-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OVCYf3W9NrXOrTPoTh7FP/uJvPUVyY+4EAB71NItOQNZCFkf6kZ7FaQX9fENHerQ QvfT+La0+DbZeFmbR6LyDA== 0000950129-01-504512.txt : 20020413 0000950129-01-504512.hdr.sgml : 20020413 ACCESSION NUMBER: 0000950129-01-504512 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20011214 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MITCHELL ENERGY & DEVELOPMENT CORP CENTRAL INDEX KEY: 0000311995 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 741032912 STATE OF INCORPORATION: TX FISCAL YEAR END: 0131 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-06959 FILM NUMBER: 1814069 BUSINESS ADDRESS: STREET 1: 2001 TIMBERLOCH PL CITY: THE WOODLANDS STATE: TX ZIP: 77380 BUSINESS PHONE: 7133775500 MAIL ADDRESS: STREET 1: P.O. BOX 4000 CITY: THE WOODLANDS STATE: TX ZIP: 77387-4000 10-K405/A 1 h92943a2e10-k405a.txt MITCHELL ENERGY & DEVELOPMENT CORP - AMEND.NO.2 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A AMENDMENT NO. 2 [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2000 COMMISSION FILE NUMBER 1-6959 MITCHELL ENERGY & DEVELOPMENT CORP. (Exact name of registrant as specified in its charter) TEXAS 74-1032912 (State of Incorporation) (I.R.S. Employer Identification No.) 2001 TIMBERLOCH PLACE THE WOODLANDS, TEXAS 77380 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number including area code: (713) 377-5500 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered ------------------- --------------------- Class A Common Stock, $.10 Par Value New York and Pacific SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or Section 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of voting stock held by nonaffiliates of the registrant at February 28, 2001 was approximately $1,180,232,000. Shares of common stock outstanding at February 28, 2001.... 49,821,336 DOCUMENTS INCORPORATED BY REFERENCE Portions of the following documents are incorporated by reference into the indicated parts of this report: Annual Report to Stockholders for the year ended December 31, 2000 - Parts I and II. Definitive Proxy Statement to be filed within 120 days after December 31, 2000 - Part III. ================================================================================ FORM 10-K/A AMENDMENT NO. 2 The undersigned registrant hereby amends Unaudited Supplemental Information included in its annual report on Form 10-K for the year ended December 31, 2000. Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized. Mitchell Energy & Development Corp. ----------------------------------- (Registrant) By: /s/ Philip S. Smith ---------------------------------------- Philip S. Smith Senior Vice President - Administration Chief Financial Officer and Principal Accounting Officer Date: December 14, 2001 Mitchell Energy & Development Corp. and Subsidiaries UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION Reserve quantities. Proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions at each year end. Proved developed reserves are expected to be recovered from existing wells using existing equipment and operating methods. Gas and oil reserves included in this Unaudited Supplement Oil and Gas Information section are presented in compliance with Statement of Financial Accounting Standards No. 69 and represent oil and gas reserves derived from the Company's net mineral interest in producing oil and gas properties. The amounts reported separately as Plant NGL Reserves represent NGLs that will be extracted from gas streams contractually committed to company-owned gas processing plants and are included in order to disclose important and useful information related to the gas processing segment. The NGL reserves represent all the NGLs that will be derived by processing natural gas produced from (i) oil and gas properties owned/operated by the Company and (ii) oil and gas properties operated by others whose gas production is tied into the gas processing facilities and contractually purchased, processed and sold by the Company. The following tables summarize changes in the Company's natural gas (gas), crude oil and condensate (oil) and plant NGL reserve quantities during the indicated years and the proved developed reserve quantities at the dates indicated:
2000 1999 1998 -------------------------- -------------------------- -------------------------- Gas Oil Gas Oil Gas Oil Bcfe * (Bcf) (MMBbls) Bcfe * (Bcf) (MMBbls) Bcfe * (Bcf) (MMBbls) ------- ------- -------- ------- ------- -------- ------- ------ -------- PROVED GAS AND OIL RESERVES Beginning balance................... 1,106.5 1,022.8 14.0 973.6 875.2 16.4 881.5 786.1 15.9 Extensions and discoveries.......... 547.5 539.1 1.4 297.0 289.8 1.2 129.1 121.3 1.3 Production marketed................. (123.8) (111.8) (2.0) (101.9) (89.3) (2.1) (105.3) (90.3) (2.5) Production consumed in operations... (4.7) (4.7) -- (4.5) (4.5) -- (3.6) (3.6) -- Purchases in place.................. 4.3 4.3 -- .1 .1 -- 91.2 73.8 2.9 Revisions of previous estimates..... (18.2) (11.6) (1.1) (48.0) (39.9) (1.3) (16.5) (11.1) (.9) Sales in place...................... (3.9) (2.1) (.3) (9.8) (8.6) (.2) (2.8) (1.0) (.3) ------- ------- ---- ------- ------- ---- ------ ----- ---- Ending balance...................... 1,507.7 1,436.0 12.0 1,106.5 1,022.8 14.0 973.6 875.2 16.4 ======= ======= ==== ======= ======= ==== ====== ===== ====
- ------------------------------------------ * Billion cubic feet of gas equivalent using a 6-to-1 conversion factor for oil.
2000 1999 1998 --------------------------- -------------------------- --------------------------- Equity Equity Equity Consol- Partner- Consol- Partner- Consol- Partner- Total idated ships ** Total idated ships** Total idated ships** ------- -------- -------- ------- -------- ------- ------- -------- -------- PROVED PLANT NGL RESERVES (MMBBLS) Beginning balance.................... 179.1 148.8 30.3 115.8 75.9 39.9 130.8 84.5 46.3 Additions............................ 42.9 42.9 -- 28.2 27.1 1.1 13.2 13.2 -- Production........................... (18.2) (17.5) (.7) (16.1) (12.2) (3.9) (15.3) (10.6) (4.7) Purchase (sale) of plant interests... (6.2) 11.4 (17.6) 15.2 15.2 -- 4.1 -- 4.1 Transfer of partnership reserves..... -- 12.1 (12.1) -- 15.2 (15.2) -- -- -- Revisions of previous estimates...... (22.6) (22.7) .1 36.0 27.6 8.4 (17.0) (11.2) (5.8) ----- ----- ----- ----- ----- ----- ----- ----- ---- Ending balance....................... 175.0 175.0 -- 179.1 148.8 30.3 115.8 75.9 39.9 ===== ===== ===== ===== ===== ===== ===== ===== ====
- ------------------------------------------ ** Represents the Company's proportional interest in the reserves of partnerships accounted for using the equity method.
PROVED DEVELOPED RESERVES AT DECEMBER 31 2000 1999 1998 1997 ------- ------ ------- ------- Gas (Bcf) .......................................................... 737.0 667.1 692.3 648.6 ===== ===== ===== ===== Oil (MMBbls)........................................................ 11.4 13.5 15.2 14.7 ===== ===== ===== ===== Plant NGLs (MMBbls) Consolidated .................................................... 115.2 119.3 58.7 72.6 Equity partnerships ............................................. -- 24.4 33.3 45.1 ----- ----- ----- ----- 115.2 143.7 92.0 117.7 ===== ===== ===== =====
Future net cash flows from natural gas and oil reserves. The following tables set forth estimates of the standardized measure of discounted future net cash flows from proved gas and oil reserves at December 31, 2000, 1999 and 1998 and a summary of the changes in those amounts for the years then ended (in millions):
2000 1999 1998 ------ ------ ------ STANDARDIZED MEASURE Future cash inflows................................................................. $12,945 $2,792 $1,769 Future production and development costs............................................. (2,557) (1,455) (1,040) Future income taxes................................................................. (3.547) (374) (147) Discount - 10% annually............................................................. (2,885) (385) (190) ------- ------ ------ $ 3,956 $ 578 $ 392 ======= ====== ====== CHANGES IN STANDARDIZED MEASURE Extensions and discoveries, net of related costs.................................... $ 2,152 $ 188 $ 50 Sales, net of production costs...................................................... (439) (184) (151) Net changes in prices and production costs.......................................... 3,559 340 (352) Accretion of discount............................................................... 74 42 63 Production rate changes and other................................................... (55) (28) 19 Development costs incurred.......................................................... 54 26 25 Purchases in place.................................................................. -- -- 71 Sales in place...................................................................... (12) (13) (2) Revisions of previous quantity estimates............................................ (68) (63) (9) Net changes in future income taxes.................................................. (1,887) (122) 143 ------- ------ ------ $ 3,378 $ 186 $ (143) ======= ====== ======
Future net cash flows from plant NGL reserves. The following tables set forth estimates of the standardized measure of discounted future net cash flows from proved plant NGL reserves at December 31, 2000, 1999 and 1998 and a summary of the changes in those amounts for the years then ended (in millions):
2000 1999 1998 --------------------------- --------------------------- --------------------------- Equity Equity Equity Consol- Partner- Consol- Partner- Consol- Partner- Total idated ships Total idated ships Total idated ships ------- ------- --------- ------- ------- -------- ------- ------- -------- STANDARDIZED MEASURE Future cash inflows.............. $5,533 $5,533 $ -- $2,976 $2,508 $ 468 $1,054 $682 $372 Future production costs.......... (4,026) (4,026) -- (2,281) (1,978) (303) (861) (568) (293) Future income taxes.............. (505) (505) -- (228) (168) (60) (56) (33) (23) Discount - 10% annually.......... (430) (430) -- (202) (153) (49) (58) (35) (23) ------ ------ ----- ------ ------ ----- ------ ---- ---- $ 572 $ 572 $ -- $ 265 $ 209 $ 56 $ 79 $ 46 $ 33 ====== ====== ===== ====== ====== ===== ====== ==== ==== CHANGES IN STANDARDIZED MEASURE Additions, net of related costs.. $ 210 $ 210 $ -- $ 57 $ 54 $ 3 $ 11 $ 11 $ -- Sales, net of production costs... (91) (85) (6) 139 83 56 (95) (83) (12) Net changes in prices and costs.. 480 480 -- (45) (30) (15) (11) (4) (7) Accretion of discount............ 29 29 -- 10 6 4 20 14 6 Purchase/sale of plant interests...................... (51) (4) (47) 30 30 -- 5 -- 5 Transfer of partnership reserves....................... -- 37 (37) -- 30 (30) -- -- -- Revisions of previous quantity estimates............. (111) (111) -- 80 55 25 (16) (9) (7) Other............................ 7 7 -- 9 5 4 (11) (5) (6) Net changes in future income taxes.......................... (166) (200) 34 (94) (70) (24) 37 26 11 ------ ------ ----- ------ ------ ----- ------ ---- ---- $ 307 $ 363 $ (56) $ 186 $ 163 $ 23 $ (60) $(50) $(10) ====== ====== ===== ====== ====== ===== ====== ==== ====
The natural gas quantities reported as gas and oil reserves represent wet gas volumes, including quantities that will be converted to NGLs by processing. As it relates to NGLs to be extracted in processing, the gas and oil future net cash flows include only the leasehold reimbursements for such NGLs; the other cash flows (amounts in excess of the leasehold reimbursements) associated with NGLs to be extracted from the Company's wet gas reserves are included in plant NGL amounts since those cash flows are attributable to the Company's gas processing plants. The future net cash flows from plant NGL reserves represent the net amounts to be derived from gas plant ownership through natural gas purchase and processing agreements. The Company's gas processing affiliate purchases raw natural gas production (including all the liquefiable hydrocarbons contained therein) from producers (both the Company's exploration and production affiliate and third parties) during the term of the purchase and processing agreements. The processing affiliate takes title to the wet gas (including the entrained NGLs) and then processes the gas for the extraction of the NGLs. Generally, under the purchase and processing agreements, the producer is paid for the NGLs associated with its gas under one of two methods. Under one method, reimbursements to the producer are based on the value of the reduction in the heating content (measured in BTUs) of the gas that is attributable to the removal of the NGLs from the gas. This method is sometimes referred to as a "Btu purchase contract" or a "keep whole contract". Under the other method, which is called a "percent of proceeds contract", the producer is paid based on a percentage of the value of NGLs extracted. Regardless of the payment method, settlements to producers are in cash, not product, and title to 100% of the NGLs is assigned to the gas processing affiliate, which bears the risks and rewards of ownership. Such reimbursements - including amounts attributable to the Company's oil and gas leasehold interests that are included in oil and gas future net cash flows - are deducted as production costs in determining future net cash flows from plant NGLs. Under the gas purchase and processing agreements, the Company's gas processing affiliate is generally obligated to gather and compresses the gas from the point of delivery to a central processing plant, to hydrate the gas, and, if necessary, treat the gas for the removal of contaminants such as carbon dioxide and hydrogen sulfide and process the gas for the extraction of NGLs. After the NGLs are removed, the gas processing affiliate compresses the residue natural gas coming out of the plant and markets the residue gas. The NGLs extracted at the plant are a raw mixture of ethane, propane, isobutane, normal butane and natural gasoline which is then separated into individual purity products at an on-site fractionator or sent via a third-party-owned pipeline to a large central fractionator and then sold to wholesale and industrial customers. Of the total remaining natural gas reserves at December 31, 2000, an estimated 843.7 Bcf will be processed at Company plants, including 290.9 Bcf of 2000's natural gas reserve additions from extensions and discoveries. It is estimated that 146.6 Bcf of such reserves and 47.7 Bcf of such reserve additions will be converted by processing into 74.3 MMBbls and 24.1 MMBbls of plant NGLs, respectively. Because of the volatility inherent in prices for natural gas, oil and NGLs and costs to develop reserves, future cash flow estimates such as those included herein can change dramatically over even short periods of time. Future cash flows from plant NGL reserves can also be significantly impacted by changes in the spread between NGL prices and natural gas costs. Except where otherwise specified by contractual agreement, future cash inflows are estimated using year-end prices. Between December 31, 2000 and February 28, 2001, energy prices declined substantially. If the reserves were valued using prices existing on February 28, the standardized measure amounts would total approximately $2,090,000,000 less than the amounts at December 31, 2000. Future production and development cost estimates are based on economic conditions at the respective year ends. Future income taxes are computed by applying applicable statutory tax rates to the difference between the estimated future net revenues and the tax basis of proved oil and gas properties after considering tax credit carryforwards, estimated future percentage depletion deductions and energy tax credits. Reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Because of the aforementioned factors, reserve estimates are generally less precise than other financial statement disclosures. Discounted future cash flow estimates such as those shown herein are not intended to represent estimates of the fair market value of oil and gas properties. Estimates of fair market value also should consider probable reserves, anticipated future oil and gas prices and interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair market value is necessarily subjective and imprecise. Gas and oil related costs and operating results. The following tables set forth capitalized costs at December 31, 2000, 1999 and 1998 and costs incurred and operating results for oil and gas producing activities for the years then ended (in thousands):
2000 1999 1998 ------------- ------------- ----------- CAPITALIZED COSTS Oil and gas properties................................................ $2,034,469 $1,881,846 $1,867,809 Support equipment and facilities...................................... 52,632 50,138 50,670 Accumulated depreciation, depletion and amortization.................. (1,278,545) (1,231,047) (1,217,675) ---------- ---------- ---------- Net capitalized costs................................................. $ 808,556 $ 700,937 $ 700,804 ========== ========== ========== COSTS INCURRED (including exploration expenses and exploratory well impairments of $12,028, $9,022 and $30,488) Property acquisitions Unproved........................................................... $ 16,916 $ 6,450 $ 12,965 Proved............................................................. 1,565 -- 71,708 Exploration........................................................... 15,309 9,646 35,663 Development........................................................... 208,510 101,589 131,395 ---------- ---------- ---------- Costs incurred........................................................ 242,300 117,685 251,731 Support equipment and facilities...................................... 2,727 729 2,972 ---------- ---------- ---------- Capital and exploratory expenditures.................................. $ 245,027 $ 118,414 $ 254,703 ========== ========== ========== OPERATING RESULTS (before charges for general and administrative and interest expense) Production revenues................................................... $ 530,085 $ 252,899 $ 225,835 Other revenues........................................................ 1,143 1,462 1,605 ---------- ---------- ---------- 531,228 254,361 227,440 Less - Production costs Operating expenses.......................................... 62,316 52,044 58,364 Production taxes............................................ 28,520 16,371 16,568 Depreciation, depletion and amortization (including proved-property impairments of $42,250 in 1998).............. 118,112 94,667 142,192 Exploration expenses........................................... 7,216 6,062 25,400 Exploratory well impairments................................... 4,812 2,960 5,088 Other operating costs.......................................... 19,852 11,234 11,702 ---------- ---------- ---------- Segment operating earnings............................................ 290,400 71,023 (31,874) Income taxes.......................................................... 77,032 23,009 (12,197) ---------- ---------- ---------- $ 213,368 $ 48,014 $ (19,677) ========== ========== ==========
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