10-Q 1 h92133e10-q.txt MITCHELL ENERGY & DEVELOPMENT CORP - SEPT 30, 2001 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q [x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED SEPTEMBER 30, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-6959 MITCHELL ENERGY & DEVELOPMENT CORP. (Exact name of registrant as specified in 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 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, and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Shares of common stock outstanding at October 31, 2001........50,234,070 ================================================================================ INDEX

DEFINITIONS. As used herein, "MMBtu" means million British thermal units, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Tcf" means trillion cubic feet, "Bbl" means barrel, "MMBbls" means million barrels, "NGL" or "NGLs" means natural gas liquids and "DD&A" means depreciation, depletion and amortization. Pipeline throughput volumes are based on average energy content of 1,000 Btu per cubic foot. Where applicable, NGL volume, price and reserve information and pipeline throughput include equity partnership interests. Part I - Financial Information ITEM 1. FINANCIAL STATEMENTS REPRESENTATION. The consolidated financial statements of Mitchell Energy & Development Corp. and subsidiaries (the "Company") and related notes included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations, although the Company believes that the disclosures included herein are adequate to make the information presented not misleading. In the opinion of the Company's management, all adjustments - which include only normal and recurring adjustments - necessary for a fair presentation of the financial position and results of operations for the periods presented have been made. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Company's 2000 Annual Report and with the Management's Discussion and Analysis of Financial Position and Results of Operations sections of that and this report. -1- MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (dollar amounts in thousands)

------------ The accompanying notes are an integral part of these financial statements. -2- MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF EARNINGS (in thousands except per-share amounts)

---------- The accompanying notes are an integral part of these financial statements. -3- MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY For the Nine Months Ended September 30, 2001 (dollar amounts in thousands)

---------- The accompanying notes are an integral part of these financial statements. -4- MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)

---------- The accompanying notes are an integral part of these financial statements. -5- MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS September 30, 2001 (1) ACCOUNTING POLICIES Mitchell Energy & Development Corp. and its majority-owned subsidiaries (the "Company") constitute a large independent energy company engaged in the exploration for and development and production of natural gas, natural gas liquids, and crude oil and condensate. The Company also operates natural gas processing plants and gathering systems in Texas and markets the natural gas liquids extracted by its plants and the natural gas throughput of its gathering systems. The consolidated financial statements include the accounts of the Company after elimination of all significant intercompany accounts and transactions. The equity method of accounting is used for investments in 20%-to-50%-owned entities. 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 reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company's exploration and production activities are accounted for using the "successful efforts" method. Long-lived assets held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that an asset's estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount for that asset to its estimated fair value. Impairment assessments for proved oil and gas properties are made on a field-by-field basis. Charges for such impairments, which are included in DD&A expense, totaled $26,029,000 (see Note 9) and none during the nine-month periods ended September 30, 2001 and 2000. Supplemental cash flow information. Short-term investments with maturities of three months or less are considered to be cash equivalents. The reported amounts for proceeds from issuance of debt and debt repayments exclude the impact of borrowings with initial terms of three months or less. Excluding amounts capitalized of $5,847,000 and $1,756,000 respectively, interest paid totaled $22,032,000 and $28,076,000 during the nine- month periods ended September 30, 2001 and 2000. Income taxes paid during the nine-month periods ended September 30, 2001 and 2000 totaled $64,278,000 and $39,135,000. Other than the asset exchange discussed in Note 3, there were no significant non-cash investing or financing activities during the nine-month periods ended September 30, 2001 and 2000. (2) DERIVATIVE FINANCIAL INSTRUMENTS The Company does not hold or issue derivative financial instruments for trading purposes, and it had no open hedge positions at September 30, 2001 or December 31, 2000. As a result, the Company's adoption effective January 1, 2001 of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," had no significant impact on its financial statements. -6- (3) GAS SERVICES PARTNERSHIP INVESTMENTS A summary of the Company's net investments in partnerships at September 30, 2001 and December 31, 2000 and its equity in their pretax earnings for the nine-month periods ended September 30, 2001 and 2000 follows (in thousands):

----------- * Prior to the asset exchange on March 31, 2000. For the applicable periods, the Company's net investment in these entities is reported as property, plant and equipment in the consolidated balance sheets and its equity in their pretax earnings is reported as revenues in the consolidated statements of earnings, each under the gas services caption. On March 31, 2000, the Company exchanged its share of the gathering and processing assets of C&L (non-operated Oklahoma facilities having a net book value of $26,946,000) for Duke Energy Field Services, Inc.'s share of the Company-operated gathering and processing assets of the U.P. Bryan Plant, Austin Chalk and Ferguson-Burleson partnerships and $11,666,000 in cash. Each of the four partnerships distributed all of their operating assets to their partners prior to the exchange and ceased operations. A gain of $4,884,000 was recognized in connection with the exchange. The results of the U.P. Bryan Plant, Austin Chalk and Ferguson- Burleson partnerships began being reported in the Company's consolidated results effective April 1, 2000. For the applicable periods during which the Company held partnership interests in the above-listed entities, summarized earnings information (on a 100% basis) for these entities for the three- and nine-month periods ended September 30, 2001 and 2000 follows (in thousands):

-7- BEF owns a plant located at Mont Belvieu, Texas with the capacity to produce up to 17,000 barrels per day of MTBE, a gasoline additive that reduces emissions. BEF has entered into agreements which require each of the three partners to provide one-third of the plant's isobutane feedstock and one of the partners, Sun Company, Inc., to purchase all of its production for a period extending through September 2004. In March 1999, the governor of California ordered that the use of MTBE be phased out in that state over a four-year period, which ban was later the subject of a legal challenge. In July 1999, a national advisory panel formed by the United States Environmental Protection Agency (the EPA) recommended that the use of MTBE be reduced, and in August 1999 a group of seven northeastern states took steps that would lead to the phase-out of MTBE usage over a three-year period. Restrictions on the use of MTBE could significantly impact future operations of the MTBE plant partially owned by the Company. However, that facility, which was built in the mid 1990s for approximately $225,000,000, was originally designed in a manner that allows it - with moderate expenditures - to be converted to the production of other products. It is not possible at this time to determine the ultimate impact, if any, of this matter on the Company's financial position or results of future operations. (4) LONG-TERM DEBT The Company's debt agreements include unsecured parent company senior notes, the proceeds of which have been advanced to the operating subsidiaries, and bank revolving credit and money market facilities. A summary of outstanding debt at September 30, 2001 and December 31, 2000 follows (in thousands):

The senior notes have no sinking fund requirements and are not redeemable prior to their respective maturity dates. During March and May 2001, the Company purchased senior notes totaling $26,567,000 principal amount at a small premium in the open market. The Company has a five-year $250,000,000 committed bank revolving credit facility that terminates in July 2003, when any amounts then outstanding are payable. Interest rates, which generally are based on spreads over LIBOR, vary based on the highest of the ratings given the Company's senior notes by two specified rating agencies. The Company pays commitment fees on the unused portion of this facility. The bank revolving credit agreement contains certain restrictions which, among other things, limit the payment of dividends by requiring consolidated tangible net worth, as defined, to equal at least $275,000,000 and require the maintenance of a specified consolidated leverage ratio based on earnings before interest, taxes and DD&A and excluding extraordinary, unusual, non-recurring and non-cash charges and credits. Retained earnings available for the payment of cash dividends totaled $548,843,000 at September 30, 2001. -8- (5) INCOME TAXES Income taxes for the nine-month periods ended September 30, 2001 and 2000 consisted of the following (in thousands):

The prior-year tax reversal of $6,293,000 in 2000 related to a legal reorganization of the Company's exploration and production operations that allowed certain previously provided deferred state income taxes to be reversed. Estimated annual tax rates of 33.29% and 34.02% (excluding the impact of the reversal discussed above), respectively, were used in computing the income tax provisions for the nine-month periods ended September 30, 2001 and 2000. Those rates were lower than the 35% statutory Federal income tax rate principally because of Section 29 Federal tax credits (under current law such credits are only available through 2002). (6) COMMITMENTS AND CONTINGENCIES The Company is party to claims and legal actions arising in the ordinary course of its business and to recurring examinations performed by the Internal Revenue Service and other regulatory agencies. While the outcome of all such matters cannot be predicted with certainty, management expects that losses, if any, resulting from their ultimate resolution will not result in charges that are material to the Company's financial position. It is possible, however, that charges could be required that would be significant to the operating results of a particular period. (7) EARNINGS PER SHARE The following table reconciles the weighted average shares outstanding used in the basic and diluted earnings per share computations for the three- and nine-month periods ended September 30, 2001 and 2000 (in thousands):

Excluded from these computations because their effect would have been antidilutive during the three- and nine-month periods ended September 30, 2001 were stock options covering 459,750 shares. (8) STOCK OPTIONS AND BONUS UNITS On May 9, 2001, stock options covering 459,750 shares and 354,200 bonus units were issued to employees by the Company at option/floor prices of $54.00. Like previous grants, these awards vest in three equal annual installments and have ten-year lives. At closing of the merger discussed in Note 10, all outstanding stock options and bonus units are to fully vest and be converted into options to purchase the acquirer's common stock and bonus units redeemable for cash based on the market price of the acquirer's common stock. The number of outstanding options and bonus units will be multiplied by 1.20 and their exercise/floor prices will be divided by 1.20 as part of the conversion. -9- (9) SEGMENT INFORMATION Selected industry segment data for the indicated periods follows (in thousands):

------------------- (a) On accrual basis, including exploratory expenditures. (b) General corporate expenses. -10- The Company's reported business segments are based on the organizational structure used by management to assess performance and make resource allocation decisions. The Company's three principal business segments are: exploration and production, natural gas processing, and gas gathering and marketing. Exploration and production segment operations include the exploration for and development and production of natural gas and oil. Natural gas processing segment operations include the extraction of natural gas liquids from natural gas processed at facilities owned by the Company and third parties. The gas gathering and marketing segment operates Company-owned natural gas gathering systems and markets the natural gas throughput of these systems, including volumes purchased from third parties. During September 2001, the Company recorded an impairment charge of $26,029,000 to reduce the carrying value of a gas field to its estimated fair value (the present value of its estimated future net cash flows). The impairment was primarily the result of recent sharp declines in natural gas prices. After entering into a defense cost reimbursement agreement with an insurance carrier during January 2000, a water well litigation provision reversal of $1,200,000 was recorded during the first quarter of 2000. (10) MERGER AGREEMENT In August 2001, an agreement was executed pursuant to which Devon Energy Corporation (Devon) would acquire the Company for cash and stock. Shareholders of the Company are to receive $31.00 cash and 0.585 of a share of Devon common stock for each of the Company's shares they own. The board of directors of each company has approved the merger. George P. Mitchell, the Company's principal stockholder, and his wife have agreed to vote their shares (approximately 45% of the Company's outstanding stock) in favor of the acquisition by Devon. It is expected that closing of the transaction will occur around year end. -11- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND RESULTS OF OPERATIONS FORWARD-LOOKING INFORMATION All statements included in this Form 10-Q, other than statements of historical fact, are forward-looking statements. These include, but are not limited to, strategies, goals and expectations set forth herein concerning exploration and production and gas services operations and the discussions below concerning the Company's liquidity and capital resources. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurances that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements include the timing and extent of changes in commodity prices for natural gas, NGLs and crude oil; the attainment of forecasted operating levels and reserve replacement; and unexpected changes in competitive and economic conditions, government regulations, technology and other factors. These factors are discussed in greater detail in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2000. LIQUIDITY AND CAPITAL RESOURCES For the eighth consecutive quarter, a new natural gas sales volume record was set by the Company. In spite of this, earnings in 2001's third quarter were well below those of the previous quarter and the prior year's comparable quarter because of sharp declines in prices for natural gas and NGLs and, to a lesser extent, crude oil and condensate. After a non-cash impairment charge that reduced net earnings by $16.9 million, third quarter earnings of $10.5 million ($.21 per diluted share) were down from the $74.4 million ($1.48 per diluted share) of the comparable prior-year period, which included a $6.3 million reversal of prior years' deferred income taxes. Excluding the unusual items, third quarter net earnings were $27.4 million ($.54 per share) in 2001 versus $68.1 million ($1.35 per share) in 2000. While the Company's earnings and cash flows are affected by many factors, energy prices are clearly one of the most significant. The following table shows the Company's quarterly average sales prices for the first three quarters of 2001 and the two prior years:

* The Company's average natural gas prices are determined by dividing its reported natural gas revenues by wet gas volumes. Reported gas revenues include proceeds received from sales of gas plus leasehold reimbursements from processors (including the Company) for gas that is converted to NGLs. During 1998, oil and NGL prices were at low points not seen since 1986 because of rising worldwide oil production during a period of relatively weak demand and unusually high inventory levels. OPEC and other countries adopted lower oil production targets during 1999, and as a result excess inventories were worked down and prices for oil and NGLs rose steadily. This strengthening continued in 2000, and the Company's average prices in the fourth quarter exceeded $30.00 per barrel for oil and $25.00 per barrel for NGLs. In response to an economic slowdown in the United States, demand for and prices of oil and NGLs have fallen during 2001. -12- After beginning the year at extremely low levels, natural gas prices moved upward during 1999. Due to reduced deliverability, low storage levels and strong demand, gas prices strengthened considerably in 2000, rising to the $10.00 per Mcf level late in December 2000. After averaging $9.42 per Mcf in January 2001, the Company's average natural gas sales price fell to $6.03 per Mcf in February and $5.13 in March resulting in an average first quarter price of $6.87 per Mcf. Prices continued to fall in the second and third quarters because of small increases in supply and decreases in demand resulting from the economic downturn mentioned in the previous paragraph. These factors combined to rebuild natural gas inventories and push prices lower. The Company has major ongoing development drilling and well recompletion programs in the Barnett Shale area of North Texas. These programs, which benefit from the use of light sand fracture technology, have significantly expanded the economically developable area. As a result of this and other successful development drilling, the Company added 580 Bcfe to its gas and oil reserves in June 2001. At June 30, 2001, estimated proved reserves were 38% higher than at the beginning of the year. Primarily because of its success in the Barnett, the Company's natural gas sales have risen sharply in recent periods. Such sales averaged a record 419.5 MMcf per day in 2001's third quarter, 31.2% and 4.0%, respectively, above the levels achieved during last year's third quarter and this year's second quarter. The Company expects to drill approximately 300 wells in the Barnett in 2001, up from 142 in 2000 and 66 in 1999. Eighteen rigs are working in the Barnett, a level that the Company now expects to maintain rather than expanding to the previously announced 20-rig program. The table which follows shows the Company's quarterly natural gas sales volumes over the past eight quarters and the quarter-to-quarter percentage growth in such sales:

The Company's production growth is being achieved almost exclusively through low-risk development drilling which is economic even at the recent low energy prices. With an estimated inventory at June 30, 2001 of almost 3,000 undrilled locations (80% of which are in the Barnett) and an ongoing 18-rig program in the Barnett, the Company expects to exceed its previously announced 20% compounded annual growth target for natural gas production during the three-year period ending in 2003. This growth can be achieved from currently booked proved reserves. Pilot tests are underway in the Barnett to study reduced well spacing (27 acre versus the current 55). If successful, the result would be an increase in the backlog of undrilled well locations. An exchange of the Company's interests in several Oklahoma systems for Duke Energy's 55% interest in jointly owned processing and gathering assets in the Austin Chalk area of Central Texas was closed on March 31, 2000. As a result, the Company's involvement in the operations of four partnerships ceased, and it now has total ownership and operating control of all its major gas processing and gathering facilities. This provided operating efficiencies and gave the Company more flexibility in using these facilities. -13- The Company's NGL production averaged 55,500 barrels per day in 2001's third quarter. The nine-month average was substantially lower at 52,000 because of an economic decision not to process gas at the Exxon Katy plant in January and February when natural gas costs exceeded the value of NGLs at that plant. After completion of a second expansion in September 2001, the Bridgeport plant is now capable of processing 430 MMcf of natural gas per day and producing 37,000 barrels of NGLs per day. With the Bridgeport expansion on line, the Company's total NGL production averaged 61,500 barrels per day in October 2001. Throughput of the Company's gas gathering systems averaged 926 MMcf per day in 2001's first nine months, up 165 MMcf (21.7%) from the comparable prior-year period. This increase was principally due to the handling of the increased Barnett Shale production and the acquisition of Duke's 55% interest in the Texas Chalk systems effective March 31, 2000. For the third quarter, throughput averaged 979 MMcf per day, up 19.7% from 2000's third quarter. CAPITAL AND EXPLORATORY EXPENDITURES. The 2001 capital budget, which was originally set at $473.4 million, was increased in August to $685 million to provide for expanded activity levels and cost increases for the drilling and completing of wells. The following table compares budgeted capital and exploratory expenditures for 2001 with actual spending during the first nine months (in millions):

Because of the impact of much lower natural gas prices on its cash flows, the Company is taking steps to reduce its capital spending. These include not adding two rigs to increase the Barnett program to 20 as previously planned and substantial reductions during the fourth quarter in the number of rigs working in other areas. With its major North Texas infrastructure projects now nearly complete (except for the previously announced third expansion of the Bridgeport plant), gas services' spending will be substantially lower going forward. FINANCING MATTERS. Cash provided by operating activities totaled $483.1 million during the first nine months of 2001. This was sufficient to cover most of the period's $503.8 million of cash used for investing activities. Borrowings were used to fund a portion of this spending. Contributing to the cash provided by operating activities was an energy-price-related reduction in trade receivables of $114.7 million which was partially offset by a $61.9 million price-related reduction in oil and gas proceeds payable and a $24.2 million Federal income tax receivable. The tax receivable, which cannot be recouped before 2002, arose because tax deposits based on annualized taxable income early in 2001 now exceed the estimated liability for the full year. Long-term debt totaled $333.8 million at September 30, 2001, up from $300.3 million at the beginning of the year. Such debt comprised 28.8% of total debt plus stockholders' equity at September 30, 2001, down from 32.6% at the beginning of the year. The Company has a $250 million bank revolving credit facility. At September 30, 2001, $190 million was available under this facility. This should be more than adequate to provide for the Company's financing needs prior to expected closing around the end of this year of the pending transaction with Devon Energy Corporation. -14- DISCLOSURES ABOUT MARKET RISK. The Company's major market risk exposure involves prices for crude oil, natural gas and NGLs. Realized prices for these products are driven primarily by prevailing world crude oil prices and domestic natural gas prices. Such prices historically have been volatile (as shown by the table on page 12), and this is expected to continue. In general, a $1.00 change in the per-barrel price of oil, together with an equivalent change in the prices for natural gas and NGLs based on Btu content (16.7 cents per Mcf for gas and 67 cents per barrel for NGLs), changes the Company's annual segment operating earnings and cash flows by approximately $35 million and its after-tax annual net earnings by almost $23 million (based on average operating levels and production volumes projected for the last half of 2001). The Company is partially hedged with respect to natural gas prices since besides being a seller it also purchases gas in connection with its gas processing operations (such purchases recently have approximated 25% of gas sales). Since it has this "physical" hedge, the Company rarely enters into financial hedging transactions to manage its exposure to price fluctuations. It does not hold or issue derivative instruments for trading purposes. The Company had no open hedge positions at September 30, 2001 or December 31, 2000. The Company's exposure to changing interest rates is limited since all but $60 million of its outstanding debt at September 30, 2001 consisted of senior notes with fixed interest rates. OPERATING STATISTICS Certain operating statistics (including, where applicable, proportional interests in equity partnerships) for the three- and nine-month periods ended September 30, 2001 and 2000 follow:

-15- RESULTS OF OPERATIONS - NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 2000 Net earnings for the nine-month periods ended September 2001 and 2000 are summarized in the table which follows. The Company's net earnings for 2001's first nine months totaled $211.4 million, versus the $161.8 million of the comparable prior-year period. Excluding the effects of unusual items, net earnings totaled $228.3 million, versus $151.6 million. The principal reasons for the earnings increase were steadily rising natural gas sales volumes and higher prices for natural gas during the first half of the year. The following table and discussion identify and explain the major increases (decreases) in earnings (in millions):

---------- * Includes general and administrative expense and other expense. EXPLORATION AND PRODUCTION OVERVIEW Exclusive of unusual items, exploration and production segment operating earnings of $318.3 million were $148.0 million above those of the comparable prior-year period, principally due to increased natural gas sales volumes and higher prices for natural gas during the first half of the year. -16- INCREASED NATURAL GAS SALES VOLUMES ($91.3 MILLION INCREASE). Natural gas sales averaged 397.5 MMcf per day during the nine-month period, 35.3% above the 293.7 MMcf per day of the prior-year period, increasing segment operating earnings by $91.3 million. The volume increases were principally attributable to the ongoing drilling and rework programs in the Barnett Shale in North Texas and exploratory success and follow-up drilling in the Lake Creek, North Needville and Personville fields. HIGHER NATURAL GAS SALES PRICE ($76.1 MILLION INCREASE). The Company's natural gas sales price averaged $4.69 per Mcf during the first nine months of 2001, $.97 (26.1%) above the prior-year period's $3.72, increasing segment operating earnings by $76.1 million. INCREASED OPERATING EXPENSES ($10.3 MILLION DECREASE). Exploration and production operating expenses were $10.3 million higher during the first nine months of 2001 primarily because of the larger number of wells being operated in 2001 and increased property taxes. GAS SERVICES OVERVIEW Exclusive of unusual items in the prior period, gas services segment operating earnings declined $38.6 million to $63.7 million in 2001's first nine months. While higher volumes and margins pushed natural gas gathering and marketing margins $5.7 million higher, these were more than offset by price-related earnings reductions for gas processing operations ($25.0 million) and increased operating expenses ($17.8 million). PRICE-RELATED DECREASE IN NGL MARGINS ($25.0 MILLION DECREASE). The average price for NGLs produced during the first nine months of 2001 of $19.55 per barrel was 7% below the prior-year period's $21.02, reducing NGL revenues by $23.0 million. Higher natural gas prices pushed gas shrinkage costs up substantially in 2001; however, the impact of this was almost entirely offset by a price-related increase in certain plants' proceeds from residue gas sales and reduced producer settlement costs due to 2001's lower NGL prices. Net feedstock costs rose by $2.0 million during the 2001 period which when added to the NGL revenue decrease resulted in a $25.0 million price-related decrease in NGL margins. HIGHER GAS GATHERING AND MARKETING MARGINS ($5.7 MILLION INCREASE). These activities generally benefit from increases in natural gas prices. Accordingly, margins were higher in 2001, particularly during the first quarter when gas prices were very high. Margins also benefited from throughput growth, which occurred primarily because of the acquisition of a 55% interest in certain Texas Chalk systems on March 31, 2000 and growth in North Texas volumes resulting from ongoing increases in the Company's Barnett Shale natural gas production. INCREASED OPERATING EXPENSES ($17.8 MILLION DECREASE). Gas Services operating expenses rose principally because of volume-related increases in North Texas and the above-mentioned acquisition of a 55% interest in the Texas Chalk systems on March 31, 2000. Also contributing to this were maintenance expenses incurred at the Bridgeport plant early in 2001 when an expansion train was tied-in. OTHER DECREASED BONUS UNIT EXPENSE ACCRUALS ($11.5 MILLION INCREASE). Bonus unit expense accruals totaled $.2 million during the first nine months of 2001, down from $11.7 million during the comparable period of the prior year, increasing pretax earnings by $11.5 million. The expense accrual in 2001 resulted from the vesting of outstanding bonus units and exercises at the high end of the period's price range. These slightly more than offset the impact of a decline in the market price of the Company's common stock to $50.12 at September 30, 2001 from $61.25 at December 31, 2000. Prices at the comparable dates in the prior year were $46.63 and $21.56, respectively. REDUCTION IN INTEREST EXPENSE INCURRED ($5.6 MILLION INCREASE). This favorable variance was primarily due to the termination in December 2000 of an accounts receivable sales program and a lower average debt balance during the first nine months of 2001 ($305.8 million versus $343.1 million). -17- RESULTS OF OPERATIONS - THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 2000 Net earnings for the three-month periods ended September 2001 and 2000 are summarized in the table which follows. The Company's net earnings for 2001's third quarter were $10.5 million, versus the $74.4 million of the comparable prior-year period. Excluding the effects of unusual items, after-tax earnings totaled $27.4 million, versus $68.1 million. Lower energy prices was the principal cause of the quarter-to-quarter earnings decline. The following table and discussion identify and explain the major increases (decreases) in earnings (in millions):

----------- * Includes general and administrative expense and other expense. EXPLORATION AND PRODUCTION OVERVIEW Excluding the proved property impairment, exploration and production segment operating earnings for the third quarter of 2001 of $44.6 million were $39.6 million below those of the prior year's comparable period as natural gas sales price declines overwhelmed the substantial earnings increases attributable to 31% production growth. -18- INCREASED NATURAL GAS SALES VOLUMES ($14.3 MILLION INCREASE). Natural gas sales averaged 419.5 MMcf per day during 2001's third quarter, 31.2% above the 319.7 MMcf of the comparable prior-year period, increasing operating earnings by $14.3 million. LOWER NATURAL GAS SALES PRICE ($43.7 MILLION DECREASE). During the third quarter of 2001, the Company's natural gas sales price averaged $2.94 per Mcf, $1.56 (34.7%) below the prior period's $4.50, reducing operating earnings by $43.7 million. LOWER OIL AND CONDENSATE SALES PRICE ($2.5 MILLION DECREASE). The Company's sales price for oil and condensate averaged $24.89 per barrel during 2001's third quarter, down $5.40 (17.8%) from the prior-year period's $30.29, reducing operating earnings by $2.5 million. GAS SERVICES OVERVIEW Gas services segment operating earnings during 2001's third quarter of $11.1 million were $22.6 million below the $33.7 million of the prior-year period. Price-related decreases in NGL and gas gathering and marketing margins and volume-related increases in operating expenses were the primary causes of this decline. The impact of these unfavorable variances was offset somewhat by higher NGL production volumes. INCREASED NGL PRODUCTION VOLUMES ($3.1 MILLION INCREASE). NGL production volumes averaged 55,500 barrels per day during 2001's third quarter, up 6.1% above the corresponding prior-year period, increasing operating earnings by $3.1 million. The volume growth, which occurred primarily at the Company's Bridgeport plant, was principally the result of continuing increases in Barnett Shale natural gas production. PRICE-RELATED DECREASE IN NGL MARGINS ($9.2 MILLION DECREASE). The average price for NGLs produced during the current quarter of $15.67 per barrel was $6.53 (29.4%) below the $22.20 of the comparable prior-year quarter, reducing NGL revenues by $31.1 million. The impact of lower natural gas and NGL prices during the current period on gas shrinkage and producer settlement costs, coupled with the impact of a sharp rise in natural gas prices during the prior-year period, resulted in a period-to-period reduction in feedstock costs of $21.9 million, netting to a $9.2 million price-related decrease in NGL margins. NGL MARKETING ACTIVITIES ($5.8 MILLION DECREASE). The Company's operations include the purchase and resale of NGLs. The results of these activities are impacted by fluctuations in NGL prices, increasing with price rises and decreasing with declines. This unfavorable variance is primarily the result of declines in NGL prices in 2001's period versus increases in 2000. LOWER GAS GATHERING AND MARKETING MARGINS ($7.2 MILLION DECREASE). Gas gathering and marketing margins were $7.2 million lower in the 2001 period. A substantial portion of the natural gas supply costs of these activities is based on beginning-of-the-month market index prices and accordingly, declining natural gas prices caused profit margins to decrease in 2001. Conversely, rising natural gas prices during the corresponding quarter of the prior year increased margins during that period. OTHER DECREASED BONUS UNIT EXPENSE ACCRUALS ($3.6 MILLION INCREASE). Bonus unit expense accruals during the third quarter of 2001 totaled $4.3 million compared with $7.9 million in the comparable prior-year period, resulting in a favorable earnings variance of $3.6 million. The price of the Company's common stock rose $3.52 per share (to $50.12 at September 30, 2001 from $46.60 at June 30, 2001) versus $14.50 (to $46.63 from $32.13) during the prior-year quarter. REDUCTION IN INTEREST EXPENSE INCURRED ($1.5 MILLION INCREASE). The $1.5 million decrease in interest expense was primarily due to the December 2000 termination of an accounts receivable sales program and to a lower effective interest rate during the third quarter of the current year. -19- Part II - Other Information ITEM 1. LEGAL PROCEEDINGS No material legal proceedings were pending at September 30, 2001. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits No exhibits are filed with this report. (b) On August 14, 2001, the Company filed a Form 8-K reporting the execution of an Agreement and Plan of Merger providing for the merger of the Company into Devon Newco Corporation. -20- SIGNATURES Pursuant to the requirements 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. MITCHELL ENERGY & DEVELOPMENT CORP. (Registrant) Dated: November 13, 2001 By /s/ Philip S. Smith -------------------------------------------- Philip S. Smith Senior Vice President - Administration and Chief Financial Officer

MITCHELL ENERGY & DEVELOPMENT CORP 10-Q