=============================================================================== SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A Amendment No. 1 (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. 0-30321 QUESTAR MARKET RESOURCES, INC. - ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) - ------------------------------------------------------------------------------- State of Utah 87-0287750 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) - ------------------------------------------------------------------------------- 180 East 100 South, P.O. Box 45601, Salt Lake City, Utah 84145-0601 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (801) 324-2600 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Common Stock, $1.00 Par Value SECURITIES REGISTERED PURSUANT TO THE SECURITIES ACT OF 1933: 7 1/2% Notes Due 2011 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 ___ State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of March 1, 2001. $0. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of March 1, 2001: 4,309,427 shares of Common Stock, $1.00 par value. (All shares are owned by Questar Corporation.) Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K/A Report with the reduced disclosure format. =============================================================================== (For purposes of Questar Market Resources'10-K/A, we are including only those items that contain changed information.) TABLE OF CONTENTS
Heading Page - -------- ---- PART I Item 2. PROPERTIES......................................................... 2 PART II Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION....................... 9 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK......... 13 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............................................ 16 SIGNATURES.................................................................. 44 PART I ITEM 2. PROPERTIES. RESERVES. The following table sets forth the Company's estimated proved reserves, the 10 percent present value of the estimated future net revenues from the reserves and the standardized measure of discounted net cash flows as of December 31, 2000. QMR's reserves were estimated by Ryder Scott Company; H. J. Gruy and Associates, Inc.; Netherland, Sewell & Associates, Inc.; Malkewicz Hueni Associates, Inc.; Gilbert Laustsen Jung Associates Ltd.; and Sproule Associates, Ltd., independent petroleum engineers. The Company does not have any long-term supply contracts with foreign governments, or reserves of equity investees or of subsidiaries with a significant minority interest. These proved reserve volumes do not include cost-of-service reserves managed and developed by Wexpro for Questar Gas. - -------------- (1) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt service; depreciation, depletion and amortization; and income tax expense). (2) The standardized measure of discounted net cash flows prepared by the Company represent the present value of estimated future net revenues after income taxes, discounted at 10 percent. Estimates of the Company's proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth in this document represent estimates. Reference should be made to Note 11 of the Notes to Consolidated Financial Statements included in Item 14 of this Report for additional information pertaining to the Company's proved natural gas and oil reserves as of the end of each of the last three years. 2
December 31, 2000 ----------------------- United States Canada Total ------------- ------ ----- Estimated proved reserves Natural gas (Bcf) 579.8 60.1 639.9 Oil and NGL (MMBbls) 11.3 3.7 15.0 Proved developed reserves (Bcfe) 492.3 74.1 566.4 Present value of estimated future net revenues before future income taxes discounted at 10% (in thousands) (1) $ 2,348,638 $ 275,436 $ 2,624,074 Standardized measure of discounted net cash flows (in thousands) (2) (Restated) $ 1,544,382 $ 173,306 $ 1,717,688 During 2000, the Company filed estimated reserves as of year-end of Form EIA-23 with the Energy Information Administration in the Department of Energy and will submit a comparable report for 2000. Although QMR uses the same technical and economic assumption when it prepares the EIA-23, it is obligated to report reserves for wells it operates, not for all wells in which it has an interest, and to include the reserves attributable to other owners in such wells. The following charts illustrate QMR's reserve statistics for the years ended December 31, 1996 through 2000: Oil and Gas Reserves (Bcfe)* *Does not include cost of service reserves managed and developed by Wexpro for Questar Gas. Proportion of Proved Developed to Proved Reserves and Proportion of Gas Reserves (Bcfe)*
Year Year-End Reserves Annual Production Reserve Life (Years) - ---- ----------------- ----------------- -------------------- 1996 493.6 51.5 9.6 1997 469.3 61.7 7.6 1998 574.1 65.3 8.8 1999 597.6 76.6 7.8 2000 730.1 82.3 8.9 *Does not include cost of service reserves managed and developed by Wexpro for Questar Gas. GEOGRAPHIC DIVERSITY OF PRODUCING PROPERTIES The following table summarizes proved reserves by the Company's major operating areas at December 31, 2000:
Total Proved Proved Developed Developed Natural Gas Percentage of Year Reserves Reserves Percent of Total Proved Reserves - ---- ------------ ---------------- ---------------- -------------------------- 1996 493.6 410.1 83% 78% 1997 469.3 392.9 84% 81% 1998 574.1 506.0 88% 85% 1999 597.6 503.9 84% 86% 2000 730.1 566.4 78% 88% *Does not include cost of service reserves managed and developed by Wexpro for Questar Gas. 3
Proved Reserves* % of Total ---------------- ---------- (Bcfe) Mid-Continent 325.6 45% Rocky Mountain Region (exclusive of Pinedale) 175.9 24% Pinedale Anticline 146.2 20% Western Canada 82.4 11% PRODUCTION. The following table sets forth the Company's net production volumes, the average sales prices per Mcf of gas, Bbl of oil and Bbl of natural gas liquids produced, and the production cost per Mcfe for the years ended December 31, 2000, 1999, and 1998, respectively: PRODUCTIVE WELLS. The following table summarizes the Company's productive wells as of December 31, 2000: PRODUCTIVE WELLS (1) (2)
Year Ended December 31, 2000 1999 1998 ------ ------ ------ UNITED STATES (EXCLUDING COST OF SERVICE ACTIVITIES) Volumes produced and sold Gas (Bcf) 61.7 59.8 48.6 Oil and NGL (MMBbls) 1.5 1.9 1.9 Sales Prices: Gas (per Mcf) $ 2.80 $ 2.02 $ 1.95 Oil and NGL (per Bbl) $ 19.61 $ 13.31 $ 12.41 Production costs per Mcfe $ .69 $ .59 $ .64 CANADA Volumes produced and sold Gas (Bcf) 7.3 2.9 2.7 Oil and NGL (MMBbls) .7 0.4 0.4 Sales Prices: Gas (per Mcf) $ 2.83 $ 1.61 $ 1.40 Oil and NGL (per Bbl) $ 22.29 $ 16.56 $ 14.09 Production costs per Mcfe $ .73 $ .67 $ .58 (1) Although many of the Company's wells produce both oil and gas, a well is categorized as either an oil well or a gas well based upon the ratio of oil to gas production. (2) Each well completed to more than one producing zone is counted as a single well. There were 140 gross wells with multiple completions. The Company also held numerous overriding royalty interests in gas and oil wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in the Company's gross and net well count. 4
GAS WELLS OIL WELLS TOTAL WELLS ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- United States 3,702 1,554 1,046 401 4,748 1,955 Canada 542 187 202 67 744 254 ----- ----- ----- ----- ----- ----- Total: 4,244 1,741 1,248 468 5,492 2,209 LEASEHOLD ACREAGE. The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest as of December 31, 2000. "Undeveloped Acreage" includes (i) leasehold interests that already may have been classified as containing proved undeveloped reserves; and (ii) unleased mineral interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding royalty, and other similar interests. Leasehold Acreage - December 31, 2000 5
Developed (1) Undeveloped (2) Total ------------------------ ------------------------ ------------------------ Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- UNITED STATES Arizona -- -- 480 450 480 450 Arkansas 37,729 16,569 1,230 373 38,959 16,942 California 760 265 23,102 9,043 23,862 9,308 Colorado 176,651 125,297 207,581 104,852 384,232 230,149 Idaho -- 44,175 10,643 44,175 10,643 -- Illinois 172 39 14,307 3,997 14,479 4,036 Indiana -- -- 1,621 467 1,621 467 Kansas 134 134 44,330 16,430 44,464 16,564 Kentucky -- -- 14,461 5,468 14,461 5,468 Louisiana 15,246 9,992 404 397 15,650 10,389 Michigan -- -- 6,200 1,266 6,200 1,266 Minnesota -- -- 313 104 313 104 Mississippi 25,706 21,408 859 273 26,565 21,681 Montana 25,285 10,187 319,745 58,594 345,030 68,781 Nevada 320 280 680 543 1,000 823 New Mexico 90,297 66,349 32,006 9,553 122,303 75,902 North Dakota 1,333 375 145,841 21,580 147,174 21,955 Ohio -- -- 202 43 202 43 Oklahoma 1,538,294 290,246 52,736 33,296 1,591,030 323,542 Oregon -- -- 43,869 7,671 43,869 7,671 South Dakota -- -- 204,558 107,988 204,558 107,988 Texas 168,336 61,000 51,881 40,725 220,217 101,725 Utah 45,712 35,001 109,180 43,280 154,892 78,281 Washington -- -- 26,631 10,149 26,631 10,149 West Virginia 969 115 -- -- 969 115 Wyoming 221,718 142,625 447,233 268,848 668,951 411,473 --------- --------- --------- --------- --------- --------- Total U.S. 2,348,662 779,882 1,793,625 756,033 4,142,287 1,535,915 --------- --------- --------- --------- --------- --------- CANADA Alberta 222,938 82,919 324,636 135,474 547,574 218,393 British Columbia 33,069 8,485 42,108 21,719 75,177 30,204 Saskatchewan 2,277 1,061 4,625 4,462 6,902 5,523 --------- --------- --------- --------- --------- --------- Total Canada 258,284 92,465 371,369 161,655 629,653 254,120 --------- --------- --------- --------- --------- --------- Total Acreage 2,606,946 872,347 2,164,994 917,688 4,771,940 1,790,035 ========= ======= ========= ======= ========= ========= (1) Developed acres are acres spaced or assignable to productive wells. (2) Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. Of the aggregate 2,164,994 gross and 917,688 net undeveloped acres, 114,827 gross and 30,747 net acres are held by production from other leasehold acreage. Substantially all the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated: DRILLING ACTIVITY. The following table summarizes the number of development and exploratory wells drilled by the Company, including the cost-of-service wells drilled by Wexpro, during the years indicated.
Acres Expiring --------------------------- Gross Net --------- ------- Twelve Months Ending December 31, 2001 154,070 58,641 December 31, 2002 88,980 44,787 December 31, 2003 141,354 62,639 December 31, 2004 74,890 49,327 December 31, 2005 and later 1,705,700 702,294 6
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 2000 1999 1998 ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- DEVELOPMENT WELLS United States Completed as natural gas wells 211 79.8 159 78.4 105 54.6 Completed as oil wells 9 1.4 5 2.4 29 1.0 Dry holes 12 5.0 15 6.1 12 3.7 Waiting on completion 36 -- 29 -- 13 -- Drilling 14 -- 6 -- 9 -- Canada Competed as natural gas wells 11 1.1 7 1.2 4 0.9 Completed as oil wells 8 2.3 5 1.9 12 4.0 Dry holes 2 1.1 2 1.3 4 1.2 Waiting on completion 2 -- 2 -- 2 -- Drilling 1 -- -- -- 1 -- ----- ----- ----- ----- ----- ----- Total Development Wells 306 90.7 230 91.3 191 65.4 Operation of Properties. The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. The charges under operating agreements customarily vary with the depth and location of the well being operated. QMR is the operator of approximately 50 percent of its wells. As operator, QMR receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per- well producing and drilling overhead reimbursement at rates customarily charged in the area to or by unaffiliated third parties. In presenting its financial data, QMR records the monthly overhead reimbursement as a reduction of general and administrative expense, which is a common industry practice. TITLE TO PROPERTIES. Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, to other encumbrances. The Company believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. PINEDALE. Both Questar E&P and Wexpro are involved in Pinedale drilling. During 2000, Questar E&P and Wexpro drilled nine wells and completed six of them in the Pinedale Anticline area of Sublette County, Wyoming. (Three of the wells will not be completed until June of 2001 when winter drilling restrictions are lifted.) Drilling results and initial production tests confirmed reserve expectations of 5-6 Bcf per well. As of December 31, 2000, gross daily production from 14 Company-owned wells was estimated at 26 MMcf and 45 Bbl of oil. 7
EXPLORATORY WELLS United States Completed as natural gas wells -- -- 1 0.2 5 1.6 Completed as oil wells -- -- -- -- 1 6 Dry holes 5 2.0 2 1.1 4 1.4 Waiting on completion -- -- 1 -- -- -- Drilling 1 -- 1 -- -- -- Canada Competed as natural gas wells 1 .2 -- -- -- -- Completed as oil wells 1 .2 -- -- 1 .3 Dry holes 2 .9 -- -- 3 1.4 Waiting on completion -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- Total Exploratory Wells 10 3.3 5 1.3 14 5.3 Total Wells 316 94.0 235 92.6 205 70.7 ===== ===== ===== ===== ===== ===== Questar E&P and Wexpro expect to continue drilling activities in Pinedale when government restrictions permit. On a combined basis, they have an approximate 60 percent average working interest in 14,800 acres in the Mesa Area of the Pinedale Anticline and expect to drill between 135- 150 wells based on 80-acre spacing. QMR's activities in Pinedale illustrate its long-term approach. Wexpro held the leasehold acreage by production as a result of three wells drilled in the area during the mid-1970's. Since the gas reserves are contained in tight sands with a low porosity, Questar E&P and Wexpro did not drill additional wells in the Pinedale area until other companies developed new stimulation techniques that fractured sandstone formations at multiple intervals and successfully used such techniques to drill wells in neighboring fields. The Pinedale wells cost an average of $2.2 million to drill and complete; this cost reflects the completion depth of the wells (12,848 to 13,300 feet), the need for special handling and multiple stimulations, and government regulations that impose pad limitations and restrict drilling. Current production profiles suggest that the average well may produce on a long- term basis after stabilizing between 2 and 4 MMcf per day within the first year or two after completion. Questar E&P and Wexpro expect to continue drilling in the Pinedale area during the next several years. 8 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RESULTS OF OPERATIONS QUESTAR MARKET RESOURCES ("QMR" or "Market Resources" or the "Company") conducts exploration and production, gas development, gathering, processing and marketing activities. On July 1, 2001, 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 and $2.0 million for the years ended December 31, 2000 and 1999, respectively, and increased $9.4 million for the year ended December 31, 1998. Following is a restated summary of financial results and operating information. 9
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 ======================================== 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 10
Year Ended December 31, 2000 1999 1998 ---------------------------------------- (In Thousands) 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 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 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. INTEREST AND OTHER INCOME Interest and other income was higher in 2000 due to a $3.9 million pre-tax gain from selling securities available for sale, capitalized financing costs associated with an underground storage project of $1.9 million and $1.4 million of interest earned on qualifying hedging collateral. Gains from selling properties amounted to $4 million in 1999, while sales of securities available for sale generated a $.4 million pre-tax gain. 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 33.2% in 2000, 28.5% in 1999 and 15.7% in 1998. Income tax rates were below the combined statutory rate of about 40% primarily due to nonconventional fuel credits, which amounted to $4.7 million in 2000, $5.3 million in 1999 and $5.7 million in 1998. 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 Mid-continent 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 11 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. LIQUIDITY AND CAPITAL RESOURCES Operating Activities (Restated) Net cash provided from operating activities decreased 3% in 2000 when compared with 1999 due to timing differences in accounts receivable and qualifying hedging accounts more than offsetting a 77% increase in net income. The balances in accounts receivable and qualifying hedging accounts increased as a result of higher energy prices. This was partially offset by increases in accounts payable caused by higher energy prices. Investing Activities (Restated) Capital expenditures in 2000 primarily reflected exploration for and development of gas and oil reserves and a purchase of a Canadian company with 61.1 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%. The details of capital expenditures for 2000, 1999 and a forecast of 2001 are as follows:
Year Ended December 31, 2000 1999 1998 ---------------------------------------- (In Thousands) Net income $77,808 $43,888 $25,585 Adjustments to net income for noncash expenses 108,121 86,630 84,763 Changes in operating assets and liabilities (54,680) 4,914 11,808 ---------------------------------------- Net cash provided from operating activities $131,249 $135,432 $122,156 ======================================== 12
Year Ended December 31, 2001 Forecast 2000 1999 ---------------------------------------- (In Thousands) 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 ======================================== Financing Activities Approximately 79% of the net cash used in investing activities was supplied by net cash flow provided from operating activities. Proceeds from short-term borrowing and cash released from an escrow account provide the remaining sources of funding in 2000. Proceeds from a 1999 sale of nonstrategic gas and oil properties were placed in an escrow account pending a possible reinvestment in other producing properties. When this did not occur, the funds were released from escrow. A sale with similar conditions and amounting to $27 million was finalized in January 2001. In the third quarter of 2000, Market Resources initiated an unrated commercial-paper program with $100 million of 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 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 and a $300 million capacity. Market Resources had borrowed $244.4 million as of December 31, 2000 under this arrangement. QMR's consolidated capital structure consisted of 37% long-term debt and 63% common shareholder's equity at December 31, 2000. The Company's long-term debt has been rated BBB+ by Standard and Poor's and Baa2 by Moody's. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. QMR'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. QMR also has reserved 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 13 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 financial 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 held floating-rate long-term debt at December 31, 2000 and 1999 of $244.4 million and $264.9 million, respectively. The book value of variable-rate debt approximates fair value. If interest rates declined by 10%, interest costs paid on variable-rate long-term debt would decrease about $1.7 million in 2000 and 1999. 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. 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. 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 14 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. 15 During 2000, the Company filed estimated reserves as of year-end of Form EIA-23 with the Energy Information Administration in the Department of Energy and will submit a comparable report for 2000. Although QMR uses the same technical and economic assumption when it prepares the EIA-23, it is obligated to report reserves for wells it operates, not for all wells in which it has an interest, and to include the reserves attributable to other owners in such wells. 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. (3) Exhibits. The following is a list of exhibits required to be filed as a part of this Report in Item 14(c). 16
Exhibit No. Description - ----------- ----------- 3.1.* Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company's Form 10 dated April 12, 2000.) 3.2.* Articles of Merger, dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company's Form 10 dated April 12, 2000.) 3.3.* Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company's Form 10 dated April 12, 2000.) 3.4.* Bylaws (as amended effective February 8, 2000.) (Exhibit No. 3.4. to the Company's Form 10 dated April 12, 2000.) 4.1.* Indenture dated as of March 1, 2001, between the Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company's 7 1/2% Notes due 2011. (Exhibit No. 4.01. to the Company's Current Report on Form 8-K dated March 6, 2001.) 4.2.* Form of 7 1/2% Notes due 2011. (Exhibit No. 4.02. to the Company's Current Report on Form 8-K dated March 6, 2001.) 4.3.* U.S. Credit Agreement, dated April 19, 1999, by and among Questar Market Resources, Inc., as U.S. borrower, NationsBank, N.A., as U.S. agent, and certain financial institutions, as lenders, with the First Amendment dated May 17, 1999, the Second Amendment dated July 30, 1999, the Third Amendment dated November 30, 1999, the Fourth Amendment dated April 17, 2000, the Fifth Amendment dated October 6, 2000, and the Sixth Amendment dated February 9, 2001. (Exhibit No. 4.1. to the Company's Form 10 dated April 12, 2000, for the U. S. Credit Agreement, and the First, Second and Third Amendments; Exhibit No. 4.1. to the Company's Form 10/A dated November 9, 2000, for the Fourth and Fifth Amendments.) The Sixth Amendment is filed with this Report.1 *Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference. (b) The Company filed two Current Reports on Form 8-K during the last quarter of 2000. The first report was dated November 21, 2000, and disclosed the settlement agreement in BRIDENSTINE V. KAISER-FRANCIS OIL COMPANY. The second report was dated December 7, 2000, and contained a press release on the results of drilling at the Pinedale Anticline area. Neither report included any financial statements. 17
4.4.* Long-term debt instruments with principal amounts not exceeding 10 percent of QMR's total consolidated assets are not filed as exhibits. The Company will furnish a copy of these agreements to the Commission upon request. 10.1.* Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; 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 Questar Gas Company's Form 10-K Annual Report for 1981.) 21.* Subsidiary Information. 24.* Power of Attorney 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 MARKET RESOURCES, INC. SALT LAKE CITY, UTAH FORM 10-K/A -- ITEM 14 (a) (1) AND (2) QUESTAR MARKET RESOURCES, INC. LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES The following financial statements of Questar Market Resources Inc. are included in Item 8: Statements of income, Years ended December 31, 2000, 1999 and 1998 Balance sheets, December 31, 2000 and 1999 Statements of common shareholder's equity, Years ended December 31, 2000, 1999 and 1998 Statements of cash flows, Years ended December 31, 2000, 1999 and 1998 Notes to 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. 18 REPORT OF INDEPENDENT AUDITORS Board of Directors Questar Market Resources, Inc. We have audited the accompanying consolidated balance sheets of Questar Market Resources, Inc. as of December 31, 2000 and 1999, and the related consolidated statements of income and common shareholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 Market Resources, Inc. at December 31, 2000 and 1999, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, 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. 19
Salt Lake City, Utah Ernst & Young LLP March 6, 2001 except for /s/ Ernst & Young LLP Note 1, as to which the date is November 30, 2001 and Note 2, as to which the date is July 31, 2001 QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Restated) See notes to consolidated financial statements. 20
Year Ended December 31, 2000 1999 1998 ------------------------------------------ (In Thousands) REVENUES From unaffiliated customers $ 649,200 $ 418,603 $ 382,791 From affiliates 92,853 79,708 75,481 ------------------------------------------ TOTAL REVENUES 742,053 498,311 458,272 OPERATING EXPENSES Cost of natural gas and other products sold 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 INTEREST AND OTHER INCOME 8,412 8,272 2,457 INCOME (LOSS) FROM UNCONSOLIDATED AFFILIATES 2,776 763 (930) DEBT EXPENSE (22,922) (17,363) (12,631) ------------------------------------------ INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 116,426 61,371 31,034 INCOME TAX EXPENSE 38,618 17,483 4,886 ------------------------------------------ INCOME FROM CONTINUING OPERATIONS 77,808 43,888 26,148 DISCONTINUED OPERATIONS, net of income taxes of $347 (563) ------------------------------------------ NET INCOME $ 77,808 $ 43,888 $ 25,585 ========================================== QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Restated) ASSETS 21
December 31, 2000 1999 ---------------------------- (In Thousands) CURRENT ASSETS Cash and cash equivalents $ 3,980 Notes receivable from Questar Corporation $ 4,000 Accounts receivable, net of allowance of $1,775 in 2000 and $1,350 in 1999 126,030 64,364 Accounts receivable from affiliates 17,427 11,459 Qualifying hedging collateral 48,377 Federal income taxes recoverable 4,976 Inventories, at lower of average cost or market Gas and oil storage 7,618 8,863 Material and supplies 2,298 2,390 Prepaid expenses and other 4,828 4,452 --------------------------- TOTAL CURRENT ASSETS 215,534 95,528 PROPERTY, PLANT AND EQUIPMENT Oil and gas properties - successful efforts accounting Proved properties 845,485 717,147 Unproved properties, not being amortized 55,608 51,624 Support equipment and facilities 13,179 13,408 Cost-of-service oil and gas operations - successful efforts accounting 348,403 318,451 Gathering, processing and marketing 137,484 124,691 --------------------------- 1,400,159 1,225,321 Less allowances for depreciation, depletion and amortization Oil and gas properties - successful efforts accounting 411,506 353,399 Cost-of-service oil and gas operations - successful efforts accounting 193,029 180,867 Gathering, processing and marketing 58,388 53,337 --------------------------- 662,923 587,603 --------------------------- NET PROPERTY, PLANT AND EQUIPMENT 737,236 637,718 INVESTMENT IN UNCONSOLIDATED AFFILIATES 15,417 13,301 OTHER ASSETS Cash held in escrow account 5,387 36,727 Securities available for sale 10,402 Other 4,344 952 --------------------------- 9,731 48,081 --------------------------- $ 977,918 $ 794,628 =========================== LIABILITIES AND SHAREHOLDER'S EQUITY See notes to consolidated financial statements. 22
December 31, 2000 1999 ------------------------- (In Thousands) CURRENT LIABILITIES Checks outstanding in excess of cash balances $ 1,246 Short-term loans $ 12,500 Notes payable to Questar 51,000 24,500 Accounts payable and accrued expenses Accounts and other payables 140,254 67,385 Accounts payable to affiliates 3,761 2,952 Federal income taxes 6,232 Other taxes 19,359 14,266 Interest 951 1,443 ------------------------- Total accounts payable and accrued expenses 164,325 92,278 ------------------------- TOTAL CURRENT LIABILITIES 227,825 118,024 LONG-TERM DEBT 244,377 264,894 DEFERRED INCOME TAXES 67,875 38,002 OTHER LIABILITIES 13,847 14,674 MINORITY INTEREST 5,483 2,529 COMMITMENTS AND CONTINGENCIES SHAREHOLDER'S EQUITY Common stock - par value $1 per share; authorized, 25,000,000 shares; issued and outstanding, 4,309,427 shares 4,309 4,309 Additional paid-in capital 116,027 116,027 Retained earnings 299,420 238,912 Cumulative other comprehensive loss (1,245) (2,743) ------------------------- 418,511 356,505 ------------------------- $ 977,918 $ 794,628 ========================= QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (Restated) See notes to consolidated financial statements. 23
Cumulative Additional Other Compre- Common Paid-in Retained Comprehensive hensive Stock Capital Earnings Income (loss) Income ------------------------------------------------------------------------- (In Thousands) Balance at January 1, 1998 $ 4,309 $ 116,027 $ 200,034 $ (19) 1998 net income 25,585 $ 25,585 Cash dividends (15,900) Foreign currency translation adjustment, net of income taxes of $214 396 396 ------------------------------------------------------------------------- Balance at December 31, 1998 4,309 116,027 209,719 377 $ 25,981 ======== 1999 net income 43,888 $43,888 Cash dividends (16,600) Dividend of shares of Questar Energy Services 1,905 Unrealized loss on securities available for sale, net of income taxes of $1,557 (2,515) (2,515) Foreign currency translation adjustment, net of income taxes of $327 (605) (605) ------------------------------------------------------------------------- Balance at December 31, 1999 4,309 116,027 238,912 (2,743) $ 40,768 ======== 2000 net income 77,808 $77,808 Cash dividends (17,300) Unrealized gain on securities available for sale, net of income taxes of $1,557 2,515 2,515 Foreign currency translation adjustment, net of income taxes of $949 (1,017) (1,017) ------------------------------------------------------------------------ Balance at December 31, 2000 $ 4,309 $ 116,027 $ 299,420 $ (1,245) $ 79,306 ======================================================================== QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Restated) See notes to consolidated financial statements. 24
Year Ended December 31, 2000 1999 1998 -------------------------------------------- (In Thousands) OPERATING ACTIVITIES Net income $ 77,808 $ 43,888 $ 25,585 Adjustments to reconcile net income to net cash provided from operating activities Depreciation, depletion and amortization 85,733 75,570 65,541 Deferred income taxes 22,818 7,979 1,693 Abandonment and impairment of oil and gas properties 3,418 7,535 15,137 (Income) loss from unconsolidated affiliates, net of cash distributions (2,117) (66) 1,211 (Gain) loss from sale of properties and securities (1,731) (4,388) 1,181 Changes in operating assets and liabilities Accounts receivable and qualifying hedging collateral (112,757) (2,631) 20,572 Inventories 1,337 (468) (4,996) Prepaid expenses and other (423) (83) 555 Accounts payable and accrued expenses 74,226 5,655 (7,002) Federal income taxes (11,207) 127 2,399 Other assets (3,125) (783) (628) Other liabilities (2,731) 3,097 908 ------------------------------------------- NET CASH PROVIDED FROM OPERATING ACTIVITIES 131,249 135,432 122,156 INVESTING ACTIVITIES Capital expenditures Purchase of property, plant and equipment (187,359) (103,384) (246,801) Other investments (24,864) (1,875) ------------------------------------------- (187,359) (128,248) (248,676) Proceeds from disposition of property, plant and equipment 2,254 37,888 7,647 Proceeds from sale of securities 18,424 1,214 ------------------------------------------- NET CASH USED IN INVESTING ACTIVITIES (166,681) (89,146) (241,029) FINANCING ACTIVITIES Change in notes receivable from Questar 4,000 21,100 8,400 Change in notes payable to Questar 26,500 (97,300) 77,500 Increase in short-term debt 12,500 Change in cash in escrow 31,340 (36,727) Checks written in excess of cash balances (1,246) 1,246 Issuance of long-term debt 61,725 275,000 64,343 Payment of long-term debt (80,087) (195,000) (14,283) Other financing 2,955 Payment of dividends (17,300) (16,600) (15,900) ------------------------------------------- NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES 40,387 (48,281) 120,060 Foreign currency translation adjustments (975) 101 (307) ------------------------------------------- Change in cash and cash equivalents 3,980 (1,894) 880 Beginning cash and cash equivalents 1,894 1,014 ------------------------------------------- ENDING CASH AND CASH EQUIVALENTS $ 3,980 $ - $ 1,894 =========================================== QUESTAR MARKET RESOURCES, INC. 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 Market Resources, Inc. and subsidiaries (the "Company" or "QMR" or "Market Resources"). The Company is a wholly-owned subsidiary of Questar Corporation ("Questar"). QMR, through its subsidiaries, conducts gas and oil exploration, development and production, gas gathering and processing, and wholesale energy marketing. Questar Exploration and Production ("Questar E & P"), conducts exploration, development and production activities. Wexpro Company ("Wexpro") operates and develops producing properties on behalf of Questar Gas. Questar Gas Management conducts gas gathering and plant processing activities. Questar Energy Trading performs wholesale energy marketing activities and through a 75% interest in Clear Creek Storage Company, LLC, operates a gas-storage field. All significant intercompany balances and transactions have been eliminated in consolidation. INVESTMENTS IN UNCONSOLIDATED AFFILIATES: QMR uses the equity method to account for investment in affiliates in which it does not have control. The Company owns a 15% interest in Canyon Creek Compression Co., a 50% interest in Blacks Fork Gas Processing Co. and a 15% interest in Roden Participants, Ltd. Generally, its investment in these affiliates equals the underlying equity in net assets. 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. The Company uses 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, 1999 and 1998 were not significant. WEXPRO SETTLEMENT AGREEMENT - OIL INCOME SHARING: Wexpro settlement agreement-oil income sharing represents payments made to Questar Gas for its share of the income from oil and NGL products associated with cost of service oil properties pursuant to the terms of the Wexpro settlement agreement (Note 9). REGULATION OF UNDERGROUND STORAGE: Clear Creek Storage Company, LLC operates an underground gas storage facility that is regulated by the Federal Energy Regulatory Commission (FERC). The FERC establishes rates for the storage of natural gas, and regulates 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. 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 our commercial bank accounts that result in available funds the next business day. NOTES RECEIVABLE FROM QUESTAR: Notes receivable from Questar represent interest bearing demand notes for cash loaned to Questar until needed in the Company's operations. The funds are centrally managed by Questar and earn an interest rate that is identical to the interest rate paid by the Company for borrowings from Questar. CHANGE IN METHOD OF ACCOUNTING FOR GAS AND OIL PROPERTIES: 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 25 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, 1997, of $38.9 million. This resulted from a reduction of net property, plant and equipment in the amount of $65.9 million and a reduction of deferred income taxes of $27.0 million. As a result of the change in accounting method, previously reported earnings decreased $7.2 million and $2.0 million for the years ended December 31, 2000 and 1999, respectively, and increased $9.4 million 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 operations and return on investment are regulated by the Wexpro settlement agreement (see Note 9). 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. GATHERING, PROCESSING AND MARKETING The investments in gathering facilities, processing plants and other general support property, plant and equipment are generally depreciated using the straight-line method based upon estimated useful lives ranging from 3 to 20 years. 26 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. DEPRECIATION, DEPLETION AND AMORTIZATION Average depreciation, depletion and amortization rates per Mcf equivalent for the 12 months ended December 31, were as follows:
For the year ended December 31, 2000 1999 1998 ------------------------------------------- (In Thousands) Depreciation., depletion and amortization expense Oil and gas properties (Restated) $ 65,169 $ 55,477 $ 48,603 Cost-of-service oil and gas operations 13,922 12,665 11,379 Gathering, processing and marketing 5,934 4,886 4,983 ------------------------------------------- $ 85,025 $ 73,028 $ 64,965 =========================================== CAPITALIZED INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: When applicable, the Company capitalizes interest costs, during the construction period of plant and equipment. Gross debt expense aggregated $22,922,000, $17,363,000, and $13,249,000, in 2000, 1999 and 1998, respectively. Debt expense was reduced by $618,000 of capitalized interest in 1998. Under provisions of the Wexpro settlement agreement, the Company capitalizes an allowance for funds used during construction (AFUDC) on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of plant and equipment. AFUDC amounted to $2,163,000, $357,000, and $745,000, in 2000, 1999, and 1998, respectively, and is included in Interest and Other Income in the Consolidated Statements of Income. FOREIGN CURRENCY TRANSLATION: The Company conducts gas and oil exploration and production 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 for the period. Adjustments resulting from such translations are reported as a separate component of other comprehensive income in shareholder's equity. Deferred income taxes have been provided on translation adjustments because the earnings are not considered to be permanently invested. MARKET RISKS: The Company's primary market-risk exposures arise from commodity price changes for natural gas and oil, changes in long-term interest rates, and foreign currency exchange rates. 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 Company's 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. 27
2000 1999 1998 ----------------------------------------- Oil and gas properties (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 operations $ 0.44 $ 0.42 $ 0.39 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. 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 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 Mid-continent 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 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: The Company accounts for income tax expense on a separate return basis. Pursuant to the Internal Revenue Code and associated regulations, the Company's operations are consolidated with those of Questar and its subsidiaries for income tax reporting purposes. The Company records tax benefits as they are generated. The Company receives payments from Questar for such tax benefits as they are utilized on the consolidated return. 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 Statements of Shareholder's Equity. Other comprehensive income transactions that currently apply to QMR result from changes in market value of securities available 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 market value. Income or loss is realized when the securities available for sale are sold. Proceeds from sales of available for sale securities were $18.4 million and $1.2 million for the year ended December 31, 2000 and 1999, respectively. Income tax expenses associated with realized gains from selling securities available for sale were $1.5 million in 2000 and $.1 million in 1999. 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 losses for the 12 months ended December 31, were as follows: 28
2000 1999 -------------------------------- (In Thousands) Unrealized loss on securities ($2,515) Foreign currency translation adjustment (Restated) ($1,245) (228) -------------------------------- Cumulative other comprehensive loss ($1,245) ($2,743) ================================ NEW ACCOUNTING STANDARD: The Company is required to adopt the accounting provisions of SFAS 133, as amended, "Accounting for Derivative Instruments and Hedging Activities" 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 equity physical transactions. ACQUISITIONS: On January 26, 2000, a subsidiary of QMR acquired 100% of the outstanding shares of Canor Energy Ltd from NI Canada ULC, a subsidiary of Northwest Natural Gas Co. for cash of $61 million (US) plus the assumption of $5.4 million of short-term debt. The transaction was accounted for as a purchase. Canor owns an interest in more than 800 wells located in Alberta, British Columbia and Saskatchewan provinces of Canada. Canor's proven gas and oil reserves were estimated at the time of purchase at 61.1 billion cubic feet equivalent. RECLASSIFICATIONS: Certain reclassifications were made to the 1999 and 1998 financial statements to conform with the 2000 presentation. Note 2 - Subsequent Event - Acquisition QMR 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. QMR 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. Note 3 - Debt QMR has a $300 million revolving credit facility agented by Bank of America. Borrowing under this agreement amounted to $244.4 million and $264.9 million at December 31, 2000 and 1999, respectively. The average interest rate as of December 31, was 7.01% in 2000 and 6.54% in 1999. The loan is segmented into United States and Canadian portions. The United States portion of the loan is a 5-year facility with $230 million available. The Canadian portion amounts to $70 million and is a 6-year facility. The interest rate is generally equal to LIBOR plus a premium. QMR's revolving credit facility contains covenants specifying a minimum amount of net equity and a maximum ratio of debt to equity. Under the most restrictive terms of the revolving credit facility, Market Resources could pay a dividend of $84.2 million. 29 Maturities of long-term debt for the five years following December 31, 2000, in thousands of dollars were as follows: 2001 $ - 2002 2,719 2003 12,719 2004 182,719 2005 2,719 Questar makes loans to QMR under a short-term borrowing arrangement. Short-term notes payable to Questar outstanding as of December 31, 2000 amounted to $51 million with an interest rate of 6.91% and $24.5 million as of December 31, 1999 with an interest rate of 6.61%. 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. Cash paid for interest was $23,414,000 in 2000, $16,964,000 in 1999 and $13,229,000 in 1998. Note 4 - Financial Instruments and Risk Management The carrying amounts and estimated fair values of the Company's financial instruments were as follows: The Company used the following methods and assumptions in estimating fair values: (1) Cash and cash equivalents, notes receivable and short-term loans - -the carrying amount approximates fair value; (2) Long-term debt - the carrying amount of variable-rate debt approximates fair value; (3) Gas and oil price hedging contracts - the fair value 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. After adjustments for transportation and heat-value associated with the hedged production of Company-owned gas, the resulting price would be between $2.90 and $3.15 per Mcf, net back to the well, as of December 31, 2000. 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 30
December 31, 2000 December 31, 1999 ----------------------------------------------------------------- Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value ----------------------------------------------------------------- (In Thousands) Financial assets Cash and cash equivalents $3,980 $3,980 Notes receivable from Questar $4,000 $4,000 Financial liabilities Short-term loans 63,500 63,500 25,746 25,746 Long-term debt 244,377 244,377 264,894 264,894 Gas and oil price hedging contracts - (98,000) - (6,200) 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. CREDIT RISK The Company's primary market areas are the Rocky Mountain regions of the United States and Canada and the Mid-continent 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. INTEREST-RATE RISK MANAGEMENT The Company held floating-rate long-term debt at December 31, 2000 and 1999. The book value of variable-rate debt approximates fair value. 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. Note 5 - Income Taxes (Restated) The components of income taxes for years ended December 31 were as follows: 31
2000 1999 1998 ------------------------------------------------ (In Thousands) Federal Current $13,678 $11,411 $4,263 Deferred 19,947 4,430 2,578 State Current 1,129 1,568 228 Deferred 1,763 959 1,166 Foreign 2,101 (885) (3,349) ------------------------------------------------ $38,618 $17,483 $4,886 ================================================ The difference between income tax expense and the tax computed by applying the statutory federal income tax rate of 35% to income from continuing operations before income taxes is explained as follows: Significant components of the Company's deferred income taxes at December 31 were as follows:
2000 1999 1998 ------------------------------------------------ (In Thousands) Income from continuing operations before income taxes $116,426 $61,371 $31,034 ================================================ Federal income taxes at statutory rate $40,749 $21,480 $10,862 State income taxes, net of federal income tax benefit 1,823 1,636 536 Nonconventional fuel credits (4,655) (5,282) (5,736) Foreign income taxes 723 (189) (964) Other (22) (162) 188 ------------------------------------------------ Income taxes $38,618 $17,483 $4,886 ================================================ Effective income tax rate 33.2% 28.5% 15.7% The Company paid $25,586,000 in 2000 and $7,183,000 in 1999 for income taxes. In 1998, Market Resources received $1,856,000 in settlement of income taxes. Note 6 - Litigation and Commitments 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 case of Bridenstine v. Kaiser-Francis Oil Company. 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. There are various other legal proceedings against Market Resources. 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. 32
2000 1999 -------------------------------- (In Thousands) Deferred tax liabilities Property, plant and equipment $77,737 $52,319 Other 775 589 -------------------------------- Total deferred tax liabilities 78,512 52,908 Deferred tax assets Alternative minimum tax and nonconventional fuel credit carryforwards 2,468 Reserves, compensation plans and other 10,637 12,438 -------------------------------- 10,637 14,906 -------------------------------- Net deferred income taxes $67,875 $38,002 ================================ Questar Energy Trading has contracted for firm-transportation services with various pipelines to transport 76.2 Mdth per day of gas. The contracts extends for 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 Energy Trading has reserved firm-storage capacity of 1,065 Mdth per day with Questar Pipeline through 2008 with an annual cost of $627,000. The minimum future payments under the terms of long-term operating leases for the Company's primary office locations for the four years following December 31, 2000, are as follows: 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 $2,087,000 in 2000, $1,804,000 in 1999 and $1,397,000 in 1998. Sublease rental receipts were $118,000 in 2000 and $94,000 in 1999. Note 7 - Employment Benefits Pension Plan: Substantially all of QMR's employees are covered by Questar's defined benefit pension plan, although some employees have elected other benefits in place of a pension benefit. Benefits are generally based on 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 applicable laws and regulations. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations. Pension cost was $385,000 in 2000, $887,000 in 1999 and $761,000 in 1998. Market Resources' portion of plan assets and benefit obligations is not determinable because the plan assets are not segregated or restricted to meet the Company's pension obligations. If the Company were to withdraw from the pension plan, the pension obligation for the Company's employees would be retained by the pension plan. At December 31, 2000, Questar's accumulated benefit obligation exceeded the fair value of plan assets. Postretirement Benefits Other Than Pensions: Market Resources pays a portion of health-care costs and life insurance costs for employees. The Company linked the health-care benefits to years of service and limited the Company's monthly health care contribution per individual to 170% of the 1992 contribution. Employees hired after December 31, 1996, do not qualify for postretirement medical benefits under this plan. 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 a transition obligation over a 20-year period beginning in 1992. Costs of postretirement benefits other than pensions were $1,654,000 in 2000, $1,158,000 in 1999 and $1,018,000 in 1998. Market Resources' portion of plan assets and benefit obligations related to postretirement medical and life insurance benefits is not determinable because the plan assets are not segregated or restricted to meet the Company's obligations. Postemployment Benefits: Market Resources 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 the present value both of current and future 33
(In Thousands) 2001 $1,885 2002 1,445 2003 522 2004 44 costs. The Company's postemployment benefit liability at December 31, 2000 and 1999 was $555,000 and $381,000, respectively based on a discount rate of 7.75%. Employee Investment Plan: The Company participates in Questar's Employee Investment Plan (EIP), which allows eligible employees to purchase Questar common stock or other investments through payroll deduction of pretax earnings. The Company pays for contributions of Questar common stock to the EIP of approximately 80% of the employees' purchases of the maximum of 6% of eligible earnings and contributes an additional $200 of common stock in the name of each eligible employee. The Company's expense and contribution to the plan was $1,125,000 in 2000, $895,000 in 1999 and $811,000 in 1998. Note 8 - Related Party Transactions QMR receives a significant portion of its revenues from services provided to Questar Gas Company. The Company received $92,455,000 in 2000, $79,324,000 in 1999 and $75,171,000 in 1998 for operating cost-of-service gas properties, gathering gas and supplying a portion of gas for resale, among other services provided to Questar Gas. Operation of cost-of-service gas properties is described in Wexpro Settlement Agreement (Note 8). The Company also received revenues from other affiliated companies totaling $397,000 in 2000, $384,000 in 1999 and $310,000 in 1998. Questar performs certain administrative functions for QMR. The Company was charged for its allocated portion of these services which totaled $6,626,000 in 2000, $4,469,000 in 1999 and $3,970,000 in 1998. These costs are included in operating and maintenance expenses and are allocated based on each affiliate's proportional share of revenues, net of gas costs; property, plant and equipment; and payroll. Management believes that the allocation method is reasonable. QMR's subsidiaries contracted for transportation and storage services with Questar Pipeline and paid $2,146,000 in 2000, $3,378,000 in 1999 and $3,968,000 in 1998 for those services. Questar InfoComm Inc is an affiliated company that provides some data processing and communication services to Market Resources. The Company paid Questar InfoComm $1,904,000 in 2000, $2,276,000 in 1999 and $2,273,000 in 1998. QMR has a 5-year lease with Questar for space in an office building located in Salt Lake City, Utah and owned by a third party. The third party has a lease arrangement with Questar Corp, which in turn sublets office space to affiliated companies. The annual lease payment, which began October of 1997, is $863,000. The Company received interest income from affiliated companies of $355,000 in 2000, $681,000 in 1999 and $1,908,000 in 1998. Market Resources incurred debt expense to affiliated companies of $2,520,000 in 2000, $3,350,000 in 1999 and $3,331,000 in 1998. Note 9 - 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%. 34 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%. Note 10 - Business Segment Information QMR is a sub-holding company that has three primary business segments: exploration and production, the management and development of cost of service properties, and gathering, processing and marketing. QMR's reportable segments are strategic business units with similar operations and management objectives. The reportable segments are managed separately because each segment requires different operational assets, technology and management strategies. 35
Year Ended December 31, 2000 1999 1998 ------------------------------------------------ (In Thousands) Revenues from Unaffiliated Customers Exploration and production $ 245,728 $ 162,475 $ 135,509 Cost of service 15,179 8,844 10,025 Gathering, processing and marketing 388,293 247,284 237,257 ------------------------------------------------ $ 649,200 $ 418,603 $ 382,791 ================================================ Revenues from Affiliated Companies Exploration and production $ 18 $ - $ - Cost of service 73,721 62,335 58,581 Gathering, processing and marketing 19,114 17,373 16,900 ------------------------------------------------ $ 92,853 $ 79,708 $ 75,481 ================================================ Depreciation, Depletion and Amortization Expense (Restated) Exploration and production $ 65,169 $ 55,477 $ 48,603 Cost of service 13,922 12,665 11,379 Gathering, processing and marketing 5,934 4,886 4,983 ------------------------------------------------ $ 85,025 $ 73,028 $ 64,965 ================================================ Operating Income (Restated) Exploration and production $ 77,919 $ 30,327 $ 10,446 Cost of service 38,502 32,948 28,218
Gathering, processing and marketing 11,739 6,424 3,474 ------------------------------------------------ $ 128,160 $ 69,699 $ 42,138 ================================================ 36
Year Ended December 31, 2000 1999 1998 ------------------------------------------------ (In Thousands) Interest and Other Income (Restated) Exploration and production $ 387 $ 6,209 $ 1,075 Cost of service 472 534 971 Gathering, processing and marketing 7,553 1,529 411 ------------------------------------------------ $ 8,412 $ 8,272 $ 2,457 ================================================ Debt Expense Exploration and production $ 17,976 $ 14,770 $ 11,552 Cost of service 721 582 149 Gathering, processing and marketing 4,225 2,011 930 ------------------------------------------------ $ 22,922 $ 17,363 $ 12,631 ================================================ Income Taxes (Restated) Exploration and production $ 18,483 $ 2,936 $ (6,197) Cost of service 13,873 12,020 10,387 Gathering, processing and marketing 6,262 2,527 696 ------------------------------------------------ $ 38,618 $ 17,483 $ 4,886 ================================================ Income From Continuing Operations (Restated) Exploration and production $ 42,137 $ 18,830 $ 6,166 Cost of service 24,380 20,880 18,653 Gathering, processing and marketing 11,291 4,178 1,329 ------------------------------------------------ $ 77,808 $ 43,888 $ 26,148 ================================================ Fixed Assets - Net (Restated) Exploration and production $ 502,766 $428,780 $447,145 Cost of service 155,374 137,584 129,573 Gathering, processing and marketing 79,096 71,354 69,055 ------------------------------------------------ $ 737,236 $637,718 $645,773 ================================================ Capital Expenditures (Restated) Exploration and production $ 140,487 $ 75,842 $213,738 Cost of service 32,048 21,076 26,653 Gathering, processing and marketing 14,824 31,330 8,285 ------------------------------------------------ $ 187,359 $128,248 $248,676 ================================================ GEOGRAPHIC INFORMATION Revenues United States $ 703,981 $ 485,995 $ 447,798 Canada 38,072 12,316 10,474 ------------------------------------------------ $ 742,053 $ 498,311 $ 458,272 ================================================ Fixed Assets - Net (Restated) United States $ 648,089 $ 611,075 $ 619,146 Canada 89,147 26,643 26,627 ------------------------------------------------ Note 11 - 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 9). 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:
$ 737,236 $ 637,718 $ 645,773 ================================================ 37
------------------------------------------------- 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 ================================================= COSTS INCURRED (RESTATED) The following costs were incurred in oil and gas exploration and development activities: 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.
------------------------------------------------ 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 ================================================ 38
------------------------------------------------ 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 ================================================ 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. 39
------------------------------------------------ United States Canada Total ------------------------------------------------ (In Thousands) 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 ================================================ 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. 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. 40
Natural Gas Oil ----------- --- United States Canada Total United States Canada Total ------------------------------------------------------------------------------------------------ (MMcf) (MBbl) 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) (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 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. 41
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 ================================================ The principal sources of change in the standardized measure of discounted future net cash flows were: 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:
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 ================================================ 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. 42
December 31, 2000 1999 1998 ------------------------------------------------ (In Thousands) Proved properties $348,403 $318,451 $297,809 Accumulated depreciation and amortization 193,029 180,867 168,236 ------------------------------------------------ $155,374 $137,584 $129,573 ================================================ 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. 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.
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 ================================================ 43
Natural Gas Oil -------------------------------- (MMcf) (MBbl) 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 ================================ 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 11th day of December 2001. QUESTAR MARKET RESOURCES, INC. (Registrant) By /s/ G. L. Nordloh ----------------------------------- G. L. Nordloh President & 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. 44
/s/ G. L. Nordloh President & Chief Executive Officer; - ------------------------ Director (Principal Executive Officer) G. L. Nordloh /s/ S. E. Parks Vice President, Treasurer and Chief - ------------------------ Financial Officer (Principal S. E. Parks Financial Officer) /s/ B. Kurtis Watts Manager, Accounting - ------------------------ (Principal Accounting Officer) B. Kurtis Watts *R. D. Cash Chairman of the Board; Director *Teresa Beck Director *Patrick J. Early Director *G. L. Nordloh Director *Keith O. Rattie Director December 11, 2001 *By /s/ G. L. Nordloh - ------------------- ------------------------------- Date G. L. Nordloh, Attorney in Fact