. Oil is sold at market prices. Any net income from oil sales remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas. Questar Gas's portion is reported as oil-income sharing. Wexpro's investment base, net of deferred income taxes, grew 15% in 2000 when compared with 1999. The average return on investment was 19.5% in 2000 and 20% in 1999. Higher energy prices were responsible for substantial increases in revenues for energy marketing and improved plant-processing margins. Increased gas demand led to higher volumes of gas gathering. Revenues in 1999 improved 9% compared with 1998 as a result of increased prices for gas, oil and NGL and a 22% rise in gas production. Natural gas selling prices averaged 4% higher in 1999. OPERATING EXPENSES (RESTATED) Operating and maintenance expenses were 34% higher in 2000 primarily due to an increase in the number of gas and oil properties and increased legal costs in the settlement of a major case. Exploration expense increased 49% in 2000 compared with 1999 primarily as a result of drilling dry exploratory wells. Lower dry hole expense caused a 12% decrease in exploration expense in 1999 compared with 1998. Depreciation, depletion and amortization expense (DD&A) increased 16% in 2000 due largely to a 10% increase in natural gas production. The average DD&A rate for oil and gas properties was $.78 per thousand cubic feet equivalent (Mcfe) for 2000, up from $.71 per Mcfe in 1999. Abandonment and impairment of oil and gas properties in 1998 reflects a write off of assets amounting to $14.7 million as a result of lower energy prices. Other taxes, primarily production related, rose 69% in 2000 driven by higher revenues and prices. 5 NONREGULATED GAS AND OIL RESERVES Market Resources achieved a 261% reserve replacement ratio in 2000 compared with 131% in 1999. Reserve additions, revisions and purchases, net of sales in place, amounted to 214.8 Bcfe in 2000, more than double the 100.1 Bcfe added in 1999. Gains in reserves occurred through drilling results in the Pinedale Anticline and the acquisition of 61.1 Bcfe of proved reserves in Canada. In January 2001, Market Resources closed on the sale of 290 producing properties and a gas gathering system in the Midcontinent for $27 million with an effective sale date of November 2000. The properties produced approximately 4.3 MMcf of gas and 180 barrels of oil per day, but were not compatible with the long-term strategic plans of the Company. In the fourth quarter of 1999, Market Resources sold producing properties mostly in the Permian Basin and Kansas with combined daily production of 4.3 MMcf of gas and 1,100 barrels of oil. Market Resources achieved a five-year average finding cost of $.82 per Mcfe, excluding cost-of-service operations, in 2000 compared with $.86 per Mcfe in 1999. QUESTAR REGULATED SERVICES (Regulated Services) conducts Questar's natural gas-distribution, transmission, storage and nonregulated retail energy services. Natural Gas Distribution - Questar Gas conducts natural gas distribution operations. Following is a summary of financial results and operating information:
YEAR ENDED DECEMBER 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) OPERATING INCOME Revenues Residential and commercial sales $467,293 $396,882 $425,452 Industrial sales 38,993 28,938 29,555 Industrial transportation 6,968 6,594 6,480 Other 23,508 17,523 15,336 ---------------------------------------- Total revenues 536,762 449,937 476,823 Natural gas purchases 334,193 257,265 281,004 ---------------------------------------- 202,569 192,672 195,819 Margin Operating expenses Operating and maintenance 101,486 103,308 96,923 Depreciation and amortization 34,450 36,426 33,261 Other taxes 10,213 7,625 8,185 ---------------------------------------- Total operating expenses 146,149 147,359 138,369 ---------------------------------------- Operating income $56,420 $45,313 $57,450 ======================================== OPERATING STATISTICS Natural gas volumes (in Mdth) Residential and commercial sales 83,373 82,201 83,231 Industrial deliveries Sales 10,314 9,823 9,681 Transportation 54,836 51,643 55,461 ---------------------------------------- Total industrial 65,150 61,466 65,142 ---------------------------------------- Total deliveries 148,523 143,667 148,373 ========================================
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YEAR ENDED DECEMBER 31, 2000 1999 1998 -------------------------------------- Natural gas revenue (per dth) Residential and commercial $5.60 $4.83 $5.11 Industrial sales 3.78 2.95 3.05 Transportation for industrial customers 0.13 0.13 0.12 System natural gas cost (per dth) $3.54 $2.61 $2.57 Heating degree days (normal 5,609) 5,402 5,317 5,462 Warmer than normal 4% 5% 3% Number of customers at December 31, Residential and commercial 703,306 684,950 662,084 Industrial 1,323 1,367 1,308 -------------------------------------- 704,629 686,317 663,392 ======================================
MARGIN (REVENUES LESS NATURAL GAS PURCHASES) Questar Gas' margin increased 5% in 2000 when compared with 1999 after declining by 2% in the prior- year comparison. The improvement was primarily the result of a $13.5 million annual general rate increase. A $7.1 million portion of the Utah rate increase went into effect January 1, 2000, with the remainder reflected in rates beginning August 11, 2000. The rate case authorized Questar Gas to earn up to an 11% return on equity and included $5 million for annual gas processing costs. The rate case resolved an issue in which the Public Service Commission of Utah (PSCU) had denied recovery of $3.6 million of gas processing costs in 1999. Usage per residential customer, calculated on a temperature adjusted basis, decreased in 2000 for the third consecutive year. Usage per residential customer was three decatherms or 3% lower in 2000 when compared with 1999 and two decatherms or 1% lower in 1999 compared with 1998. Temperatures have been warmer than normal for the past seven years. However, since 1995, the financial impact of warmer weather has been minimized because of a weather-normalization adjustment in rates. Customers served by Questar Gas grew by 18,312 or 2.7% in 2000, following growth rates of 3.5% in 1999 and 3.4% in 1998. Industrial deliveries were 6% higher in 2000 due to an increase in natural gas volumes used to generate electricity. Gas deliveries to industrial customers decreased by 6% in 1999 because a major steel-producing customer reduced operations. Margins from gas delivered to industrial customers, either sold or transported, are substantially lower than from gas delivered to residential and commercial customers. Significant gas-cost increases in the second half of 2000 due to rising demand for natural gas in the western U. S. did not affect the margin. Under rate regulation in Utah and Wyoming, Questar Gas can request authorization to recover from customers the cost of its gas supply on a dollar-for-dollar basis. Gas costs in Utah rates have risen from $1.72 per dth in 1999 to $2.91 in 2000. As of January 1, 2001, gas costs in rates rose to $4.67 per dth. OPERATING EXPENSES Operating and maintenance expenses were 2% lower in 2000 due to decreases in legal, information technology and labor costs. Questar Gas improved a number of its information technology systems in 1999 as part of its year 2000 system-readiness program. Labor costs were lower as a result of early retirement programs effective October 31, 2000, and August 31, 1998. Operating and maintenance expenses were 7% higher in 1999 due to incremental costs of serving a growing customer base. Depreciation expense was $2.8 million lower in 2000 due to investments in several information systems being fully depreciated. Depreciation increased 10% in 1999 because of capital spending. Other taxes 7 increased in 2000 because of a $1.4 million current-year adjustment of prior-year taxes and from higher property tax rates. ACQUISITION OF DISTRIBUTION SYSTEMS Questar Gas has agreed in principle to acquire two gas distribution systems in exchange for 390,000 shares of Questar Corporation common stock. The acquisitions, pending approval from the PSCU and Public Service Commission of Wyoming (PSCW), will add about 10,500 customers in Utah and Wyoming. The transactions will be accounted for as a purchase. Natural Gas Transmission - Questar Pipeline conducts natural gas-transmission and storage operations. Following is a summary of financial results and operating information:
Year Ended December 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) OPERATING INCOME Revenues Transportation $72,547 $69,885 $70,824 Storage 37,711 37,647 36,463 Processing 6,763 3,570 Other 2,055 1,058 1,270 ---------------------------------------- Total revenues 119,076 112,160 108,557 Operating expenses Operating and maintenance 43,761 38,534 38,832 Depreciation and amortization 15,391 16,743 13,927 Other taxes 3,071 2,488 2,600 ---------------------------------------- Total operating expenses 62,223 57,765 55,359 ---------------------------------------- Operating income $56,853 $54,395 $53,198 ======================================== OPERATING STATISTICS Natural gas transportation volumes (in Mdth) For unaffiliated customers 158,604 135,886 120,747 For Questar Gas 108,183 105,499 107,501 For other affiliated customers 8,370 12,153 26,878 ---------------------------------------- Total transportation 275,157 253,538 255,126 ======================================== Transportation revenue (per dth) $0.26 $0.28 $0.28
REVENUES Revenues rose 6% in 2000 compared with 1999 due to an increase in the demand charges resulting from a higher quantity of transportation volumes under firm contracts and a full year of operation of a plant that removes excess carbon dioxide from the gas stream. The plant began operation mid-year 1999. The transportation system experienced an increased demand for gas transportation resulting from colder fourth-quarter temperatures and expanded usage for regional power generation. As of December 31, 2000, approximately 77% of Questar Pipeline's transportation system was reserved by firm-transportation customers under contracts with varying terms and lengths. Questar Gas has reserved transportation capacity from Questar Pipeline of approximately 828,000 dth per day, representing 69% of the total reserved daily-transportation capacity at December 31, 2000. This contract, which accounts for 78% of the demand charges collected by Questar Pipeline, extends through June 2002. 8 Revenues from storage operations were unchanged in 2000 when compared with 1999 after increasing 3% in 1999. Questar Pipeline's primary storage facility at Clay Basin in eastern Utah was enlarged in May 1998. The storage facility is 100% subscribed under long-term contracts. Most of those contractual volumes have remaining terms of at least nine years. Questar Gas has contracted for 26% of firm-storage capacity for at least seven years. OPERATING EXPENSES Operating and maintenance expense climbed 14% in 2000 compared with 1999. A full year of expenses associated with a gas-processing plant added $2 million of expense and legal costs in a case involving the TransColorado pipeline added $1.8 million. The estimated useful life of the carbon-dioxide removal plant was increased from 10 to 20 years resulting in a $1.3 million reduction of depreciation expense in 2000. Because processing fees are determined on a cost-of-service basis, the lower depreciation expense resulted in a $1.3 million refund to Questar Gas, the primary customer of processing services. Depreciation expense increased 20% in 1999 resulting from capital investment in facilities and information-technology systems. TRANSCOLORADO CASE Questar TransColorado Inc. (QTC), a subsidiary of Questar Pipeline, and KN TransColorado, Inc., (KNTC), a subsidiary of Kinder Morgan, are partners in the TransColorado Gas Transmission Company (TransColorado). The partners are involved in a complex lawsuit that is pending in a state district court in Colorado. At the center of the lawsuit is the validity of a contractual right claimed by QTC to put its 50% interest in TransColorado to KNTC during the 12-month period beginning March 31, 2001. QTC and KNTC entered a standstill agreement regarding various issues in the litigation. QTC provided notice to KNTC that it elected to put its interest in TransColorado as of March 31, 2001, were it not for the provisions of the standstill agreement. Questar Pipeline recorded a $49.7 million pretax write-down of its investment in the TransColorado partnership in 1999. QTC share of TransColorado's operating losses ranged from $.3 million to $1.2 million per month. CORPORATE AND OTHER OPERATIONS - This business segment is responsible for information-technology and communications services and corporate administration.
YEAR ENDED DECEMBER 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) OPERATING INCOME Revenues $73,409 $57,679 $47,907 Operating expenses Cost of products sold 24,640 9,651 1,515 Operating and maintenance 33,506 37,516 37,113 Depreciation and amortization 7,590 5,953 6,575 Other taxes 1,073 1,071 1,019 ---------------------------------------- Total operating expenses 66,809 54,191 46,222 ---------------------------------------- Operating income $6,600 $3,488 $1,685 ========================================
REVENUES Revenues increased 27% because of the acquisitions of Consonus of Oregon at mid-year 2000 and two computer-networking businesses in the second half of 1999. Questar InfoComm is the majority owner of Consonus. Consonus is an e-commerce business that combines Internet services and network support in facilities designed to withstand many of the effects of natural disasters. The gross 9 margin on products and services sold amounted to $8.3 million, $2.6 million and $2 million in 2000, 1999 and 1998, respectively. OPERATING EXPENSES Operating and maintenance expenses were 11% lower in 2000 when compared with 1999. The impact of adding businesses was partially offset by the effect of an early retirement program in 1999. A $2.9 million charge associated with an early retirement program was recorded in 1999 when 50 employees elected to retire. The workforce reduction resulted in a $2.8 million decrease of operating expenses in 2000. Amortization of goodwill, incurred because of the acquisition of Consonus, amounted to $1.7 million in 2000. CONSOLIDATED OPERATING RESULTS (Restated) REVENUES Consolidated revenues rose 37% in 2000 compared with 1999 as a result of higher energy prices, a 10% increase in gas produced from nonregulated sources and a boost in revenues from e-commerce business. Higher energy prices increased revenues from gas and oil production, energy marketing, natural gas distribution and gas plant processing. Consolidated revenues increased 2% in 1999 compared with 1998 due primarily to increased gas production, higher selling prices for energy and the revenues from electronic commerce services. These increases were largely offset by lower revenues from gas distribution due to lower gas costs collected in rates. COST OF NATURAL GAS AND OTHER PRODUCTS SOLD Higher energy prices were apparent in the cost of natural gas and other products sold. The dominant areas were natural gas purchased for resale to distribution customers and energy purchases in marketing transactions. In addition, the cost of e-commerce services increased in 2000. The cost of natural gas and other products sold was 4% lower in 1999 due to lower gas costs allowed in distribution rates. OPERATING AND MAINTENANCE Operating and maintenance expenses increased by 14% in 2000 when compared with 1999. Through an acquisition of Canadian properties and development drilling, Market Resources increased the number of producing properties. Legal expenses grew in 2000. A major lawsuit involving affiliates of Market Resources was settled in 2000, while a lawsuit involving affiliates of Questar Pipeline began in 2000. Operating and maintenance expenses increased 6% in 1999 compared with 1998 resulting from higher costs of serving a growing number of gas-distribution customers, adding gas and oil producing properties, and the cost of an early retirement program for information-technology employees. Labor costs were about $4.6 million lower in 1999 compared with 1998 as a result of an early retirement program offered to employees of Regulated Services in 1998. Questar Regulated Services initiated an early retirement window program effective October 31, 2000. A total of 262 employees from Questar Gas, Questar Pipeline and Questar Regulated Services elected to retire. The window program is projected to result in pretax labor-cost savings for Regulated Services of $6-8 million yearly. DEPRECIATION, DEPLETION AND AMORTIZATION Depreciation, depletion and amortization (DD&A) increased 8% in 2000 when compared with 1999 as a result of increased gas production and investment in depreciable assets. The average DD&A rate for oil and gas wells was $.78 per thousand cubic feet equivalent (Mcfe) in 2000, up from $.71 per Mcfe in 1999. Software that reached the end of its depreciable life and an increase of the estimated useful life of a processing plant resulted in a $4.1 million reduction of 2000 depreciation expense. DD&A was 11% higher in 1999 as a result of increased gas production and more investment in exploration and 10 production, distribution and transmission facilities. EXPLORATION AND ABANDONMENT AND IMPAIRMENT OF OIL AND GAS PROPERTIES Exploration expense increased 49% in 2000 compared with 1999 primarily as a result of drilling dry exploratory wells. Lower dry hole expense caused a 12% decrease in exploration expense in 1999 compared with 1998. Abandonment and impairment of oil and gas properties in 1998 reflects a write off of assets amounting to $14.7 million as a result of lower energy prices. OTHER TAXES Production and property taxes increased in 2000 because of higher revenues. Lower revenues in prior years caused a decrease of other taxes in 1999. Rising property values caused higher property taxes in 2000. A current-year adjustment of a prior-year tax added $1.4 million to expense in 2000. INTEREST AND OTHER INCOME Gain from selling securities of other companies is a significant part of interest and other income. However, the level of securities sales dropped in 2000 because of the general decline in market value of technology companies. These sales generated a pretax gain of $26.5 million ($16.3 million after tax) in 2000 and a pretax gain of $60.7 million ($36.9 million after tax) in 1999.
YEAR ENDED DECEMBER 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) Gain from sales of securities $26,523 $60,720 $10,474 Interest income and other earnings 8,025 7,523 3,087 Gain (loss) from selling properties (1,784) 6,242 142 Allowance for borrowed funds used during construction 4,476 2,017 1,426 Return earned on working-gas inventory 2,223 2,198 1,892 ---------------------------------------- Interest and other income $39,463 $78,700 $17,021 ========================================
OPERATIONS OF UNCONSOLIDATED AFFILIATES Higher energy prices and not repeating TransColorado's operating losses resulted in earnings in 2000 as opposed to losses the year before. This income-statement line item included a $49.7 million write-down of investment in the TransColorado partnership and $5.9 million of operating loss, net of AFUDC, from TransColorado in 1999. DEBT EXPENSE Interest expense increased due to higher short- and long-term borrowing and to higher interest rates in 2000. INCOME TAXES The effective combined federal, state and foreign income tax rate was 34.4% in 2000, 32.5% in 1999 and 28.8% in 1998. Income tax rates were below the combined statutory rate of about 38% primarily due to nonconventional fuel credits, which amounted to $6.5 million in 2000, $7.2 million in 1999 and $8 million in 1998. In addition, a Colorado state income tax credit derived from conducting business in a designated enterprise zone reduced state income taxes by $3.2 million in 2000. 11 LIQUIDITY AND CAPITAL RESOURCES Operating Activities (Restated) YEAR ENDED DECEMBER 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) Net income $149,477 $96,852 $89,310 Adjustments to net income 173,428 135,981 118,928 Changes in operating assets and liabilities (70,838) (25,502) 69,767 ---------------------------------------- Net cash provided from operating activities $252,067 $207,331 $278,005 ========================================
Net cash provided from operating activities increased 22% in 2000 when compared with 1999 due primarily to a 54% increase in net income. Changes in operating assets and liabilities resulted in a decrease of cash flow due to the timing differences associated with the effect of higher energy prices on accounts receivable and the purchased-gas adjustments. This was partially offset by the change in accounts payable. Interest bearing deposits with energy brokers, included in accounts receivable, increased significantly in 2000. Net cash provided from operating activities decreased 25% in 1999 compared with 1998 as a result of disbursements on accounts payable. The balance in payables was higher at the end of 1998 due to construction projects completed in 1999. The write-downs of investments in partnership and oil and gas properties were noncash expenses. Investing Activities (Restated) Capital expenditures amounted to $315.1 million in 2000 and $262 million in 1999. Capital spending in 2001 is expected to range between $354 million and $563 million. The upper spending level is contingent upon several key projects going forward. A 75-mile pipeline planned for central Utah is awaiting final environmental approval. If approval is received in 2001 and the pipeline is constructed, Questar Pipeline could spend an additional $74 million. Another major pipeline project, Questar Southern Trails Pipeline could begin construction in 2001 pending final right of way agreements. This would further increase capital spending by $45 million. The development of Questar's e-commerce business is dependent upon the level of outside venture capital invested.
YEAR ENDED DECEMBER 31, 2001 Forecast 2000 1999 ---------------------------------------- (IN THOUSANDS) Questar Market Resources Exploratory drilling $2,500 $446 $1,173 Development drilling 76,000 97,361 64,642 Other exploration 2,800 342 13,808 Reserve acquisitions 32,000 65,130 3,704 Production 5,100 8,382 8,746 Gathering and processing 28,000 3,330 12,705 Electric generation 25,000 Storage 7,100 11,513 4,108 General 1,500 855 19,362 ---------------------------------------- 180,000 187,359 128,248
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YEAR ENDED DECEMBER 31, 2001 Forecast 2000 1999 ---------------------------------------- (IN THOUSANDS) Questar Regulated Services Natural gas distribution Distribution system and customer additions 49,900 49,454 50,077 General 17,800 16,313 18,370 ---------------------------------------- 67,700 65,767 68,447 Natural gas transmission Transmission system 20,700 15,312 11,936 Storage 11,900 333 1,571 Partnerships 7,900 9,024 14,414 Southern Trails Pipeline 13,975 14,639 Processing plant 250 2,912 General 6,600 4,141 4,952 ---------------------------------------- 47,100 43,035 50,424 ---------------------------------------- Other 2,100 1,167 1,385 ---------------------------------------- Total Questar Regulated Services 116,900 109,969 120,256 Corporate and other operations Electronic commerce 49,900 12,878 4,296 Communications and technology 3,100 1,317 3,472 General 3,600 3,619 5,711 ---------------------------------------- 56,600 17,814 13,479 ---------------------------------------- $353,500 $315,142 $261,983 ========================================
QUESTAR MARKET RESOURCES Capital expenditures in 2000 primarily reflected exploration for and development of gas and oil reserves and a purchase of a Canadian company, which added 61 Bcfe of proved reserves. Market Resources participated in drilling 316 wells (94 net wells) in 2000 that resulted in 223 gas wells, 18 oil wells, 21 dry holes and 54 wells in progress at year end. The success rate was 92%. QUESTAR REGULATED SERVICES - NATURAL GAS DISTRIBUTION The distribution system was extended by 964 miles of main, feeder and service lines to accommodate the addition of 18,312 customers. QUESTAR REGULATED SERVICES - NATURAL GAS TRANSMISSION Capital spending focused on expansion of the gas transmission network, conversion of a crude-oil pipeline to transport gas into Southern California and the acquisition of an additional 18% interest in a pipeline partnership. CORPORATE AND OTHER OPERATIONS Capital expenditures included acquiring e-commerce operations and developing information- technology facilities. 13 Financing Activities Cash flow generated from operations plus proceeds from the sales of securities and release of cash previously held in escrow were used to fund capital expenditures, reduce short- and long-term borrowings, repurchase shares of Questar common stock and pay dividends to holders of common stock. Proceeds from a 1999 sale of nonstrategic gas and oil properties were placed in an escrow account pending possible reinvestment in other producing properties. In April 1999, the Company announced plans to repurchase up to $50 million of its shares over the next two years. From April 1999 through August 2000, the Company acquired 3.2 million shares for $51.4 million, with about half of those purchases occurring in 2000. The Company used part of the $121.9 million in proceeds from its 1999 and 2000 sales of Nextel and other securities to fund those stock repurchases. Short-term borrowings amounted to $181.1 million of commercial paper and $28 million of bank loans at December 31, 2000. A year earlier, short-term debt consisted of $128.4 million of commercial paper and $15.7 million of bank loans. The weighted average interest rate on balances at December 31 was 6.68% in 2000 and 6.14% in 1999. Parent-company commercial-paper borrowings are backed by short-term line-of-credit arrangements and rated P1 and A1 by Moody's and Standard and Poor's, respectively. In the third quarter of 2000, Market Resources initiated an unrated commercial-paper program with a $100 million capacity. Commercial-paper borrowings are limited to and supported by available capacity on Market Resources' existing revolving credit facility. Market Resources had a commercial-paper balance of $12.5 million that was included in the total $181.1 million balance at December 31, 2000. On March 6, 2001, Market Resources issued in a public offering $150 million of 7.5% notes due 2011. Market Resources applied the proceeds of the debt offering to repay a portion of its outstanding floating-rate debt. In 1999, Market Resources entered into a long-term revolving-credit facility with a syndication of banks. The credit facility has a $300 million capacity. Market Resources had borrowed $244.4 million as of December 31, 2000 under this arrangement. On February 27, 2001, Questar Pipeline gave notice that it will redeem $30 million of its 9 7/8% debentures on March 30, 2001. The redemption price is equal to 104.67% of the principal amount plus interest from December 1, 2000. The Company typically has negative net working capital at December 31 because of short-term borrowings. These borrowings are seasonal and generally peak at year end because of cold-weather gas purchases. Negative working capital at year end was exacerbated by rising energy prices experienced in the second half of 2000 and extending into the first quarter of 2001. Questar's consolidated capital structure consisted of 42% long-term debt and 58% common shareholders' equity at December 31, 2000. Moody's and Standard and Poor's have rated the long-term debt of Questar Gas and Questar Pipeline A1 and A+, respectively. Questar Market Resources' debt rating is BBB+ by Standard and Poor's and Baa2 by Moody's. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Questar's primary market-risk exposures arise from commodity-price changes for natural gas, oil and other hydrocarbons and changes in long-term interest rates. The Company has an investment in a foreign operation that may subject it to exchange-rate risk. Market Resources also has reserved 14 pipeline capacity for which it is obligated to pay $3 million annually for the next six years, regardless of whether it is able to market the capacity to others. HEDGING POLICY The Company has established policies and procedures for managing market risks through the use of commodity-based derivative arrangements. A primary objective of these hedging transactions is to protect the Company's commodity sales from adverse changes in energy prices. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Board of Directors. Additionally, under the terms of the Market Resources' revolving credit facility, not more than 75% of Market Resources' production quantities can be committed to hedging arrangements. The Company does not enter into derivative arrangements for speculative purposes. ENERGY-PRICE RISK MANAGEMENT Energy-price risk is a function of changes in commodity prices as supply and demand fluctuate. Market Resources bears a majority of the risk associated with changes in commodity prices. The Company uses hedge arrangements in the normal course of business to limit the risk of adverse price movements; however, these same arrangements usually limit future gains from favorable price movements. Market Resources held hedge contracts covering the price exposure for about 50.5 million dth of gas and 1 million barrels of oil at December 31, 2000. A year earlier the contracts covered 72.1 million dth of natural gas and 2.4 million barrels of oil. The hedging contracts exist for a significant share of Questar-owned gas and oil production and for a portion of gas-marketing transactions. The contracts at December 31, 2000, had terms extending through December 2003, with about 91% of those contracts expiring by the end of 2001. The mark-to-market adjustment of gas and oil price-hedging contracts at December 31, 2000 was a negative $98 million and represented a liability owed to counterparties if terminated. A 10% decline in gas and oil prices would decrease the mark-to-market adjustment by $18.1 million; while a 10% increase in prices would increase the mark-to-market adjustment by $18.1 million. The mark-to-market adjustment of gas and oil price-hedging contracts at December 31, 1999 was a negative $6.2 million. A 10% decline in gas and oil prices at that time would have caused a positive mark-to-market adjustment of $16.7 million. Conversely, a 10% increase in prices would have resulted in a $16.3 million negative mark-to-market adjustment. The calculations used energy prices posted on the NYMEX, various "into the pipe" postings and fixed prices for the indicated measurement dates. These sensitivity calculations do not consider changes in the fair value of the corresponding scheduled physical transactions (i.e., the correlation between the index price and the price to be realized for the physical delivery of gas or oil production), which should largely offset the change in value of the hedge contracts. INTEREST-RATE RISK MANAGEMENT The Company owed $714.9 million of long-term debt at December 31, 2000, of which $470.5 million was fixed-rate debt. The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The fair value of Questar's long-term debt amounted to $735.6 million at December 31, 2000. The Company owed $735.4 million of long-term debt at December 31, 1999, of which $470.1 million was fixed-rate debt. The fair value of Questar's long-term debt amounted to $728.3 million at December 31, 1999. The fair-value calculation was based upon quoted market prices and the discounted present value of cash flows using the Company's current borrowing rates. If interest rates declined by 10%, fair value would increase to $758.4 million in 2000 and $753.3 million in 1999. Interest costs paid on variable-rate long-term debt would decrease about $1.7 million. The sensitivity calculations do not represent the cost to retire the debt securities. The book value of variable-rate debt approximates fair value. 15 SECURITIES AVAILABLE FOR SALE Securities available for sale represent equity instruments traded on national exchanges. The value of these investments is subject to day to day market volatility. A 10% change in prices would result in a change in value of $3.3 million in 2000 and $9.5 million in 1999. FOREIGN CURRENCY RISK MANAGEMENT The Company does not hedge the foreign currency exposure of its foreign operation's net assets and long-term debt. Long-term debt held by the foreign operation amounting to $54.4 million (U.S.) is expected to be repaid from future operations of the foreign company. In January 2000, Market Resources purchased 100% of the outstanding common stock plus debt of a Canadian company for $66.4 million (U.S.). Forward-Looking Statements This report includes "forward-looking statements" within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company's future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as "may", "will", "could", "expect", "intend", "project", "estimate", "anticipate", "believe", "forecast", or " "continue" or the negative thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of the Company's expected performance at the time, actual results may vary from management's stated expectations and projections due to a variety of factors. Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include changes in general economic conditions, gas and oil prices and supplies, competition, rate-regulatory issues, regulation of the Wexpro settlement agreement, availability of gas and oil properties for sale or for exploration and other factors beyond the control of the Company. These other factors include the rate of inflation, quoted prices of securities available for sale, the weather and other natural phenomena, the effect of accounting policies issued periodically by accounting standard-setting bodies, and adverse changes in the business or financial condition of the Company. 16 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a)(1)(2) Financial Statements and Financial Statement Schedules. The financial statements identified in the List of Financial Statements are filed as part of this Report. (a)(3) Exhibits. The following is a list of exhibits required to be filed as a part of this Report in Item 14(c).
EXHIBIT NO. DESCRIPTION ----------- ----------- 2.* Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems Corporation, and Universal Resources Corporation. (Exhibit No. (2) to Current Report on Form 8-K dated December 16, 1986.) 3.1.* Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for Quarter ended June 30, 1998.) 3.2.* Bylaws (as amended effective August 14, 2001). (Exhibit No. 3.2. to Form 10-Q Report for Quarter ended September 30, 2001.) 4.1.*(1) Rights Agreement dated as of February 13, 1996, between the Company and Chemical Mellon Shareholder Services L.L.C. pertaining to the Company's Shareholder Rights Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 13, 1996.) 4.2.* Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 8, 2000.) 10.1.* Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Mountain Fuel Supply Company's Form 10-K Annual Report for 1981.) 10.2*.(2) Questar Corporation Annual Management Incentive Plan, as amended and restated effective February 13, 2001. (Exhibit No. 10.2. to Form 10-K Annual Report for 2000.) 10.3.*(2) Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.2. to Form 10-Q Report for Quarter Ended June 30, 1998.) 17 10.4.*(2) Questar Corporation Long-Term Stock Incentive Plan, as amended and restated effective March 1, 2001. (Exhibit No. 10.4. to Form 10-K Annual Report for 2000.) 10.5.*(2) Questar Corporation Executive Severance Compensation Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.3. to Form 10-Q Report for Quarter Ended June 30, 1998.) 10.6.*(2) Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective October 26, 2000. (Exhibit No. 10.6. to Form 10-K Annual Report for 2000.) 10.7.*(2) Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective June 1, 1998. (Exhibit No. 10.6. to Form 10-Q Report for Quarter Ended June 30, 1998.) 10.8.*(2) Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998.) 10.9.*(2) Form of Individual Indemnification Agreement dated February 9, 1993 between Questar Corporation and Directors. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992.) 10.10.*(2) Questar Corporation Deferred Share Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.7. to Form 10-Q Report for Quarter Ended June 30, 1998.) 10.11.*(2) Questar Corporation Deferred Compensation Plan, as amended and restated effective October 26, 2000. (Exhibit No. 10.11. to Form 10-K Annual Report for 2000.) 10.12.*(2) Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30, 1996.) 10.13.*(2) Questar Corporation Deferred Share Make-Up Plan. (Exhibit No. 10.8. to Form 10-Q Report for Quarter Ended June 30, 1998.) 10.14.*(2) Questar Corporation Special Situation Retirement Plan. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June 30, 1998.) 10.15.* Employment Agreement between Questar Corporation and Keith O. Rattie effective February 1, 2001. (Filed as Exhibit No. 10.15. to Form 10-K Annual 18 Report for 2000.) 21. Subsidiary Information. (Filed as Exhibit No. 21. to Form 10-K Report for 2000.) 23.01 Consent of Independent Auditors. 24. Power of Attorney. (Filed as Exhibit No. 24. to Form 10-K Report for 2000.) 99.1. Undertakings for Registration Statements on Form S-3 (No. 33-48168) and on Form S-8 (Nos. 33-4436, 33-15149, 33-40800, 33-40801, 33-48169, 333-04913, and 333-04951). (Filed as Exhibit No. 99.1. to Form 10-K Report for 2000.)
----------------------- *Exhibits so marked have been filed with the Securities and Exchange Commission as part of the indicated filing and are incorporated herein by reference. (1)The name of the Rights Agent has been changed to USBank National Association. (2)Exhibit so marked is management contract or compensation plan or arrangement. (b) The Company did not file any Current Reports on Form 8-K during the last quarter of 2000. 19 ANNUAL REPORT ON FORM 10-K/A ITEM 8, ITEM 14(a) (1) and (2), and (d) LIST OF FINANCIAL STATEMENTS FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA YEAR ENDED DECEMBER 31, 2000 QUESTAR CORPORATION SALT LAKE CITY, UTAH FORM 10-K/A -- ITEM 14 (a) (1) AND (2) QUESTAR CORPORATION AND SUBSIDIARIES LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES The following financial statements of Questar Corporation and subsidiaries are included in Item 8: Consolidated statements of income--Years ended December 31, 2000, 1999 and 1998 Consolidated balance sheets--December 31, 2000 and 1999 Consolidated statements of common shareholder's equity--Years ended December 31, 2000, 1999 and 1998 Consolidated statements of cash flows--Years ended December 31, 2000, 1999 and 1998 Notes to consolidated financial statements Financial statement schedules, for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission, are not required under the related instructions or are inapplicable, and therefore have been omitted. 20 Report of Independent Auditors Board of Directors Questar Corporation We have audited the accompanying consolidated balance sheets of Questar Corporation as of December 31, 2000 and 1999, and the related consolidated statements of income, common shareholders' equity, and cash flows for each of the three years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Questar Corporation at December 31, 2000 and 1999, and the consolidated results of its operations and its cash flows for the three years then ended in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 to the consolidated financial statements, in 2000 the Company changed its method of accounting for oil and gas operations. /s/ Ernst & Young, LLP Salt Lake City, Utah March 6, 2001 except for Note 1, as to which the date is November 30, 2001 and Note 2, as to which the date is July 31, 2001 QUESTAR CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Restated)
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES $1,266,153 $ 924,219 $ 906,256 OPERATING EXPENSES Cost of natural gas and other products sold 562,229 352,554 367,932 Operating and maintenance 251,477 221,082 208,191 Depreciation, depletion and amortization 142,491 132,164 118,745 Exploration 7,917 5,321 6,069 Abandonment and impairment of oil and gas properties 3,418 7,535 15,137 Other taxes 50,654 32,724 36,792 ------------------------------------------ TOTAL OPERATING EXPENSES 1,018,186 751,380 752,866 ------------------------------------------ OPERATING INCOME 247,967 172,839 153,390 INTEREST AND OTHER INCOME 39,463 78,700 17,021 OPERATIONS OF UNCONSOLIDATED AFFILIATES Income (loss) 3,996 (4,356) 2,917 Write-down of investment in partnership (49,700) ------------------------------------------ 3,996 (54,056) 2,917 DEBT EXPENSE (63,510) (53,944) (47,971) ------------------------------------------ INCOME BEFORE INCOME TAXES 227,916 143,539 125,357 INCOME TAXES 78,439 46,687 36,047 ------------------------------------------ NET INCOME $ 149,477 $ 96,852 $ 89,310 ========================================== EARNINGS PER COMMON SHARE Basic $ 1.86 $ 1.17 $ 1.08 Diluted $ 1.85 $ 1.17 $ 1.08 Average common shares outstanding Basic 80,412 82,547 82,365 Diluted 80,915 82,676 82,817
See notes to consolidated financial statements 21 QUESTAR CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Restated)
ASSETS DECEMBER 31, 2000 1999 ---------------------------- (IN THOUSANDS) CURRENT ASSETS Cash and cash equivalents $ 9,416 $ 8,291 Accounts receivable 277,331 143,987 Unbilled gas accounts receivable 45,293 37,287 Federal income taxes recoverable 9,694 Inventories, at lower of average cost or market Gas and oil storage 30,062 27,360 Materials and supplies 10,472 10,254 Purchased-gas adjustments 35,565 432 Prepaid expenses and other 9,189 11,249 ---------------------------- TOTAL CURRENT ASSETS 427,022 238,860 PROPERTY, PLANT AND EQUIPMENT Questar Market Resources 1,400,159 1,225,321 Questar Regulated Services - gas distribution 1,067,362 1,013,599 Questar Regulated Services - gas transmission 731,246 698,236 Questar Regulated Services - other 5,764 4,493 Corporate and other operations 82,603 72,769 ---------------------------- 3,287,134 3,014,418 LESS ALLOWANCES FOR DEPRECIATION AND AMORTIZATION Questar Market Resources 662,923 587,603 Questar Regulated Services - gas distribution 447,496 421,111 Questar Regulated Services - gas transmission 243,006 228,784 Questar Regulated Services - other 3,073 2,542 Corporate and other operations 43,661 40,727 ---------------------------- 1,400,159 1,280,767 ---------------------------- NET PROPERTY, PLANT AND EQUIPMENT 1,886,975 1,733,651 SECURITIES AVAILABLE FOR SALE 33,019 94,945 INVESTMENT IN UNCONSOLIDATED AFFILIATES 34,505 25,269 OTHER ASSETS Regulatory assets 37,646 26,025 Goodwill, net 20,514 7,750 Cash held in escrow 5,387 36,727 Other noncurrent assets 26,959 21,507 ---------------------------- TOTAL OTHER ASSETS 90,506 92,009 ---------------------------- $2,472,027 $2,184,734 ============================
22 LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, 2000 1999 ---------------------------- (IN THOUSANDS) CURRENT LIABILITIES Short-term debt $ 209,139 $ 144,115 Accounts payable and accrued expenses Accounts and other payables 273,892 132,473 Federal income taxes 17,374 Other taxes 30,718 22,315 Deferred income taxes 13,515 164 Interest 7,300 7,518 ---------------------------- Total accounts payable and accrued expenses 325,425 179,844 ---------------------------- TOTAL CURRENT LIABILITIES 534,564 323,959 LONG-TERM DEBT 714,537 735,043 DEFERRED INCOME TAXES 213,136 189,014 DEFERRED INVESTMENT TAX CREDITS 5,262 5,648 OTHER LONG-TERM LIABILITIES 33,680 29,944 MINORITY INTEREST 18,216 6,610 COMMITMENTS AND CONTINGENCIES - Note 7 COMMON SHAREHOLDERS' EQUITY Common stock - without par value; 350,000,000 shares authorized; 80,818,274 outstanding at December 31, 2000 and 81,418,853 outstanding at December 31, 1999 268,630 278,437 Retained earnings 671,415 577,022 Cumulative other comprehensive income 12,587 39,057 ---------------------------- TOTAL COMMON SHAREHOLDERS' EQUITY 952,632 894,516 ---------------------------- $2,472,027 $2,184,734 ============================
See notes to consolidated financial statements 23 QUESTAR CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Restated)
CUMULATIVE COMMON STOCK NOTE OTHER COMPRE- -------------------------- RETAINED RECEIVABLE COMPREHENSIVE HENSIVE SHARES AMOUNT EARNINGS FROM ESOP INCOME INCOME ---------------------------------------------------------------------------------- (DOLLARS IN THOUSANDS) BALANCES AT JANUARY 1, 1998 82,142,084 $ 291,322 $ 499,754 $ (10,173) $ 22,955 Issuance of common stock 521,879 8,243 Purchase of common stock (31,885) (677) 1998 net income 89,310 $ 89,310 Payment of common stock dividends of $.6525 per share (53,747) Income tax benefit of dividends paid to ESOP 143 Collection of note receivable from ESOP 6,218 Other comprehensive income Unrealized loss on securities available for sale, net of income taxes of $3,086 (4,992) (4,992) Foreign currency translation adjustment, net of income taxes of $214 396 396 ----------------------------------------------------------------------------------- BALANCES AT DECEMBER 31, 1998 82,632,078 298,888 535,460 (3,955) 18,359 $ 84,714 ============ Issuance of common stock 488,302 8,124 Purchase of common stock (1,701,527) (28,575) 1999 net income 96,852 $ 96,852 Payment of common stock dividends of $.67 per share (55,328) Income tax benefit of dividends paid to ESOP 38 Collection of note receivable from ESOP 3,955 Other comprehensive income Unrealized gain on securities available for sale, net of income taxes of $13,193 21,303 21,303 Foreign currency translation adjustment, net of income taxes of $327 (605) (605) --------------------------------------------------------------------------------- BALANCES AT DECEMBER 31, 1999 81,418,853 278,437 577,022 - 39,057 $117,550 ============ Issuance of common stock 958,232 11,764 Purchase of common stock (1,558,811) (25,543) 2000 net income 149,477 $149,477 Payment of common stock dividends of $.685 per share (55,084) Income tax benefit associated with exercise of nonqualified options and premature dispositions 3,972 Other comprehensive income Unrealized loss on securities available for sale, net of income taxes of $16,767 (25,453) (25,453) Foreign currency translation adjustment, net of income taxes of $949 (1,017) (1,017) --------------------------------------------------------------------------------- BALANCES AT DECEMBER 31, 2000 80,818,274 $ 268,630 $ 671,415 $ - $ 12,587 - $123,007 =================================================================================
See notes to consolidated financial statements 24 QUESTAR CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Restated)
YEAR ENDED DECEMBER 31, 2000 1999 1998 ---------------------------------------- OPERATING ACTIVITIES (IN THOUSANDS) Net income $ 149,477 $ 96,852 $ 89,310 Adjustments to reconcile net income to net cash provided from operating activities Depreciation, depletion and amortization 148,293 139,124 122,254 Deferred income taxes and investment tax credits 47,355 (1,087) (7,487) Write-down of investment in partnership 49,700 Abandonment and impairment of oil and gas properties 3,418 7,535 15,137 (Income) loss from unconsolidated affiliates, net of cash distributions (899) 7,671 (360) Gain from sales of properties and securities (24,739) (66,962) (10,616) ---------------------------------------- 322,905 232,833 208,238 Changes in operating assets and liabilities Accounts receivable (136,700) (1,004) 8,822 Inventories (2,892) 252 (7,238) Prepaid expenses and other 2,077 615 2,556 Accounts payable and accrued expenses 144,190 (41,549) 38,207 Federal income taxes (27,068) 8,684 2,251 Purchased-gas adjustments (35,133) 1,635 35,184 Other assets (17,144) 3,446 (7,664) Other liabilities 1,832 2,419 (2,351) ---------------------------------------- NET CASH PROVIDED FROM OPERATING ACTIVITIES 252,067 207,331 278,005 INVESTING ACTIVITIES Capital expenditures Purchase of property, plant and equipment (305,818) (215,814) (421,810) Other investments (9,324) (46,169) (33,667) ---------------------------------------- Total capital expenditures (315,142) (261,983) (455,477) Proceeds from disposition of property, plant and equipment 2,726 45,721 45,613 Proceeds from sales of securities 46,814 75,126 6,759 ---------------------------------------- NET CASH USED IN INVESTING ACTIVITIES (265,602) (141,136) (403,105) FINANCING ACTIVITIES Issuance of common stock 15,736 8,124 8,243 Purchase of Questar common stock (25,543) (28,575) (677) Issuance of long-term debt 61,725 317,000 152,743 Repayment of long-term debt (80,075) (206,996) (77,198) Increase (decrease) in short-term loans 64,581 (76,985) 89,900 Cash held in escrow 31,340 (36,727) Other financing 2,955 3,993 6,361 Payment of dividends (55,084) (55,328) (53,747) ---------------------------------------- NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES 15,635 (75,494) 125,625 Foreign currency translation adjustment (975) 101 (307) ---------------------------------------- CHANGE IN CASH AND CASH EQUIVALENTS 1,125 (9,198) 218 BEGINNING CASH AND CASH EQUIVALENTS 8,291 17,489 17,271 ---------------------------------------- ENDING CASH AND CASH EQUIVALENTS $ 9,416 $ 8,291 $ 17,489 ========================================
See notes to consolidated financial statements 25 QUESTAR CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 - Summary of Accounting Policies PRINCIPLES OF CONSOLIDATION: The consolidated financial statements contain the accounts of Questar Corporation and subsidiaries (Questar or the Company). Questar is a diversified natural gas company with two principal lines of business: nonregulated and regulated. The Company's nonregulated activities of gas and oil exploration and production, gas gathering and processing, and energy marketing are conducted by Questar Market Resources, Inc. and subsidiaries (Market Resources). The Company's regulated activities of natural gas distribution, transmission and storage operations are conducted by Questar Regulated Services Co. and subsidiaries (Regulated Services). Natural gas-distribution activities are conducted by Questar Gas. Questar Pipeline provides natural gas transmission and storage services. Regulated Services also includes Questar Energy Services which conducts retail-energy services. Corporate and other operations include information-technology and telecommunication services and corporate activities. All significant intercompany accounts and transactions have been eliminated in consolidation. INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Questar uses the equity method to account for investments in affiliates in which it does not have control. Principal affiliates and percentage ownership include: Overthrust Pipeline Company (72%), TransColorado Gas Transmission Company (50%), Canyon Creek Compression Company (15%) and Blacks Fork Gas Processing Company (50%). Generally, the Company's investment in these affiliates equals the underlying equity in net assets, except for TransColorado where the investment was written down. The Company experienced an other-than-temporary decline in its partnership investment in TransColorado caused by low volumes resulting from unfavorable regional transportation economics. REGULATION: Questar Gas is regulated by the Public Service Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW). While Questar Gas also serves a small area of southeastern Idaho, the Public Utilities Commission of Idaho has deferred to the PSCU for rate oversight of this area. Questar Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). These regulatory agencies establish rates for the storage, transportation and sale of natural gas. The regulatory agencies also regulate, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment. The financial statements of rate-regulated businesses are presented in accordance with regulatory requirements. Methods of allocating costs to time periods, in order to match revenues and expenses, may differ from those of other businesses because of cost-allocation methods used in establishing rates. USE OF ESTIMATES: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent liabilities reported in the financial statements and accompanying notes. Actual results could differ from those estimates. REVENUE RECOGNITION: Revenues are recognized in the period that services are provided or products are delivered. Questar Gas records gas-distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. Rate-regulated companies periodically collect revenues subject to possible refunds pending final orders from regulatory agencies. These companies establish appropriate reserves for revenues collected subject to refund. The Company's exploration and production operations use the sales method of accounting for gas revenues, whereby revenue is recognized on all gas sold to purchasers. A liability is recorded to the extent that the Company has an imbalance in excess of its share of remaining reserves in an underlying property. The Company's net gas imbalances at December 31, 2000 and 1999 were not significant. PURCHASED-GAS ADJUSTMENTS: Questar Gas accounts for purchased-gas costs in accordance with 26 procedures authorized by the PSCU and PSCW under which purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. CASH AND CASH EQUIVALENTS: Cash equivalents consist principally of repurchase agreements with maturities of three months or less. In almost all cases, the repurchase agreements are highly liquid investments in overnight securities made through commercial bank accounts that result in available funds the next business day. SECURITIES AVAILABLE FOR SALE: The value of securities available for sale approximates fair value at the balance sheet date based on published share prices. Based on market value at the balance sheet date, the Company records unrealized gains or losses, net of income taxes, as a separate component of other comprehensive income in shareholders' equity. Gains or losses resulting from the sale of securities are included in the determination of income as incurred. CHANGE IN METHOD OF ACCOUNTING FOR GAS AND OIL PROPERTIES: On July 1, 2001, Questar elected to change its accounting method for gas and oil properties from the full cost method to the successful efforts method. The change was prompted by an acquisition of a company that uses successful efforts. A subsidiary, Wexpro, has always employed the successful efforts method. Management believes that the successful efforts method is preferable and will more accurately present the results of operations of the Company's exploration, development and production activities, minimizes asset write-downs caused by temporary declines in gas and oil prices and reflects impairment of the carrying value of the Company's gas and oil properties only when there has been an other-than-temporary decline in their fair value. As a result, prior years and interim financial statements have been retroactively restated to reflect this change in accounting method. The effect, net of income taxes, was a reduction of retained earnings recorded retroactively as of December 31, 1995, of $37.6 million. This resulted from a reduction of net property, plant and equipment in the amount of $61.9 million and a reduction of deferred income taxes of $24.3 million. As a result of the change in accounting method, previously reported earnings decreased $7.2 million ($.09 per share) and $2.0 million ($.03 per share) for the years ended December 31, 2000 and 1999, respectively, and increased $9.4 million ($.15 per share) for the year ended December 31, 1998. PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment is stated at cost. The Company uses the successful efforts accounting method for its gas and oil exploration and development activities. OIL AND GAS PROPERTIES Under the successful efforts method of accounting, the Company capitalizes all costs related to property acquisitions, successful exploratory wells, and successful and unsuccessful development wells. Also, the costs of related support equipment and facilities are capitalized. The costs of unsuccessful exploratory wells are expensed when such wells are determined to be nonproductive. Unproved leaseholds costs are capitalized and reviewed periodically for impairment. Costs related to impaired prospects are charged to expense. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs associated with production and general corporate activities are expensed in the period incurred. The Company recognizes gain or loss on the sale of properties on a field basis. Leasehold costs are amortized on the unit-of-production method based on proved reserves on a field basis. All other capitalized costs associated with oil and gas properties are depreciated on the unit-of-production method based on proved developed reserves on a field basis. Costs of future site restoration, dismantlement, and abandonment for producing properties are accrued as part of depreciation, depletion and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit of production rate. COST-OF-SERVICE OIL AND GAS OPERATIONS As ordered by the Public Service Commission of Utah, the successful efforts method of accounting is utilized with respect to costs associated with certain "cost of service" oil and gas properties managed and developed by Wexpro and regulated for ratemaking purposes. Cost of service oil and gas properties are those properties for which the 27 operations and return on investment are regulated by the Wexpro settlement agreement (see Note 10). In accordance with the settlement agreement, production from the gas properties operated by Wexpro is delivered to Questar Gas at Wexpro's cost of providing this service. That cost includes a return on Wexpro's investment. Oil produced from the cost of service properties is sold at market prices. Proceeds are credited, pursuant to the terms of the settlement agreement, allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates. Capitalized costs are amortized on an individual field basis using the unit-of-production method based upon proved developed oil and gas reserves attributable to the field. Costs of future site restoration, dismantlement, and abandonment for producing properties are accrued as part of depreciation and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit of production rate.
2000 1999 --------------------------- (IN THOUSANDS) PROPERTY, PLANT AND EQUIPMENT Oil and gas properties - successful efforts accounting Proved properties (Restated) $ 845,485 $ 717,147 Unproved properties, not being amortized (Restated) 55,608 51,624 Support equipment and facilities 13,179 13,408 --------------------------- 914,272 782,179 Cost-of-service oil and gas properties - successful efforts accounting 348,403 318,451 Gathering, processing and marketing 137,484 124,691 --------------------------- $ 1,400,159 $ 1,225,321 =========================== ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION Oil and gas properties - successful efforts accounting (Restated) $ 411,506 $ 353,399 Cost-of-service oil and gas properties - successful efforts accounting 193,029 180,867 Gathering, processing and marketing 58,388 53,337 --------------------------- $ 662,923 $ 587,603 ===========================
For the remaining Company properties, the provision for depreciation, depletion and amortization is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets. The investment in natural gas distribution, transmission, storage, gathering and processing property, plant and equipment, and is charged to expense using the straight-line method. The costs of gas wells and related production facilities are charged to expense using the unit-of-production method. Average depreciation, depletion and amortization rates used in the 12 months ended December 31 were as follows:
2000 1999 1998 --------------------------------------- Questar Market Resources Oil and gas properties, per Mcf equivalent (Restated) U.S. $ 0.73 $ 0.72 $ 0.74 Canada (in U.S. dollars) 1.12 0.63 0.71 Combined U.S. and Canada 0.78 0.71 0.74 Cost of service oil and gas properties, per Mcfe 0.44 0.42 0.39
28 Average depreciation and amortization rates used were as follows:
2000 1999 1998 --------------------------------------- Questar Regulated Services Natural gas distribution Distribution plant 4.0% 4.2% 4.3% Gas wells, per Mcf $ 0.15 $ 0.15 $ 0.17 Natural gas transmission, processing and storage 3.2% 3.4% 3.2%
SFAS 121 The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" in evaluating impairment of properties. GOODWILL: Goodwill is amortized on the straight-line method principally over 10 years. Goodwill amortization expense was $1.7 million in 2000 and the accumulated amortization balance was $1.8 million at December 31, 2000. CAPITALIZED INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: Questar's regulated subsidiaries capitalize the cost of capital employed during the construction period of plant and equipment in accordance with FERC guidelines. Capitalized financing costs, called allowance for funds used during construction (AFUDC), consist of debt and equity portions. The debt portion of AFUDC is recorded as a reduction of interest expense and the equity portion is recorded in other income. The Company's nonregulated subsidiaries capitalize interest costs during construction of assets when it is applicable. Under provisions of the Wexpro settlement agreement, the Company capitalizes AFUDC on cost-of-service construction projects and records the amount in other income. Debt expense was reduced by $4,224,000 in 2000, $3,035,000 in 1999 and $1,421,000 in 1998. AFUDC included in interest and other income amounted to $4,476,000 in 2000, $2,017,000 in 1999 and $1,426,000 in 1998. REACQUISITION OF DEBT: Gains and losses on the reacquisition of debt by rate-regulated affiliates are deferred and amortized as debt expense over the would-be remaining life of the retired debt or the life of the replacement debt in order to match regulatory treatment. FOREIGN CURRENCY TRANSLATION: The Company conducts gas and oil exploration and production activities in western Canada. The local currency is the functional currency of the Company's foreign operations. Translation from the functional currency to U. S. dollars is performed for balance-sheet accounts using the exchange rate in effect at the balance-sheet date. Revenue and expense accounts are translated using an average exchange rate. Adjustments resulting from such translations are reported as a separate component of other comprehensive income in shareholders' equity. Deferred income taxes have been provided on translation adjustments because the earnings are not considered to be permanently invested. HEDGING POLICY: The Company has established policies and procedures for managing market risks through the use of commodity-based derivative arrangements. A primary objective of these hedging transactions is to protect the Company's commodity sales from adverse changes in energy prices. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Board of Directors. Additionally, under the terms of Market Resources' revolving credit facility, not more than 75% of Market Resources' production quantities can be committed to hedging arrangements. The Company does not enter into derivative arrangements for speculative purposes. ENERGY-PRICE RISK MANAGEMENT: Market Resources enters into swaps, futures contracts or options agreements to hedge exposure to price fluctuations in connection with marketing of the Company's natural gas and oil production, and to secure a known margin for the purchase and resale of gas, oil and electricity in marketing activities. It is expected that there is a high degree of correlation between the changes in market value of such contracts and the market price ultimately received on the hedged physical transactions. The timing of production and of the hedge contracts is closely matched. Hedge prices are established in the areas of Market Resources' production operations. 29 The Company settles most contracts in cash and recognizes the gains and losses on hedge transactions during the same time period as the related physical transactions. Cash flows from the hedge contracts are reported in the same category as cash flows from the hedged assets. Contracts which do not have high correlation with the related physical transactions are marked-to-market and recognized in the current-period income. INTEREST-RATE RISK MANAGEMENT: The Company borrows funds under both fixed and variable interest rate arrangements. Variable-rate agreements expose the Company to market risk related to changes in interest rates. CREDIT RISK: The Company's primary market areas are the Rocky Mountain regions of the United States and Canada and the Midcontinent region of the United States. Exposure to credit risk may be impacted by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from non-performance are unlikely to occur. INCOME TAXES: Questar files income tax reports on a consolidated basis in accordance with the Internal Revenue Code and associated regulations. Questar's subsidiaries account for income taxes on a separate-return basis. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers. Questar Gas and Questar Pipeline have adopted procedures with their regulatory commissions to include under-provided deferred taxes in customer rates on a systematic basis. Questar Gas and Questar Pipeline use the deferral method to account for investment tax credits as required by regulatory commissions. EARNINGS PER SHARE: The Company presents basic and diluted earnings per share (EPS) on the income statement. Basic EPS are computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the accounting period. Diluted EPS includes the potential dilution from exercising stock options, which is the reason for the difference between the number of basic and diluted average shares outstanding. COMPREHENSIVE INCOME: Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income transactions reported in the Consolidated Statement of Shareholders' Equity. Other comprehensive income transactions that currently apply to Questar result from changes in the market value of securities held for sale and changes in holding value resulting from foreign currency translation adjustments. These transactions are not the culmination of the earnings process, but result from periodically adjusting historical balances to fair value. Income is realized when the securities available for sale are sold. Income taxes associated with realized gains from selling securities available for sale, which were included in other comprehensive income in prior years, were $10.2 million in 2000, $23.4 million in 1999 and $1.9 million in 1998. Beginning in 2001, other comprehensive income will include mark-to-market adjustments of the Company's qualified energy derivatives. The balances of cumulative other comprehensive income (loss) for the 12 months ended December 31, were as follows:
2000 1999 ------------------------- (IN THOUSANDS) Unrealized gain on securities $13,832 $39,285 Foreign currency translation adjustment (Restated) (1,245) (228) ------------------------- Cumulative other comprehensive income $12,587 $39,057 =========================
BUSINESS SEGMENTS: Questar's line-of-business disclosures are presented based on the way senior management evaluates the performance of its business segments. Certain intersegment sales include intercompany profit. 30 NEW ACCOUNTING STANDARD: The Company is required to adopt the accounting provisions of Statement of Financial Accounting Standards 133, as amended, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) beginning in January 2001. SFAS 133 addresses the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to carry all derivative instruments in the balance sheet at fair value. The accounting for changes in fair value, which result in gains or losses, of a derivative instrument depends on whether such instrument has been designated and qualifies as part of a hedging relationship and, if so, depends on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair value, cash flows or foreign currencies. If the hedged exposure is a fair-value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of the change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. If the hedged exposure is a cash-flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income in the shareholders' equity section of the balance sheet and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the gain or loss, is reported in earnings immediately. As of January 1, 2001, the Company structured a majority of its energy derivative instruments as cash flow hedges. As a result of adopting SFAS 133 in January 2001, the Company expects to record a liability for derivative instruments of approximately $121 million. The offset to this amount, net of income taxes, will be recorded as a loss in other comprehensive income in the shareholders' equity section of the balance sheet. The fair-value calculation does not consider changes in fair value of the corresponding scheduled physical transactions. The Company has identified a number of contracts that are derivative instruments as defined by SFAS 133, but are specifically excluded from the provisions of SFAS 133 on the basis of normal sales and purchase transactions. These contracts are primarily located in the natural gas distribution and transmission activities. RECLASSIFICATIONS: Certain reclassifications were made to the 1999 and 1998 financial statements to conform with the 2000 presentation. NOTE 2 - SUBSEQUENT EVENT - ACQUISITION Market Resources acquired 100% of the common stock of Shenandoah Energy, Inc. (SEI) on July 31, 2001 for $403 million in cash including assumed debt. SEI was a privately held Denver-based exploration, production, gathering and drilling company. Market Resources obtained an estimated 415 billion cubic feet equivalent of proved oil and gas reserves, gas processing capacity of 100 MMcf per day, 90 miles of gathering lines, 114,000 acres of net undeveloped leasehold acreage and four drilling rigs. SEI operations are located primarily in the Uintah Basin of eastern Utah. The transaction was accounted for as a purchase business combination in accordance with accounting principles generally accepted in the United States. The purchase price in excess of the estimated fair value of the assets was assigned to goodwill. The acquisition was financed through bank borrowings. 31 Note 3 - Debt Questar has short-term line-of-credit arrangements with several banks under which it may borrow up to $220 million. These lines have interest rates generally below the prime interest rate. Commercial paper borrowings are backed by the short-term line-of-credit arrangements. The details of short-term debt are as follows:
DECEMBER 31, 2000 1999 ------------------------------ (In Thousands) Commercial paper with variable interest rates $181,100 $128,379 Bank loans with variable interest rates 28,039 15,736 ------------------------------ $209,139 $144,115 ============================== Weighted average interest rate at December 31 6.68% 6.14%
The details of long-term debt are as follows:
DECEMBER 31, 2000 1999 ------------------------------ (IN THOUSANDS) Questar Market Resources Revolving-credit loan due 2001- 2005 with variable interest rates (7.01% at December 31, 2000) $244,377 $264,894 Questar Regulated Services - Natural gas distribution Medium-term notes 6.85% to 8.43%, due 2007 to 2024 225,000 225,000 Questar Regulated Services - Natural gas transmission Medium-term notes 5.85% to 7.55%, due 2008 to 2019 130,400 130,400 9 3/8% debentures due 2021 85,000 85,000 9 7/8% debentures due 2020 30,000 30,000 Corporate and other 148 155 ------------------------------ Total long-term debt outstanding 714,925 735,449 Less current portion 8 7 Less unamortized debt discount 380 399 ------------------------------ $714,537 $735,043 ==============================
Maturities of long-term debt for the five years following December 31, 2000, in thousands of dollars are as follows: 2001 $8 2002 6,977 2003 16,978 2004 186,980 2005 6,981 Cash paid for interest was $66,833,000 in 2000, $56,019,000 in 1999 and $49,430,000 in 1998. As of December 31, 2000, Questar Pipeline guaranteed $100 million of long-term debt borrowed by TransColorado Gas Transmission Company. The partnership has borrowed $200 million under a three-year revolving-credit arrangement that will expire unless renewed by October 2001. 32 Market Resources revolving-credit loan contains covenants specifying a minimum amount of net equity and a maximum ratio of debt to equity. On March 6, 2001, Market Resources issued in a public offering $150 million of 7.5% notes due 2011. Market Resources applied the proceeds of the debt offering to repay a portion of its outstanding floating-rate debt. On February 27, 2001, Questar Pipeline gave notice that it will redeem $30 million of its 9 7/8% debentures on March 30, 2001. The redemption price is equal to 104.67% of the principal amount plus interest from December 1, 2000. Note 4 - Common Stock Dividend Reinvestment and Stock Purchase Plan: The Dividend Reinvestment and Stock Purchase Plan (Reinvestment Plan) allows parties interested in owning Questar common stock to reinvest dividends or invest additional funds in common stock. The Company can use unissued shares or purchase shares in the open market in order to meet shareholders' purchase demands. The Reinvestment Plan issued total shares of 322,062, 371,985 and 329,794 in 2000, 1999 and 1998, respectively. At December 31, 2000, 1,920,761 shares were reserved for future issuance. Employee Investment Plan: The Employee Investment Plan (Plan) allows eligible employees to purchase shares of Questar Corporation common stock or other investments through payroll deduction. Since January 1, 1999, the Company has matched 80% of employees-pretax purchases up to a maximum of 6%. Prior to that date, the Company matched 75% of employees' eligible contributions. The Company's expense equals its matching contribution. Questar's expense and contribution to the Plan amounted to $5,042,000, $4,713,000 and $4,542,000 for the years ended December 31, 2000, 1999 and 1998, respectively. Stock Plans: The Company has a Long-term Stock Incentive Plan for officers and employees and a Stock Option Plan for nonemployee directors (Stock Plans). The number of shares made available for a given year for options or other stock awards under the Long-term Stock Incentive Plan is 1% of the outstanding shares of common stock on the first day of the calendar year. The current plan was amended March 1, 2011, subject to shareholders approval. The option price equals the market price of the stock on the grant date. Stock options for employees have a 10-year life and vest in four equal annual installments beginning six months after grant date. Nonemployee directors may receive shares of common stock instead of cash in payment for directors fees under a separate plan. At December 31, 2000 there were 90,729 shares available for future issuance under this plan. No compensation expense is recorded for stock options issued to employees or directors because the exercise price equals the market price on the date of issue. If compensation expense had been recorded, it would be based on an estimate of the fair value of stock options granted and would reduce earnings per share by $.03 in 2000 and 1998 and $.02 in 1999. For purposes of the pro-forma expense, the weighted average fair value of the options was amortized over the vesting period. The pro-forma estimates rely upon subjective assumptions and the use of a mathematical model to estimate value, and may not be representative of future results. 33 Transactions involving option shares in the Stock Plans are summarized as follows:
WEIGHTED AVERAGE SHARES PRICE RANGE EXERCISE PRICE -------------------------------------------------- Balance at January 1, 1998 2,940,610 $9.81 -$19.13 $16.22 Granted 857,800 21.38 21.38 Cancelled (77,200) 13.69 - 21.38 17.33 Exercised (437,209) 9.81 - 16.81 14.72 -------------------------------------------------- Balance at December 31, 1998 3,284,001 9.81- 21.38 17.74 -------------------------------------------------- Granted 866,400 17.00 17.00 Cancelled (82,900) 9.81 - 21.38 17.94 Exercised (138,445) 9.81 - 16.81 14.44 -------------------------------------------------- Balance at December 31, 1999 3,929,056 9.81 - 21.38 17.69 -------------------------------------------------- Granted 1,289,050 15.00 15.00 Cancelled (89,254) 13.69 - 21.38 17.19 Exercised (1,301,361) 9.81 - 21.38 15.99 -------------------------------------------------- Balance at December 31, 2000 3,827,491 $9.81 -$21.38 $17.37 ================================================== Exercisable at December 31, 2000 2,464,368 $17.98 Available for future grant at December 31, 2000 1,191,636
The stock options at December 31, 2000 had a weighted average remaining life of 4.6 years. The fair value of the stock options was determined on the grant date using the Black-Scholes option-valuation model. The calculated fair value of options granted and major assumptions used in the model at the date of grant were as follows:
2000 1999 1998 ----------------------------------------- Fair value of options at grant date $3.38 $3.16 $3.94 Risk-free interest rate 6.79% 5.11% 5.56% Expected price volatility 25.1% 20.6% 20.2% Expected dividend yield 4.53% 3.88% 3.09% Expected life in years 7.0 7.2 4.4
In addition to stock options, the Company issued restricted shares to officers and employees as part of its payment of bonuses. Compensation expense is recorded when the bonus is earned. Restricted stock vests in two equal, annual installments beginning one year after grant. Stock is issued at the market price on date of grant. Recipients of restricted stock awards are entitled to full voting rights and receipt of dividends.
2000 1999 1998 ---------------------------------------- Shares of restricted stock awarded 46,053 16,919 7,620 Market price at award date $28.01 $15.00 $17.00
Shareholder Rights: On February 13, 1996, Questar's Board of Directors declared a stock-right dividend for each outstanding share of common stock. The stock rights were issued March 25, 1996. The rights become exercisable if a person, as defined, acquires 15% or more of the Company's common stock or announces an offer for 15% or more of the common stock. Each right initially represents the right to buy one share of the Company's common stock for $87.50. Once any person acquires 15% or more of the Company's common stock, the rights are automatically modified. Each right not owned by the 15% owner becomes exercisable for the number of shares of Questar's stock that have a market value equal to two times the exercise price of the right. This same result occurs if a 15% owner acquires the Company through a reverse merger when Questar and its stock survive. If the Company is involved in a merger or other business combination at any time after the rights become exercisable, rightsholders will be entitled to 34 buy shares of common stock in the acquiring company having a market value equal to twice the exercise price of each right. The rights may be redeemed by the Company at a price of $.005 per right until 10 days after a person acquires 15% ownership of the common stock. The rights expire March 25, 2006. Note 5 - Financial Instruments and Risk Management The carrying value and estimated fair values of the Company's financial instruments were as follows:
DECEMBER 31, 2000 DECEMBER 31, 1999 --------------------------------------------------------- CARRYING ESTIMATED CARRYING ESTIMATED VALUE FAIR VALUE VALUE FAIR VALUE --------------------------------------------------------- (IN THOUSANDS) Financial assets Cash and cash equivalents $9,416 $9,416 $8,291 $8,291 Financial liabilities Short-term loans 209,139 209,139 144,115 144,115 Long-term debt 714,545 735,554 735,050 728,273 Gas and oil price-hedging contracts (98,000) (6,200)
The Company used the following methods and assumptions in estimating fair values: CASH AND CASH EQUIVALENTS AND SHORT-TERM LOANS - the carrying amount approximates fair value; LONG-TERM DEBT - the carrying amount of variable-rate debt approximates fair value. The fair value of fixed-rate debt is based on quoted market prices, and on the discounted present value of cash flows using the Company's current borrowing rates; GAS AND OIL PRICE-HEDGING CONTRACTS - the mark-to-market adjustment of contracts is based on market prices as posted on the NYMEX from the last trading day of the year. The average price of the oil contracts at December 31, 2000, was $18.30 per barrel and was based on the average of fixed amounts in contracts which settle against the NYMEX. All oil contracts relate to Company-owned production where basis adjustments would result in a net to the well price of $17.20 per barrel. The average price of the gas contracts at December 31, 2000 was $3.87 per MMBtu representing the average of contracts with different terms including fixed, various "into the pipe" postings and NYMEX references. Gas-hedging contracts were in place for Market Resources-owned production and gas-marketing transactions. Removing transportation and heat-value adjustments on the hedges of Company-owned gas as of December 31, 2000, would result in a price between $2.90 and $3.15 per Mcf, net back to the well. Fair value is calculated at a point in time and does not represent the amount the Company would pay to retire the debt securities. In the case of gas and oil price-hedging activities, the fair value calculation does not consider the the fair value of the corresponding scheduled physical transactions (i.e., the correlation between the index price and the price to be realized for the physical delivery of gas or oil production). ENERGY-PRICE RISK MANAGEMENT Market Resources held hedge contracts covering the price exposure for about 50.5 million dth of gas and 1 million barrels of oil at December 31, 2000. A year earlier the contracts covered 72.1 million dth of natural gas and 2.4 million barrels of oil. The hedging contracts exist for a significant share of Questar-owned gas and oil production and for a portion of gas-marketing transactions. The contracts at December 31, 2000, had terms extending through December 2003, with about 91% of those contracts expiring by the end of 2001. A primary objective of energy-price hedging is to protect product sales from adverse changes in energy prices. The Company does not enter into hedging contracts for speculative purposes. 35 SECURITIES AVAILABLE FOR SALE Securities available for sale represent equity instruments traded on national exchanges. The value of these investments is subject to day-to-day market volatility. Common shares of Nextel Communications, XO Communications and ParkerVision represented the Company's primary investments. At December 31, 2000, the Company holdings amounted to 803,000 shares of Nextel, 214,000 shares of ParkerVision and 237,000 shares of XO. CREDIT RISK. The Company's primary market areas are the Rocky Mountain regions of the United States and Canada and the Midcontinent region of the United States. Exposure to credit risk may be impacted by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from non-performance are unlikely to occur. Note 6 - Income Taxes (Restated) Details of Questar's income tax expenses and deferred income taxes are provided in the following tables. The components of income taxes were as follows:
YEAR ENDED DECEMBER 31, 2000 1999 1998 -------------------------------------------- (IN THOUSANDS) Federal Current $24,758 $43,326 $39,454 Deferred 47,098 (2,745) (4,094) State Current 4,067 6,602 3,918 Deferred 801 776 505 Deferred investment tax credits (386) (387) (387) Foreign income taxes 2,101 (885) (3,349) -------------------------------------------- $78,439 $46,687 $36,047 ============================================
36 The difference between income tax expense reported and the tax computed by applying the statutory federal income tax rate of 35% to income before income taxes is explained as follows:
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------ (IN THOUSANDS) Income before income taxes $227,916 $143,539 $125,357 ========================================== Federal income taxes at 35% $79,771 $50,239 $43,875 State income taxes, net of federal income tax benefit 3,107 4,789 2,505 Nonconventional fuel credits (6,453) (7,154) (7,953) Investment tax credits utilized (386) (387) (387) Deferred taxes related to regulated assets that were not provided in prior years 921 921 922 Tax benefits from dividends paid to ESOP (398) (840) Foreign income taxes 723 (189) (964) Other 756 (1,134) (1,111) ------------------------------------------ Income tax expense $78,439 $46,687 $36,047 ========================================== Effective income tax rate 34.4% 32.5% 28.8%
Significant components of the Company's deferred income taxes were as follows:
DECEMBER 31, 2000 1999 -------------------------- (IN THOUSANDS) Deferred tax liabilities Property, plant and equipment $227,633 $193,041 Mark-to-market adjustments of securities available for sale 8,568 24,333 Other 9,977 13,557 -------------------------- Total deferred tax liabilities 246,178 230,931 Deferred tax assets Associated with write-down of investment in partnership 11,806 18,706 Alternative minimum tax and nonconventional- fuel-credit carryforwards 3 2,468 Deferred compensation 7,443 4,910 Depletion and ITC carryforwards 1,995 2,140 Other 11,795 13,693 -------------------------- Total deferred tax assets 33,042 41,917 -------------------------- Deferred income taxes - noncurrent $213,136 $189,014 ========================== Deferred income taxes - current Purchased -gas adjustment $13,515 $164 ==========================
Cash paid for income taxes was $54,088,000, $35,244,000 and $35,036,000 in 2000, 1999 and 1998, respectively. 37 Note 7 - Litigation and Commitments BRIDENSTINE VS. KAISER-FRANCIS OIL COMPANY On January 4, 2001, a district court judge in Texas County, Oklahoma, approved the settlement agreement reached by the Questar defendants and Union Pacific Resources Company, predecessor in interest to Questar Exploration & Production (QE&P), as defendants in the Bridenstine case. Under the terms of the settlement, the Company and Union Pacific Resources paid a total of $22.5 million ($16.5 million by the Company) to resolve all of the issues in the litigation. The Questar defendants disputed plaintiffs' claims, but settled the lawsuit to avoid the uncertainty of a jury verdict. Payment of the settlement funds did not have a material adverse effect on the Company's results of operations, financial position, or liquidity. TRANSCOLORADO CASE Questar TransColorado Inc. (QTC) and its partner, KN TransColorado, Inc., (KNTC) in the TransColorado Gas Transmission Company (TransColorado) are involved in a complex lawsuit that is pending in a state district court in Colorado. At the center of the lawsuit is the validity of a contractual right claimed by QTC to put its 50% interest in TransColorado to KNTC during the 12-month period beginning March 31, 2001. KNTC originally filed a lawsuit in June of 2000 alleging that Questar Pipeline and its affiliates breached their fiduciary duties to TransColorado and KNTC by developing a plan to construct and operate a new pipeline that would compete with TransColorado, rendering TransColorado economically unviable. KNTC is seeking damages in excess of $150 million plus punitive damages; a declaratory judgment that KNTC's obligation to purchase QTC's interest in the project be declared void and unforceable; and a dissolution of the partnership under Colorado law. QTC and its affiliates subsequently filed a counterclaim and third-party complaint against KNTC and named affiliates, including Kinder Morgan, Inc., seeking a declaratory judgment that its contractual right to exercise the put is binding and enforceable and damages of at least $185 million. The trial judge denied the motion filed by the Questar defendants to stay the proceedings and remove some issues to be considered by the FERC. The parties have entered into a standstill agreement that preserves the claims made by Questar and by KNTC pending the resolution of the litigation. On December 31, 2000, QTC gave notice of its election to exercise its contractual right to sell its 50% interest in TransColorado to KNTC. The parties have agreed to hire an outside party to operate the TransColorado pipeline during the pending litigation. The trial is scheduled for February of 2002. GRYNBERG LAWSUITS Questar affiliates are named defendants in a lawsuit filed by independent gas producer Jack J. Grynberg under the Federal False Claims Act. This case and the 75 substantially similar cases filed by Grynberg against pipelines and their affiliates have been consolidated for discovery and pre-trial rulings in Wyoming federal district court. The cases involve allegations of industry wide mismeasurement and undervaluation of gas on which royalty payments are due the federal government. The complaint seeks treble damages and imposition of civil penalties. The Wyoming district court judge has not ruled on the defendants' motion to dismiss. Grynberg has filed a case against Questar Pipeline, Questar Energy Trading and Questar Gas Management in Utah state district court, alleging mismeasurement of gas volumes attributable to his working ownership interest in a specified property in southwestern Wyoming. Grynberg alleges breach of contract, negligent misrepresentation, fraud, breach of fiduciary duty, etc. On March 13, 2001, the trial judge granted defendants' motion to dismiss a case by Grynberg. It is too early to estimate the outcome of the other cases filed by Grynberg against Questar affiliates. There are various other legal proceedings against Questar and its subsidiaries. While it is not currently possible to predict or determine the outcomes of these proceedings, it is the opinion of management that the outcomes will not have a materially adverse effect on the Company's results of operations, financial position or liquidity. 38 COMMITMENTS Historically, 45% to 50% of Questar Gas's gas-supply portfolio has been provided from company-owned gas reserves at the cost of service. The remainder of the gas supply has been purchased from various suppliers under agreements with a duration of one year or less and index-based pricing. Generally, at the conclusion of the heating season and after a bid process, new agreements for the upcoming heating season are put into place. Questar Gas bought significant quantities of natural gas under purchase agreements amounting to $184 million, $93 million and $100 million in 2000, 1999 and 1998, respectively. In addition, Questar Gas makes use of various storage arrangements to meet peak-gas demand during certain times of the heating season. Questar Energy Trading has contracted for firm-transportation services with various pipelines to transport 76.2 Mdths per day of gas. The contracts extend for the next six years and have an annual cost of approximately $3 million. Due to market conditions and competition, it is possible that Questar Energy Trading may be unable to sell enough gas to fully utilize the contracted capacity. Questar sold its headquarters building under a sale and lease-back arrangement in November 1998. The operating agreement commits the Company to occupy the building for the next 11 years with an option for renewal. The minimum future payments under the terms of long-term operating leases for the Company's primary office locations, including its headquarters building, for the five years following December 31, 2000, are as follows:
(IN THOUSANDS) 2001 $4,507 2002 4,314 2003 4,155 2004 3,677 2005 3,633 Thereafter 37,121
Total minimum future rental payments have not been reduced for sublease rental receipts of $187,000, and $24,000, which are expected to be received in the years ended December 31, 2001, and 2002, respectively. Total rental expense amounted to $4,402,000 in 2000, $4,321,000 in 1999 and $563,000 in 1998. Sublease rental receipts were $96,000 in 2000 and $94,000 in 1999. Note 8 - Rate Regulation and Other Matters STATE RATE REGULATION On August 11, 2000, the Public Service Commission of Utah (PSCU) issued an order in the general rate case filed by Questar Gas. The PSCU granted $13.5 million in general rate relief and authorized an 11% return on equity. The $13.5 million in general rate relief includes the $7.1 million in interim rate relief that Questar Gas was authorized to collect, subject to refund, effective January 1, 2000. The PSCU's order allows Questar Gas to collect $5 million of carbon-dioxide-processing costs yearly. In February 2000, the Public Service Commission of Wyoming (PSCW) reaffirmed Questar Gas's 11.83% authorized return on equity in a general rate case filing and approved the request for a $377,000 rate reduction. Cost efficiencies and slower population growth in Wyoming compared with Utah, enabled Questar Gas to reduce its rates in Wyoming. The PSCW's rate-ruling also ordered the Company to transfer the recovery of carbon dioxide gas processing costs from gas costs to general rates beginning April 2000. Questar Gas routinely files semi-annual applications with the PSCU and the PSCW requesting permission to reflect annualized gas cost increases or decreases depending on gas prices. These requests for gas cost increases or decreases are passed on to customers on a dollar-for-dollar basis with no markup. 39 On May 31, 2000, Questar Gas filed with the PSCW to reflect annualized gas costs of $11.1 million in rates for Wyoming customers. The filing reflected a $53,000 increase from the previous filing. The PSCW authorized Questar Gas to reflect the request in rates effective July 1, 2000. On June 14, 2000, Questar Gas filed a request with the PSCU to reflect annualized gas costs of $286.6 million in rates for Utah customers effective July 1, 2000. The request slightly decreased rates for residential and commercial customers. However, the PSCU, by an interim order, chose to make no adjustment in rates. Due to the rapidly rising gas prices caused by a high demand for energy, Questar Gas filed an out-of-period pass-on application on September 19, 2000, with the PSCW seeking approval to reflect an increase of annualized gas costs of $2.5 million in rates for Wyoming customers. The PSCW authorized the requested gas-cost increase in rates effective October 1, 2000. On September 20, 2000, Questar Gas filed a special pass-through application with the PSCU requesting permission to reflect annualized gas cost increases of $63.5 million in rates for Utah customers. The PSCU, by interim order, authorized Questar Gas to reflect the increase in rates effective October 1, 2000. As a result of a continuing growing demand for energy and the accompanying pressure on energy prices, Questar Gas filed on December 19, 2000, with the PSCU to reflect a $167.5 million increase of annualized gas cost in rates for Utah customers. The PSCU, by interim order, authorized Questar Gas to reflect the increase in rates effective January 1, 2001. On December 19, 2000, Questar Gas filed an application with the PSCW to increase gas costs in Wyoming rates by $7.1 million. The PSCW authorized the increase in Wyoming gas rates effective January 1, 2001. FEDERAL RATE REGULATION The Federal Energy Regulatory Commission (FERC) issued a final order granting a certificate of public convenience and necessity to Questar's Southern Trails Pipeline. The FERC's July 28, 2000, ruling came after the agency became satisfied that the pipeline was in the public convenience and necessity and could be completed in an environmentally sound manner. The California State Lands Commission has formally certified the Environmental Impact Report for the Southern Trails Pipeline. Questar Pipeline is actively working on right-of-way issues and exploring marketing opportunities to subscribe Southern Trail's pipeline capacity. Questar Pipeline has received a preliminary determination from the FERC to construct a 75-mile natural gas pipeline from the Price area in eastern Utah to a proposed interconnect with Kern River Gas Transmission Co. near Elberta, Utah. A final order is contingent upon completion of an environmental impact statement. The proposed expansion of Questar Pipeline's interstate system will parallel an existing Questar pipeline for 57 miles from Price to Payson, Utah. The $80 million project, referred to as Main Line 104, will be 24 inches in diameter, with a maximum operating pressure of 1,400 pounds per square inch. Note 9 - Employee Benefits Pension Plan: The Company has a defined-benefit pension plan covering the majority of its employees. Benefits are generally based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 pay-period interval during the ten years preceding retirement. The Company's policy is to make contributions to the plan at least sufficient to meet the minimum funding requirements of the Internal Revenue Code. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations. The Company offered early retirement windows to specific groups of employees in 2000, 1999 and 1998. Questar's Regulated Services has offered early retirement windows to eligible employees in 2000 and 1998. In 2000, a total of 276 employees and recipients of long-term disability from Questar Gas, Questar Pipeline and Questar Regulated Services elected to retire effective October 31. The $14.4 million cost of the early retirement window will be amortized over a five-year period in accordance with regulatory treatment. In 1998, Regulated Services offered an early retirement window that was accepted by 178 eligible employees. The $3.1 million cost of the window is being amortized over a five-year period beginning August 1998. 40 Questar InfoComm, which conducts telecommunications and information-technology services, announced an early retirement program effective November 1, 1999. Fifty employees elected to retire and the $2.9 million cost was expensed in 1999. A summary of pension expense is as follows:
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------ (IN THOUSANDS) Service cost $7,354 $8,894 $7,746 Interest cost 18,447 18,814 18,617 Expected return on plan assets (23,782) (24,059) (23,016) Prior service and other costs 1,581 1,365 872 Recognized net actuarial gain (552) Early retirement expenses 1,340 3,744 530 ------------------------------------------ Pension expense $4,388 $8,758 $4,749 ==========================================
Assumptions used to calculate pension expense were as follows:
2000 1999 1998 ------------------------------------------ Discount rate 7.75% 6.75% 6.75% Rate of increase in compensation 5.00% 5.00% 5.00% Long-term return on assets 9.25% 9.25% 8.50%
The status of the pension plan was as follows:
Pension Plan 2000 1999 -------------------------- (IN THOUSANDS) Change in benefit obligation Projected benefit obligation at January 1, $246,958 $252,799 Service cost 7,354 8,894 Interest cost 18,447 18,814 Plan amendments 8,153 2,164 Change in discount rate assumption (42,321) Actuarial loss 34,096 35,264 Benefits paid (11,275) (11,469) Early retirement settlements paid (80,946) (17,187) -------------------------- Projected benefit obligation at December 31, 222,787 246,958 -------------------------- Change in plan assets Fair value of plan assets at January 1, 274,907 264,632 Actual return on plan assets 4,284 32,831 Contributions to the plan 3,000 6,100 Benefits paid (11,275) (11,469) Early retirement settlements paid (80,946) (17,187) -------------------------- Fair value of plan assets at December 31, 189,970 274,907 -------------------------- Plan assets less the projected benefit obligation (32,817) 27,949 Unrecognized net actuarial (gain) loss 3,053 (36,724) Unrecognized prior-service cost 19,138 12,424 Unrecognized transition obligation 67 210 -------------------------- (Current liability) prepaid pension expense ($10,559) $3,859 ==========================
41 Postretirement Benefits Other Than Pensions: Postretirement health-care benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health-care benefits, as determined by an employee's years of service, and limited to 170% of the 1992 contribution. The Company's policy is to fund amounts allowable for tax deduction under the Internal Revenue Code. Plan assets consist of equity securities and corporate and U.S. government debt obligations. The Company is amortizing its transition obligation over a 20-year period, which began in 1992. Regulated Services accounts for approximately 50% of the postretirement benefit costs. The impact of postretirement benefit costs on Questar's future net income will be mitigated by the ability to recover these costs from customers. The regulatory agencies allow Questar Gas and Questar Pipeline to recover future costs if the amounts are funded in external trusts. A summary of the expense of postretirement benefits other than pensions follows:
YEAR ENDED DECEMBER 31, 2000 1999 1998 -------------------------------------------- (IN THOUSANDS) Service cost $823 $1,006 $1,138 Interest cost 4,979 4,545 4,094 Expected return on plan assets (3,241) (2,831) (1,830) Amortization of transition obligation 1,877 1,877 1,878 Amortization of regulatory liability 523 -------------------------------------------- Postretirement-benefit expense $4,438 $5,120 $5,280 ============================================
Assumptions used to calculate postretirement benefit expense were as follows:
2000 1999 1998 ---------------------------------------------- Discount rate 7.75% 6.75% 6.75% Long-term return on assets 9.25% 9.25% 8.50% Health care inflation rate 10.00% 10.50% 11.00% decreasing to decreasing to decreasing to 6.5% by 2008 5.5% by 2010 5.5% by 2010
A 1% increase in the health-care inflation rate would increase the service cost and interest cost by $290,000 and the accumulated postretirement benefit obligation by $3.3 million. A 1% decrease in the health-care inflation rate would decrease the service cost and interest cost by $210,000 and the accumulated postretirement benefit obligation by $2.8 million. The status of the postretirement benefit programs was as follows: Postretirement Benefits Other Than Pensions
2000 1999 --------------------------- (IN THOUSANDS) Change in benefit obligation Projected benefit obligation at January 1, $66,169 $64,245 Service cost 823 1,006 Interest cost 4,979 4,545 Actuarial gain (701) (498) Benefits paid (3,406) (3,129) --------------------------- Projected benefit obligation at December 31, 67,864 66,169 ---------------------------
42
2000 1999 --------------------------- (IN THOUSANDS) Change in plan assets Fair value of plan assets at January 1, 35,302 30,845 Actual return on plan assets 389 3,732 Contributions to the plan 3,017 3,854 Benefits paid (3,406) (3,129) --------------------------- Fair value of plan assets at December 31, 35,302 35,302 --------------------------- Projected benefit obligation in excess of plan assets (32,562) (30,867) Unrecognized transition obligation 22,529 24,406 Unrecognized net gain (2,442) (4,594) --------------------------- Accrued postretirement benefit liability recorded in current liabilities ($12,475) ($11,055) ===========================
Postemployment Benefits: The Company recognizes the net present value of the liability for postemployment benefits, such as long-term disability benefits and health-care and life-insurance costs, when employees become eligible for such benefits. Postemployment benefits are paid to former employees after employment has been terminated but before retirement benefits are paid. The Company accrues both current and future costs. In 2000, 14 former employees of Questar Regulated Services and recipients of postemployment benefits accepted early retirement benefits. Questar's postemployment liability at December 31, 2000, 1999 and 1998 was $1,381,000, $2,347,000 and $2,452,000, respectively. Note 10 - Wexpro Settlement Agreement Wexpro's operations are subject to the terms of the Wexpro settlement agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas's utility operations to share in the results of Wexpro's operations. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the settlement agreement are as follows: a. Wexpro continues to hold and operate all oil-producing properties previously transferred from Questar Gas's nonutility accounts. The oil production from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after-tax rate of return is adjusted annually and is approximately 13.64%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. b. Wexpro conducts developmental oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 18.64%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers. d. Wexpro conducts developmental gas drilling on productive gas properties and bears any costs of dry holes. Natural gas produced from successful drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is approximately 21.64%. e. Wexpro operates natural-gas properties owned by Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after-tax rate of return is approximately 13.64%. 43 Note 11 - Operations by Line of Business (Restated) Following is a summary of operations by line of business for the Year Ended December 31.
QUESTAR REGULATED SERVICES ------------------------------------------------- QUESTAR NATURAL GAS NATURAL GAS OTHER CORPORATE INTERCOMPANY QUESTAR MARKET DISTRIBUTION TRANSMISSION & OTHER TRANSACTIONS CONSOLIDATED RESOURCES OPERATIONS --------------------------------------------------------------------------------------------- (IN THOUSANDS) 2000 Revenues From unaffiliated customers $649,200 $531,988 $42,500 $3,642 $38,823 $1,266,153 From affiliated companies 92,853 4,774 76,576 283 34,586 ($209,072) --------------------------------------------------------------------------------------------- 742,053 536,762 119,076 3,925 73,409 (209,072) 1,266,153 Operating expenses Cost of natural gas and other products sold 369,752 334,193 2,253 24,640 (168,609) 562,229 Operating and maintenance 106,761 101,486 43,761 1,668 33,506 (35,705) 251,477 Exploration 7,917 7,917 Depreciation, depletion and amortization 85,025 34,450 15,391 35 7,590 142,491 Abandonment and impairment of oil and gas properties 3,418 3,418 Other expenses 41,020 10,213 3,071 35 1,073 (4,758) 50,654 --------------------------------------------------------------------------------------------- Total operating expenses 613,893 480,342 62,223 3,991 66,809 (209,072) 1,018,186 --------------------------------------------------------------------------------------------- Operating income (loss) 128,160 56,420 56,853 (66) 6,600 247,967 Interest and other income 8,412 1,673 3,025 1,349 36,926 (11,922) 39,463 Income from unconsol. Affiliates 2,776 1,220 3,996 Debt expense (22,922) (21,041) (17,584) (722) (13,163) 11,922 (63,510) Income tax expense (38,618) (12,889) (13,689) (217) (13,026) (78,439) --------------------------------------------------------------------------------------------- Net income $77,808 $24,163 $29,825 $344 $17,337 $149,477 ============================================================================================= Identifiable assets $960,491 $830,889 $538,408 $19,640 $122,599 $2,472,027 Investment in unconsol. affiliates 15,417 19,088 34,505 Capital expenditures 187,359 65,767 43,035 1,167 17,814 315,142 1999 Revenues From unaffiliated customers $418,603 $447,606 $36,922 $2,260 $18,828 $924,219 From affiliated companies 79,708 2,331 75,238 196 38,851 ($196,324) --------------------------------------------------------------------------------------------- 498,311 449,937 112,160 2,456 57,679 (196,324) 924,219 Operating expenses Cost of natural gas and other products sold 239,201 257,265 774 9,651 (154,337) 352,554 Operating and maintenance 79,719 103,308 38,534 1,700 37,516 (39,695) 221,082 Exploration 5,321 5,321 Depreciation, depletion and amortization 73,028 36,426 16,743 14 5,953 132,164 Abandonment and impairment of oil and gas properties 7,535 7,535 Other expenses 23,808 7,625 2,488 24 1,071 (2,292) 32,724 --------------------------------------------------------------------------------------------- Total operating expenses 428,612 404,624 57,765 2,512 54,191 (196,324) 751,380 --------------------------------------------------------------------------------------------- Operating income (loss) 69,699 45,313 54,395 (56) 3,488 172,839 Interest and other income 8,272 2,980 4,229 1,014 73,406 (11,201) 78,700 Income (loss) from unconsol. affiliates 763 (5,109) (10) (4,356) Write-down of investment in partnership (49,700) (49,700) Debt expense (17,363) (20,062) (17,466) (605) (9,649) 11,201 (53,944) Income tax (expense) credit (17,483) (9,012) 5,260 (102) (25,350) (46,687) --------------------------------------------------------------------------------------------- Net income (loss) $43,888 $19,219 ($8,391) $251 $41,885 $96,852 ============================================================================================= 44 QUESTAR REGULATED SERVICES ------------------------------------------------- QUESTAR NATURAL GAS NATURAL GAS OTHER CORPORATE INTERCOMPANY QUESTAR MARKET DISTRIBUTION TRANSMISSION & OTHER TRANSACTIONS CONSOLIDATED RESOURCES OPERATIONS --------------------------------------------------------------------------------------------- (IN THOUSANDS) Identifiable assets $777,923 $722,290 $517,981 $11,423 $155,117 $2,184,734 Investment in unconsol. affiliates 13,301 11,724 244 25,269 Capital expenditures 128,248 68,447 50,424 1,385 13,479 261,983 1998 Revenues From unaffiliated customers $382,791 $475,754 $37,156 $2,355 $8,200 $906,256 From affiliated companies 75,481 1,069 71,401 99 39,707 ($187,757) --------------------------------------------------------------------------------------------- 458,272 476,823 108,557 2,454 47,907 (187,757) 906,256 Operating expenses Cost of natural gas and other products sold 230,462 281,004 1,249 1,515 (146,298) 367,932 Operating and maintenance 73,460 96,923 38,832 2,269 37,113 (40,406) 208,191 Exploration 6,069 6,069 Depreciation, depletion and amortization 64,965 33,261 13,927 17 6,575 118,745 Abandonment and impairment of oil and gas properties 15,137 15,137 Other expenses 26,041 8,185 2,600 1,019 (1,053) 36,792 --------------------------------------------------------------------------------------------- Total operating expenses 416,134 419,373 55,359 3,535 46,222 (187,757) 752,866 --------------------------------------------------------------------------------------------- Operating income (loss) 42,138 57,450 53,198 (1,081) 1,685 153,390 Interest and other income 2,457 3,566 78 655 22,756 (12,491) 17,021 Income (loss) from unconsolidated affiliates (930) 4,011 (164) 2,917 Debt expense (12,631) (19,792) (14,456) (385) (13,198) 12,491 (47,971) Income tax (expense) credit (4,886) (13,816) (14,940) 339 (2,744) (36,047) --------------------------------------------------------------------------------------------- Net income (loss) $26,148 $27,408 $27,891 ($472) $8,335 $89,310 ============================================================================================= Identifiable assets $728,953 $699,727 $556,226 $8,519 $118,115 $2,111,540 Investment in unconsol. affiliates 3,673 54,712 253 58,638 Capital expenditures 248,676 76,328 114,318 493 15,662 455,477
Questar Market Resources has subsidiaries that conducts gas and oil exploration and production activities in western Canada. Canadian operations reported revenues, measured in U. S. dollars, totaling $38.1 million, $12.3 million and $10.5 million for the 12 months ended December 31, 2000, 1999, and 1998, respectively. Total assets at December 31, stated in U. S. dollars, amounted to $103.9 million, $31.0 million and $30.3 million in 2000, 1999 and 1998, respectively. 45 Note 12 - Quarterly Financial and Stock Price Information (Unaudited) Following is a summary of quarterly financial and stock price data. (Restated)
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER YEAR --------------------------------------------------------------------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2000 Revenues $336,702 $232,542 $245,117 $451,792 $1,266,153 Operating income 78,653 41,240 43,521 84,553 247,967 Net income 48,568 24,155 26,406 50,348 149,477 Basic earnings per common share 0.60 0.30 0.33 0.63 1.86 Diluted earnings per common share 0.60 0.30 0.33 0.62 1.85 Dividends per common share 0.17 0.17 0.17 0.175 0.685 Market price per common share High $19.00 $20.63 $28.00 $31.88 $31.88 Low $13.56 $17.13 $18.88 $26.00 $13.56 Close $18.56 $19.38 $27.81 $30.06 $30.06 Price-earnings ratio on closing price 16.3 Annualized dividend yield on closing price 3.7% 3.5% 2.4% 2.3% 2.3% Market-to-book ratio on closing price 2.55 Average number of common shares traded per day 233 169 237 280 230 1999 Revenues $277,814 $177,858 $183,070 $285,477 $924,219 Operating income 66,691 30,402 27,346 48,400 172,839 Net income 42,926 22,966 15,051 15,909 96,852 Basic earnings per common share 0.52 0.28 0.18 0.19 1.17 Diluted earnings per common share 0.52 0.28 0.18 0.19 1.17 Dividends per common share 0.165 0.165 0.17 0.17 0.67 Market price per common share High $19.38 $19.94 $19.63 $19.13 $19.94 Low $16.13 $15.81 $17.88 $14.75 $14.75 Close $16.94 $19.13 $18.13 $15.00 $15.00 Price-earnings ratio on closing price 12.8 Annualized dividend yield on closing price 3.9% 3.5% 3.8% 4.5% 4.5% Market-to-book ratio on closing price 1.36 Average number of common shares traded per day 201 147 138 179 166 1998 Revenues $300,083 $179,157 $150,282 $276,734 $906,256 Operating income 68,590 25,724 18,604 40,472 153,390 Net income 41,797 16,578 8,492 22,443 89,310 Basic earnings per common share 0.51 0.20 0.10 0.27 1.08 Diluted earnings per common share 0.50 0.20 0.10 0.27 1.08 Dividends per common share 0.1575 0.165 0.165 0.165 0.6525 Market price per common share High $22.28 $22.38 $19.81 $20.38 $22.38 Low $20.19 $18.69 $15.81 $17.38 $15.19 Close $20.78 $19.63 $19.25 $19.38 $19.38 Price-earnings ratio on closing price 17.9 Annualized dividend yield on closing price 3.2% 3.4% 3.4% 3.4% 3.4% Market-to-book ratio on closing price 1.89 Average number of common shares traded per day 171 165 169 188 173
46 Note 13 - Supplemental Oil and Gas Information (Unaudited) THE COMPANY USES THE SUCCESSFUL EFFORTS ACCOUNTING METHOD FOR ITS OIL AND GAS EXPLORATION AND DEVELOPMENT activities. As ordered by the Public Service Commission of Utah, the successful efforts method of accounting is utilized with respect to costs associated with certain cost-of-service oil and gas properties managed and developed by Wexpro and regulated for ratemaking purposes. Cost-of-service oil and gas properties are those properties for which the operations and return on investment are regulated by the Wexpro settlement agreement (See Note 10). Oil and Gas Exploration and Development Activities: The following information is provided with respect to Questar's oil and gas exploration and development activities, located in the United States and Canada. CAPITALIZED COSTS (RESTATED) The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation and amortization follow:
----------------------------------------------------------- AS OF DECEMBER 31, UNITED STATES CANADA TOTAL ----------------------------------------------------------- (IN THOUSANDS) 2000 Proved properties $732,078 $113,407 $845,485 Unproved properties 30,940 24,668 55,608 Support equipment and facilities 12,002 1,177 13,179 ----------------------------------------------------------- 775,020 139,252 914,272 Accumulated depreciation, depletion and amortization 361,401 50,105 411,506 ----------------------------------------------------------- $413,619 $89,147 $502,766 =========================================================== 1999 Proved properties $663,051 $54,096 $717,147 Unproved properties 41,654 9,970 51,624 Support equipment and facilities 12,418 990 13,408 ----------------------------------------------------------- 717,123 65,056 782,179 Accumulated depreciation, depletion and amortization 314,986 38,413 353,399 ----------------------------------------------------------- $402,137 $26,643 $428,780 =========================================================== 1998 Proved properties $656,085 $47,069 $703,154 Unproved properties 34,736 11,478 46,214 Support equipment and facilities 13,949 929 14,878 ----------------------------------------------------------- 704,770 59,476 764,246 Accumulated depreciation, depletion and amortization 284,252 32,849 317,101 ----------------------------------------------------------- $420,518 $26,627 $447,145 ===========================================================
47 COSTS INCURRED (RESTATED) The following costs were incurred in oil and gas exploration and development activities:
--------------------------------------------------- YEAR ENDED DECEMBER 31, UNITED STATES CANADA TOTAL --------------------------------------------------- (IN THOUSANDS) 2000 Property acquisition Unproved $3,054 $14,703 $17,757 Proved 1,202 31,058 32,260 Exploration 6,433 3,664 10,097 Development 64,582 29,478 94,060 --------------------------------------------------- $75,271 $78,903 $154,174 =================================================== 1999 Property acquisition Unproved $12,565 $337 $12,902 Proved 2,367 17 2,384 Exploration 8,402 323 8,725 Development 53,347 3,608 56,955 --------------------------------------------------- $76,681 $4,285 $80,966 =================================================== 1998 Property acquisition Unproved $29,343 $144 $29,487 Proved 126,723 3,131 129,854 Exploration 10,187 2,122 12,309 Development 42,875 4,477 47,352 --------------------------------------------------- $209,128 $9,874 $219,002 ===================================================
RESULTS OF OPERATIONS (RESTATED) Following are the results of operations of Market Resources' oil and gas exploration and development activities, before corporate overhead and interest expenses. In 1998, oil and gas properties were written down due to lower energy prices.
--------------------------------------------------- UNITED STATES CANADA TOTAL --------------------------------------------------- YEAR ENDED DECEMBER 31, 2000 (IN THOUSANDS) Revenues From unaffiliated customers $207,656 $38,072 $245,728 From affiliates 18 18 --------------------------------------------------- Total revenues 207,674 38,072 245,746 --------------------------------------------------- Production expenses 49,116 9,370 58,486 Exploration 5,533 2,442 7,975 Depreciation, depletion and amortization 51,973 13,196 65,169 Abandonment and impairment of oil and gas properties 2,327 1,091 3,418 --------------------------------------------------- Total expenses 108,949 26,099 135,048 --------------------------------------------------- Revenues less expenses 98,725 11,973 110,698 Income taxes - Note A 31,972 5,580 37,552 --------------------------------------------------- Results of operations before corporate overhead and interest expenses $66,753 $6,393 $73,146 =================================================== 48 YEAR ENDED DECEMBER 31, 1999 Revenues $150,159 $12,316 $162,475 --------------------------------------------------- Production expenses 41,948 3,681 45,629 Exploration 4,803 321 5,124 Depreciation, depletion and amortization 51,927 3,550 55,477 Abandonment and impairment of oil and gas properties 5,542 1,993 7,535 --------------------------------------------------- Total expenses 104,220 9,545 113,765 --------------------------------------------------- Revenues less expenses 45,939 2,771 48,710 Income taxes - Note A 12,313 1,233 13,546 --------------------------------------------------- Results of operations before corporate overhead and interest expenses $33,626 $1,538 $35,164 =================================================== YEAR ENDED DECEMBER 31, 1998 Revenues $125,035 $10,474 $135,509 --------------------------------------------------- Production expenses 38,788 3,004 41,792 Exploration 4,434 1,332 5,766 Depreciation, depletion and amortization 45,301 3,302 48,603 Abandonment and impairment of oil and gas properties 10,045 5,092 15,137 --------------------------------------------------- Total expenses 98,568 12,730 111,298 --------------------------------------------------- Revenues less expenses 26,467 (2,256) 24,211 Income taxes - Note A 5,514 (896) 4,618 --------------------------------------------------- Results of operations before corporate overhead and interest expenses $20,953 ($1,360) $19,593 ===================================================
Note A - Income tax expenses has been reduced by nonconventional fuel tax credits of $4,655,000 in 2000, $5,282,000 in 1999 and $5,736,000 in 1998. 49 ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES Estimates of the reserves located in the United States were made by Ryder Scott Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, and Malkewicz Hueni Associates, Inc., independent reservoir engineers. Estimated Canadian reserves were prepared by Gilbert Laustsen Jung Associates Ltd. and Sproule Associates Ltd. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available. The quantities reported below are based on existing economic and operating conditions at December 31. All oil and gas reserves reported were located in the United States and Canada. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.
NATURAL GAS OIL UNITED STATES CANADA TOTAL UNITED STATES CANADA TOTAL --------------------------------------------------------------------------------------------- (MMcf) (MBbls) PROVED RESERVES Balance at January 1, 1998 357,529 21,134 378,663 12,664 2,435 15,099 Revisions of estimates 378 (3,568) (3,190) (3,165) 238 (2,927) Extensions and discoveries 28,598 1,984 30,582 442 261 703 Purchase of reserves in place 129,207 5,110 134,317 3,720 71 3,791 Sale of reserves in place (440) (440) (76) (76) Production (48,584) (2,725) (51,309) (1,936) (404) (2,340) --------------------------------------------------------------------------------------------- Balance at December 31, 1998 466,688 21,935 488,623 11,649 2,601 14,250 Revisions of estimates 4,155 (106) 4,049 4,031 372 4,403 Extensions and discoveries 77,737 1,720 79,457 794 257 1,051 Purchase of reserves in place 17,020 17,020 130 130 Sale of reserves in place (11,984) (11,984) (3,665) (3,665) Production (59,839) (2,873) (62,712) (1,876) (435) (2,311) --------------------------------------------------------------------------------------------- Balance at December 31, 1999 493,777 20,676 514,453 11,063 2,795 13,858 Revisions of estimates 25,662 (7,890) 17,772 221 (64) 157 Extensions and discoveries 123,155 2,511 125,666 1,532 208 1,740 Purchase of reserves in place 846 52,000 52,846 1 1,520 1,521 Sale of reserves in place (1,885) (1,885) (17) 0 (17) Production (61,722) (7,241) (68,963) (1,484) (741) (2,225) --------------------------------------------------------------------------------------------- Balance at December 31, 2000 579,833 60,056 639,889 11,316 3,718 15,034 ============================================================================================= PROVED-DEVELOPED RESERVES Balance at January 1, 1998 300,550 16,670 317,220 10,769 1,851 12,620 Balance at December 31, 1998 411,826 17,835 429,661 10,443 2,281 12,724 Balance at December 31, 1999 412,008 17,076 429,084 9,897 2,565 12,462 Balance at December 31, 2000 434,122 55,623 489,745 9,696 3,077 12,773
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES (RESTATED) Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. 50 The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The usefulness of the standardized measure of future net cash flows is impaired because of the reliance on reserve estimates and production schedules that are inherently imprecise.
YEAR ENDED DECEMBER 31, UNITED STATES CANADA TOTAL ----------------------------------------------- (IN THOUSANDS) 2000 Future cash inflows $5,412,945 $568,771 $5,981,716 Future production costs (955,827) (73,583) (1,029,410) Future development costs (107,355) (2,900) (110,255) Future income tax expenses (1,489,267) (182,537) (1,671,804) ----------------------------------------------- Future net cash flows 2,860,496 309,751 3,170,247 10% annual discount to reflect timing of net cash flows (1,316,114) (136,445) (1,452,559) ----------------------------------------------- Standardized measure of discounted future net cash flows $1,544,382 $173,306 $1,717,688 =============================================== 1999 Future cash inflows $1,332,761 $108,990 $1,441,751 Future production costs (398,591) (28,280) (426,871) Future development costs (61,034) (3,146) (64,180) Future income tax expenses (188,988) (10,353) (199,341) ----------------------------------------------- Future net cash flows 684,148 67,211 751,359 10% annual discount to reflect timing of net cash flows (280,911) (23,652) (304,563) ----------------------------------------------- Standardized measure of discounted future net cash flows $403,237 $43,559 $446,796 =============================================== 1998 Future cash inflows $982,404 $66,885 $1,049,289 Future production costs (320,355) (22,088) (342,443) Future development costs (45,138) (696) (45,834) Future income tax expenses (84,868) (84,868) ----------------------------------------------- Future net cash flows 532,043 44,101 576,144 10% annual discount to reflect timing of net cash flows (212,959) (14,809) (227,768) ----------------------------------------------- Standardized measure of discounted future net cash flows $319,084 $29,292 $348,376 ===============================================
51 The principal sources of change in the standardized measure of discounted future net cash flows were:
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------- (IN THOUSANDS) Beginning balance $446,796 $348,376 $300,994 Sales of oil and gas produced, net of production costs (187,260) (116,846) (93,717) Net changes in prices and production costs 1,637,549 171,392 (53,613) Extensions and discoveries, less related costs 492,398 79,511 24,120 Revisions of quantity estimates 70,155 28,665 (14,399) Purchase of reserves in place 32,260 2,384 129,854 Sale of reserves in place (1,867) (33,043) (540) Accretion of discount 44,680 34,837 30,099 Net change in income taxes (776,276) (61,807) 5,632 Change in production rate (50,077) (8,859) 6,728 Other 9,330 2,186 13,218 ------------------------------------------- Net change 1,270,892 98,420 47,382 ------------------------------------------- Ending balance $1,717,688 $446,796 $348,376 ===========================================
COST-OF-SERVICE ACTIVITIES The following information is provided with respect to cost-of-service oil and gas properties managed and developed by Wexpro and regulated by the Wexpro settlement agreement. Information on the standardized measure of future net cash flows has not been included for cost-of-service activities because the operations of and return on investment for such properties are regulated by the Wexpro settlement agreement. CAPITALIZED COSTS Capitalized costs for cost-of-service oil and gas properties net of the related accumulated depreciation and amortization were as follows:
DECEMBER 31, 2000 1999 1998 ---------------------------------------- (IN THOUSANDS) Wexpro $155,374 $137,584 $129,573 Questar Gas 22,620 25,380 27,739 ---------------------------------------- $177,994 $162,964 $157,312 ========================================
COSTS INCURRED Costs incurred by Wexpro for cost of service oil and gas producing activities were $32,066,000 in 2000, $21,273,000 in 1999 and $26,956,000 in 1998. 52 RESULTS OF OPERATIONS Following are the results of operations of the Company's cost-of-service gas and oil development activities before corporate overhead and interest expenses.
YEAR ENDED DECEMBER 31, 2000 1999 1998 ------------------------------------------- (IN THOUSANDS) Revenues From unaffiliated companies $15,179 $8,844 $10,025 From affiliates - Note A 73,721 62,335 58,581 ------------------------------------------- Total revenues 88,900 71,179 68,606 Production expenses 27,861 18,548 22,439 Depreciation and amortization 13,922 12,665 11,379 ------------------------------------------- Total expenses 41,783 31,213 33,818 ------------------------------------------- Revenues less expenses 47,117 39,966 34,788 Income taxes 16,923 14,602 12,441 ------------------------------------------- Results of operations before corporate overhead and interest expenses $30,194 $25,364 $22,347 ===========================================
Note A - Represents revenues received from Questar Gas pursuant to Wexpro Settlement Agreement. ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES The following estimates were made by the Company's reservoir engineers. No estimates are available for cost of service proved-undeveloped reserves that may exist.
NATURAL GAS OIL ---------------------------- (MMcf) (MBbls) PROVED DEVELOPED RESERVES Balance at January 1, 1998 337,179 3,049 Revisions of estimates 15,017 (46) Extensions and discoveries 25,077 333 Production (37,138) (613) ---------------------------- Balance at December 31, 1998 340,135 2,723 Revisions of estimates 5,699 976 Extensions and discoveries 46,739 213 Production (38,890) (623) ---------------------------- Balance at December 31, 1999 353,683 3,289 Revisions of estimates 16,523 504 Extensions and discoveries 50,351 234 Production (41,546) (579) ---------------------------- Balance at December 31, 2000 379,011 3,448 =============================
53 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the day of January 16, 2002. QUESTAR CORPORATION (Registrant) By /s/ R. D. Cash ---------------------------------------- R. D. Cash Chairman and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ R. D. Cash Chairman and Chief Executive --------------------------- Officer (Principal Executive R. D. Cash Officer) /s/ S. E. Parks Senior Vice President, Treasurer and --------------------------- Chief Financial Officer (Principal S. E. Parks Financial and Accounting Officer) *R. D. Cash Director *K. O. Rattie Director *Teresa Beck Director *Patrick J. Early Director *W. W. Hawkins Director *Robert E. Kadlec Director *Dixie L. Leavitt Director *Gary G. Michael Director *G. L. Nordloh Director *Scott S. Parker Director *D. N. Rose Director *Harris H. Simmons Director JANUARY 16, 2002 *By /s/ R. D. Cash ----------------------- -------------------------------- Date R. D. Cash, Attorney in Fact 55