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 quarterly period ended June 30, 2002 ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. Commission file number 1-10447 CABOT OIL & GAS CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 04-3072771 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 1200 Enclave Parkway, Houston, Texas 77077 (Address of principal executive offices including Zip Code) (281) 589-4600 (Registrant's telephone number) 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 ___ --- As of July 23, 2002, there were 31,792,901 shares of Common Stock, Par Value $.10 Per Share, outstanding. CABOT OIL & GAS CORPORATION INDEX TO FINANCIAL STATEMENTS Part I. Financial Information Page ---- Item 1. Financial Statements Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2002 and 2001 ........................................................... 3 Condensed Consolidated Balance Sheet at June 30, 2002 and December 31, 2001 .............. 4 Condensed Consolidated Statement of Cash Flows for the Three and Six Months Ended June 30, 2002 and 2001 ........................................................... 5 Notes to Condensed Consolidated Financial Statements ..................................... 6 Report of Independent Accountants ........................................................ 12 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .............................................................. 13 Item 3A. Quantitative and Qualitative Disclosures about Market Risk .......................... 21 Part II. Other Information Item 2. Changes in Securities and Use of Proceeds ........................................... 23 Item 4. Submission of Matters to a Vote of Security Holders ................................. 23 Item 6. Exhibits and Reports on Form 8-K .................................................... 24 Signature ......................................................................................... 25 -2- PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) (In Thousands, Except Per Share Amounts) THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------- ------------------------- 2002 2001 2002 2001 ---------- ----------- ----------- ----------- NET OPERATING REVENUES Natural Gas Production ............................ $ 55,300 $ 73,411 $ 101,806 $ 174,136 Brokered Natural Gas .............................. 15,687 27,273 29,385 62,695 Crude Oil and Condensate .......................... 17,348 10,964 31,066 22,520 Change in Derivative Fair Value (Note 8) ......... (564) (4,988) (1,180) 1,211 Other ............................................. 1,813 946 3,580 1,936 --------- ---------- ---------- ---------- 89,584 107,606 164,657 262,498 OPERATING EXPENSES Brokered Natural Gas Cost ......................... 14,581 26,323 26,848 60,479 Direct Operations - Field & Pipeline .............. 11,921 9,650 24,156 17,870 Exploration ....................................... 10,824 14,540 17,880 25,313 Depreciation, Depletion and Amortization .......... 23,453 16,198 46,663 32,089 Impairment of Unproved Properties ................. 2,337 1,482 4,674 2,964 Impairment of Long-Lived Assets ................... -- -- 1,063 -- General and Administrative ........................ 9,572 5,691 15,311 11,638 Taxes Other Than Income ........................... 7,475 6,715 13,627 16,617 --------- ---------- ---------- ---------- 80,163 80,599 150,222 166,970 Gain (Loss) on Sale of Assets .......................... 429 (31) 411 (27) --------- ---------- ---------- ---------- INCOME FROM OPERATIONS ................................. 9,850 26,976 14,846 95,501 Interest Expense ....................................... 6,331 4,704 12,557 9,409 --------- ---------- ---------- ---------- Income Before Income Taxes ............................. 3,519 22,272 2,289 86,092 Income Tax Expense ..................................... 1,398 8,679 966 33,438 --------- ---------- ---------- ---------- NET INCOME ............................................. $ 2,121 $ 13,593 $ 1,323 $ 52,654 ========= ========== ========== ========== Basic Earnings Per Share ............................... $ 0.07 $ 0.46 $ 0.04 $ 1.79 Diluted Earnings Per Share ............................. $ 0.07 $ 0.45 $ 0.04 $ 1.76 Average Common Shares Outstanding ...................... 31,737 29,509 31,671 29,414 The accompanying notes are an integral part of these condensed consolidated financial statements. -3- CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) (In Thousands) JUNE 30, DECEMBER 31, 2002 2001 ------------ ------------ Current Assets Cash and Cash Equivalents ............................................ $ 7,710 $ 5,706 Accounts Receivable .................................................. 52,715 50,711 Inventories .......................................................... 15,151 17,560 Other ................................................................ 11,863 11,010 ----------- ----------- Total Current Assets .............................................. 87,439 84,987 Properties and Equipment, Net (Successful Efforts Method) ................ 974,913 981,338 Other Assets ............................................................. 2,728 2,706 ----------- ----------- $ 1,065,080 $ 1,069,031 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts Payable ..................................................... $ 73,554 $ 79,575 Accrued Liabilities .................................................. 35,947 30,665 ----------- ----------- Total Current Liabilities ......................................... 109,501 110,240 Long-Term Debt ........................................................... 397,000 393,000 Deferred Income Taxes .................................................... 198,522 200,859 Other Liabilities ........................................................ 13,076 18,380 Stockholders' Equity Common Stock: Authorized -- 40,000,000 Shares of $.10 Par Value Issued and Outstanding - 32,094,768 Shares and 31,905,097 Shares in 2002 and 2001, Respectively .................. 3,210 3,191 Additional Paid-in Capital ........................................... 351,561 346,260 Retained Earnings (Accumulated Deficit) .............................. (562) 650 Accumulated Other Comprehensive Income (Loss) (Note 9) ............... (2,844) 835 Less Treasury Stock, at Cost: 302,600 Shares in 2002 and 2001 ................................... (4,384) (4,384) ---------- ----------- Total Stockholders' Equity ........................................ 346,981 346,552 ---------- ----------- $ 1,065,080 $ 1,069,031 =========== =========== The accompanying notes are an integral part of these condensed consolidated financial statements. -4- CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In Thousands) THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------ ------------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income ............................................. $ 2,121 $ 13,593 $ 1,323 $ 52,654 Adjustment to Reconcile Net Income to Cash Provided by Operating Activities: Depletion, Depreciation and Amortization ........... 23,453 16,198 46,663 32,089 Impairment of Unproved Properties .................. 2,337 1,482 4,674 2,964 Impairment of Long-Lived Assets .................... -- -- 1,063 -- Deferred Income Taxes .............................. 422 5,319 (49) 19,107 (Gain) Loss on Sale of Assets ...................... (429) 31 (411) 27 Exploration Expense ................................ 10,824 14,540 17,880 25,313 Change in Derivative Fair Value .................... 564 4,988 1,180 (1,211) Other .............................................. 1,542 602 2,907 1,381 Changes in Assets and Liabilities: Accounts Receivable ................................ (1,080) 15,503 (2,004) 30,036 Inventories ........................................ (3,086) (6,618) 2,409 (3,157) Other Current Assets ............................... 839 4,575 (2,396) (534) Other Assets ....................................... (115) 73 (22) 217 Accounts Payable and Accrued Liabilities ........... 21,216 (11,194) 15,116 8,785 Other Liabilities .................................. (5,129) (1,597) (5,304) (578) ---------- ---------- ---------- ---------- Net Cash Provided by Operating Activities ........ 53,479 57,495 83,029 167,093 ---------- ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures ................................... (30,126) (29,008) (71,188) (63,754) Proceeds from Sale of Assets ........................... 3,445 302 3,443 739 Exploration Expense .................................... (10,824) (14,540) (17,880) (25,313) ---------- ---------- ---------- ---------- Net Cash Used by Investing Activities ................ (37,505) (43,246) (85,625) (88,328) ---------- ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Sale of Common Stock ................................... 3,031 3,182 3,136 7,376 Increase in Debt ....................................... 44,000 54,000 100,000 73,000 Decrease in Debt ....................................... (59,000) (66,000) (96,000) (155,000) Dividends Paid ......................................... (1,271) (1,181) (2,536) (2,354) ---------- ---------- ---------- ---------- Net Cash Provided (Used) by Financing Activities ..... (13,240) (9,999) 4,600 (76,978) ---------- ---------- ---------- ---------- Net Increase in Cash and Cash Equivalents ................. 2,734 4,250 2,004 1,787 Cash and Cash Equivalents, Beginning of Period ............ 4,976 5,111 5,706 7,574 ---------- ---------- ---------- ---------- Cash and Cash Equivalents, End of Period .................. $ 7,710 $ 9,361 $ 7,710 $ 9,361 ========== ========== ========== ========== The accompanying notes are an integral part of these condensed consolidated financial statements. -5- CABOT OIL & GAS CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. FINANCIAL STATEMENT PRESENTATION During interim periods, Cabot Oil & Gas Corporation follows the same accounting policies used in its Annual Report to Stockholders and its Report on Form 10-K filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report to Stockholders when reviewing interim financial results. In management's opinion, the accompanying interim financial statements contain all material adjustments necessary for a fair presentation. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year. Our independent accountants have performed a review of these condensed consolidated interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Section 7 and 11 of the Act. In June 2001, the Financial Accounting Standards Board ("FASB") approved for issuance Statement of Financial Accounting Standards 143, "Asset Retirement Obligations" ("SFAS 143"). SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company will adopt the statement effective no later than January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. At this time, the Company cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations, or cash flows. 2. PROPERTIES AND EQUIPMENT Properties and equipment are comprised of the following: JUNE 30, DECEMBER 31, 2002 2001 ------------- ------------- (In thousands) Unproved Oil and Gas Properties ........................ $ 74,829 $ 70,709 Proved Oil and Gas Properties .......................... 1,434,070 1,400,341 Gathering and Pipeline Systems ......................... 133,901 131,768 Land, Building and Improvements ........................ 4,805 4,674 Other .................................................. 28,458 27,513 ------------ ------------ 1,676,063 1,635,005 Accumulated Depreciation, Depletion and Amortization ... (701,150) (653,667) ------------ ------------ $ 974,913 $ 981,338 ============ ============ -6- 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following: JUNE 30, DECEMBER 31, 2002 2001 ----------- ------------- (In thousands) Accounts Receivable Trade Accounts ............................................ $ 50,171 $ 39,570 Joint Interest Accounts ................................... 5,687 12,889 Current Income Tax Receivable ............................. 1,413 2,662 Other Accounts ............................................ 691 986 ---------- ---------- 57,962 56,107 Allowance for Doubtful Accounts ............................. (5,247) (5,396) ---------- ---------- $ 52,715 $ 50,711 ========== ========== Other Current Assets Commodity Hedging Contracts ............................... $ 844 $ 2,387 Drilling Advances ......................................... 1,951 2,111 Prepaid Balances .......................................... 4,044 2,114 Restricted Cash and Other Accounts ........................ 5,024 4,398 ---------- ---------- $ 11,863 $ 11,010 ========== ========== Accounts Payable Trade Accounts ............................................ $ 23,526 $ 19,914 Natural Gas Purchases ..................................... 7,210 4,559 Royalty and Other Owners .................................. 18,033 11,041 Capital Costs ............................................. 8,630 30,923 Taxes Other Than Income ................................... 2,812 2,686 Drilling Advances ......................................... 4,429 2,627 Wellhead Gas Imbalances ................................... 2,690 2,353 Other Accounts ............................................ 6,224 5,472 ---------- ---------- $ 73,554 $ 79,575 ========== ========== Accrued Liabilities Employee Benefits ......................................... $ 7,465 $ 7,151 Taxes Other Than Income ................................... 13,066 13,623 Interest Payable .......................................... 6,971 6,996 Commodity Hedging Contracts ............................... 5,604 -- Income Taxes Payable ...................................... 882 45 Other Accrued ............................................. 1,959 2,850 ---------- ---------- $ 35,947 $ 30,665 ========== ========== Other Liabilities Postretirement Benefits Other Than Pension ................ $ 1,802 $ 1,689 Accrued Pension Cost ...................................... 2,722 7,280 Taxes Other Than Income and Other ......................... 8,552 9,411 ---------- ---------- $ 13,076 $ 18,380 ========== ========== 4. LONG-TERM DEBT At June 30, 2002, the Company had $127 million outstanding under its credit facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time-to-time on the basis of the projected present value (as determined by the banks' petroleum engineer incorporating certain assumptions provided by the lender) of estimated future net cash flows from proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in December 2003 and is subject to renewal. At June 30, 2002, excess capacity totaled $123 million, or 49% of the total available credit line. -7- In addition to the credit facility, the Company has the following debt outstanding: .. $100 million of 12-year 7.19% Notes to be repaid in five annual installments of $20 million beginning in November 2005 .. $75 million of 10-year 7.26% Notes due in July 2011 .. $75 million of 12-year 7.36% Notes due in July 2013 .. $20 million of 15-year 7.46% Notes due in July 2016 5. EARNINGS PER SHARE Basic earnings per share for the second quarter were based on the quarterly weighted average shares outstanding of 31,737,292 in 2002 and 29,509,047 in 2001. Basic earnings per share for the first six months of the year were based on the year-to-date weighted average shares outstanding of 31,670,874 in 2002 and 29,414,275 in 2001. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. Second quarter common stock equivalents, which include both stock awards and stock options, totaled 457,720 in 2002 and 444,011 in 2001. For the year to date period ended June 30, the common stock equivalents were 429,007 in 2002 and 439,767 in 2001. Stock awards and stock options excluded from the calculation of diluted earnings per share because the effect was antidilutive were 1,168,871 and 781,360 for the second quarter of 2002 and 2001, respectively and 1,197,584 and 785,604 for the year to date periods ended June 30, 2002 and 2001, respectively. 6. ENVIRONMENTAL LIABILITY The EPA notified the Company in February 2000 of its potential liability for waste material disposed of at the Casmalia Superfund Site ("Site"), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1992. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for disposal of approximately 4.5 billion pounds of waste would be expected to pay the clean-up costs, which are estimated by the EPA to be $271.9 million. The EPA is also pursuing the owners/operators of the Site to pay for remediation. Documents received by the Company with the notification from the EPA indicate that the Company used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that the Company violated any laws in the disposal of material at the Site. The EPA's actions stem from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site. A group of potentially responsible parties, including the Company, formed a group, called the Casmalia Negotiating Committee ("CNC"). The CNC has had extensive settlement discussions with the EPA and has reached a settlement in principal to pay approximately $27 million toward Site clean up in return for a release from liability. The CNC is currently negotiating a consent decree to memorialize the settlement. On January 30, 2002, the Company placed $1,283,283 in an escrow account. This amount approximates the Company's volumetric share of EPA's cost estimate, plus a 5% premium and is the Company's settlement amount. The escrow account is being funded by the Company and many other CNC members to maximize the likelihood that there will be sufficient funds to fund the settlement agreement upon its completion, which is expected later in 2002. This cash settlement, once released from escrow and paid to the federal government, will resolve all federal claims against the Company for response costs and will release the Company from all response costs related to the Site, except for future claims against the Company for natural resource damage, unknown conditions, transshipment risks and claims by third parties, all of which are expected to be covered by insurance to be purchased by participating CNC members. Responsibility for certain State of California oversight and response costs, while not covered by the settlement or insurance, are not expected to be material. No determination has been made as to whether any insurance arrangement will allow the Company to recover its contribution to the settlement. The Company has established a reserve that management believes to be adequate to provide for this environmental liability based on its estimate of the probable outcome of this matter and estimated legal costs. -8- 7. LITIGATION Wyoming Royalty Litigation In June 2000, two overriding royalty owners sued the Company in Wyoming state court for unspecified damages. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that the Company has deducted improper costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that the Company has failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. In December 2001, fourteen overriding royalty owners sued the Company in Wyoming federal court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification. The Company intends to vigorously defend the case. The Company has a reserve that it believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. While the potential impact to the Company may materially affect quarterly or annual financial results including cash flows, management does not believe it would materially impact the Company's financial position. West Virginia Royalty Litigation In December 2001, two royalty owners sued the Company in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allege that the Company has failed to pay royalty based upon the wholesale market value of the gas produced, that the Company has taken improper deductions from the royalty and has failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. The plaintiffs have also claimed that they are entitled to a 1/8/th/ royalty share of the gas sales contract settlement the Company reached with Columbia in the 1995 Columbia bankruptcy proceeding. The Company has removed the suit to federal court. At a recent status conference, the court set up a schedule for the procedural handling of the plaintiffs' allegations that the case should proceed as a class action. Under this procedure, all discovery and pleadings necessary to place class certification issue before the court are expected to be completed by November 1, 2002. The investigation into this claim continues and it is in the discovery phase. The Company intends to vigorously defend the case. The Company has a reserve that it believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. While the potential impact to the Company may materially affect quarterly or annual financial results including cash flows, management does not believe it would materially impact the Company's financial position. 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At June 30, 2002, the Company had two cash flow hedges open: a series of ten natural gas costless collar arrangements and one crude oil price collar arrangement. At June 30, 2002, a $4.6 million pre-tax unrealized loss was recorded to Other Comprehensive Income along with a $5.6 million derivative liability, a $0.8 million derivative asset, and a non-cash loss of approximately $0.2 million. The ineffective portion of the cash flow hedges was recorded as a component of the Change in Derivative Fair Value on the statement of operations. If commodity prices remain at the current level over the next twelve months, the Company would recognize a loss of approximately $2.8 million ($4.6 million pre-tax) to earnings which was deferred in Accumulated Other Comprehensive Income at June 30, 2002. -9- For 2002, the Company has entered into the following derivative arrangements: .. A series of nine natural gas price collar arrangements covering 16.1 Bcf of production over the period of January through April 2002 with weighted average floor and ceiling prices of $2.68 per Mcf and $3.53 per Mcf. .. A series of ten natural gas price costless collar arrangements covering 18.3 Bcf of production over the period of May through August 2002 with weighted average floor and ceiling prices of $2.54 per Mcf and $3.17 per Mcf. .. A crude oil price collar arrangement covering 1,224 Mbbls of production over the period of March through December 2002 with a $20.00 per barrel floor price and a $23.00 per barrel ceiling price. 9. COMPREHENSIVE INCOME Comprehensive income includes net income and certain items recorded directly to stockholders' equity and classified as Other Comprehensive Income. The following table illustrates the calculation of comprehensive income for the six-month periods ended June 30: SIX MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2001 ---------------------- ---------------------- (In thousands) Accumulated Other Comprehensive Income - Beginning of Period ................................ $ 835 $ -- Net Income .............................................. $ 1,323 $ 52,654 Other Comprehensive Income (net of tax) Cumulative effect of change in accounting principle - January 1, 2001 ..................... -- (2,617) Reclassification adjustment for settled contracts ............................... (1,420) 2,267 Changes in fair value of outstanding hedge positions ................................. (2,259) 13,568 --------- --------- Other Comprehensive Income (Loss) $ (3,679) $ (3,679) $ 13,218 $ 13,218 --------- --------- --------- ---------- Comprehensive Income (Loss) ............................. $ (2,356) $ 65,872 ========= ========= Accumulated Other Comprehensive Income (Loss) - End of Period ...................... $ (2,844) $ 13,218 ========= ========== 10. RETIREMENT OF EXECUTIVE OFFICER In May 2002, Ray Seegmiller retired as the Company's Chairman and Chief Executive Officer. The Company recorded a charge of approximately $3.6 million in the second quarter of 2002 for expenses related to his retirement. The costs include a lump sum cash payment of $0.9 million in recognition of Mr. Seegmiller's employment agreement, his contributions to the Company and in lieu of a 2002 long-term incentive award. Another $1.0 million was expensed as part of his supplemental executive retirement plan benefits. Mr. Seegmiller's previously awarded stock grants and options vested upon retirement, resulting in compensation expense of approximately $1.7 million. -10- 11. ACQUISITION OF CODY COMPANY In August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million comprised of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company's balance sheet effective August 1, 2001 and the results of operations of Cody Company beginning August 1, 2001. The purchase price totaling approximately $315.6 million was allocated to specific assets and liabilities based on certain estimates of fair values resulting in approximately $302.4 million allocated to property and $13.2 million allocated to working capital items. This $315.6 million amount was inclusive of a $78.0 million non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million. The purchase price allocation is preliminary and subject to change as additional information becomes available. Management does not expect the final purchase price allocation to differ materially from the preliminary allocation. The following unaudited pro forma condensed income statement information has been prepared to give effect to the Cody acquisition as if it had occurred on January 1, 2001. The information presented is not necessarily indicative of the results of future operations of the Company. PERIOD ENDING JUNE 30, 2001 QUARTER SIX MONTHS ------------- ------------- (Unaudited) (In thousands) Revenues ......................................... $ 128,557 $ 315,865 Net Income ....................................... $ 15,674 $ 62,792 Per share - Basic ........................... $ 0.50 $ 2.00 Per share - Diluted ......................... $ 0.49 $ 1.97 The results of operations for Cody Company are consolidated with Cabot Oil & Gas Corporation as of August 1, 2001. -11- Report of Independent Accountants To the Board of Directors and Shareholders of Cabot Oil & Gas Corporation: We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the "Company") as of June 30, 2002, and the related condensed consolidated statements of operations and of cash flows for each of the three and six-month periods ended June 30, 2002 and June 30, 2001. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2001, and the related consolidated statements of operations, stockholders' equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 15, 2002 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2001, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Houston, Texas July 26, 2002 -12- ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following review of operations for the first six months of 2002 and 2001 should be read along with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management's Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2001. Overview In the first half of 2002, we produced 45.3 Bcfe, an increase of 27% over the 2001 first half. Natural gas production was 36.9 Bcf, up 6.3 Bcf compared to the 2001 first half. Oil production was up 587 Mbbls, or 74% over the comparable period of last year. Production from the properties acquired with Cody Company contributed 6.6 Bcfe, or 68% of the total 9.7 Bcfe increase in equivalent production, and drilling successes in the Gulf Coast and Eastern regions have contributed the other 3.1 Bcfe, or 32%. Commodity prices were unusually high during the first half of 2001, and our financial results reflected their impact during that period. However, in the first half of 2002, natural gas prices were 51% lower and crude oil prices were 20% lower than in 2001. This lower commodity price environment impacted our financial results. Operating revenues decreased $97.8 million, or 37%, and net income decreased $51.4 million, mainly as a result of this weakened price environment. Operating cash flows were similarly impacted, declining by $84.1 million over last year. Our net income for the first six months of 2002 was $1.3 million, or $0.04 per share, including a $1.2 million non-cash loss realized from the change in the fair value of our derivatives under SFAS 133 (see Note 8), $3.6 million in charges related to the retirement of the Chief Executive officer in May 2002 (see Note 10), and a first quarter $1.1 million property impairment. These selected items decreased after-tax net income by $3.6 million, or $0.12 per share, in the first half of 2002. Excluding these selected items, our 2002 net income was $4.9 million, or $0.16 per share. We drilled 54 gross wells (49 development and 5 exploratory wells) with a success rate of 94% compared to 96 gross wells (83 development and 13 exploratory wells) and an 88% success rate in the first half of 2001. For the full year, we plan to drill 111 gross wells and spend $104.7 million in capital and exploration expenditures compared to 208 gross wells and $453.4 million of capital and exploration expenditures in 2001, including the $231.2 million August 2001 Cody acquisition. Total expenditures were $66.8 million for the first half of 2002, compared to $99.6 million for the comparable period in 2001. We remain focused on our strategies of growth from the drill bit and synergistic acquisitions. Management believes that these strategies are appropriate in the current industry environment, enabling Cabot Oil & Gas to add shareholder value over the long-term. The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 20. Financial Condition Capital Resources and Liquidity Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowings supported by our oil and gas reserves. The level of earnings and cash flows depend on many factors, including the price of crude oil and natural gas and our ability to control and reduce costs. Demand for crude oil and natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. However, demand and prices moved higher strengthening from the summer of 2000 to the spring of 2001 until they began to decline in the late summer and early fall of 2001 and remained low to start 2002. Prices then recovered somewhat during the second quarter of 2002. This is a variation from the cyclical nature of demand that we had seen previously in the market and may be a result of increases in commodity storage levels. Our primary sources of cash during the first six months of 2002 were from funds generated from operations and increased borrowing on our revolving credit facility, as well as proceeds from a sale on non-strategic assets and exercises of stock options. Cash was primarily used to fund exploration and development expenditures and to pay dividends. -13- We had a net cash inflow of $2.0 million in the first six months of 2002. Cash inflows from operating activities totaled $83.0 million in the period. The $89.0 million of capital and exploration expenditures were funded with a combination of the operating cash flows, $4.0 million of increased borrowing on the revolving credit facility, $3.4 million in proceeds from the sale of non-strategic assets, and $3.1 million in proceeds from stock option exercises. SIX MONTHS ENDED JUNE 30, 2002 2001 ---------- ----------- (In millions) Cash Flows Provided by Operating Activities ............$ 83.0 $ 167.1 ======== ======== Cash flows from operating activities in the 2002 first half were $84.1 million lower than the corresponding period of 2001 primarily due to lower natural gas and oil prices and less favorable changes in working capital. SIX MONTHS ENDED JUNE 30, 2002 2001 --------- ----------- (In millions) Cash Flows Used by Investing Activities ................$ (85.6) $ (88.3) ======== ======== Cash flows used by investing activities in the first half of 2002 were primarily a result of capital and exploration expenditures of $89.0 million. This amount was partially offset by $3.4 million in proceeds from the sale of non-strategic assets. A portion of the 2002 cash spending related to the 2001 capital program as certain 2001 projects were completed in the first quarter of 2002. Cash flows used by investing activities in the first half of 2001 were substantially attributable to capital and exploration expenditures of $89.0 million, partially offset by proceeds from the sale of certain oil and gas properties of $0.7 million. SIX MONTHS ENDED JUNE 30, 2002 2001 --------- ----------- (In millions) Cash Flows Provided (Used) by Financing Activities .....$ 4.6 $ (77.0) ======== ======== Cash flows provided by financing activities in the first six months of 2002 consist primarily of $4.0 million in increased borrowings on the revolving credit facility and $3.1 million in proceeds from stock option exercises. Cash flows used by financing activities in the first half of 2001 included $82.0 million used to reduce borrowings on our revolving credit facility, partially offset by $7.4 million in proceeds from stock option exercises. The available credit line under our revolving credit facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the bank's petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2003. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance, if necessary, our capital requirements, including acquisitions. Our 2002 interest expense is expected to be approximately $24.9 million, including interest on the $170 million 7.33% weighted average fixed rate notes used to partially fund the acquisition of Cody Company in 2001. In May 2001, a $16 million principal payment was made on the 10.18% Notes. This amount had been reflected as "Current Portion of Long-Term Debt" on the balance sheet. Additionally, the final $16 million payment on these notes that was due in May 2002 was paid in May 2001 using existing capacity on the revolving credit agreement. -14- Capitalization Our capitalization information is as follows: JUNE 30, DECEMBER 31, 2002 2001 ------------ ------------ (In millions) Debt ..................................$ 397.0 $ 393.0 Stockholders' Equity (1) .............. 347.0 346.6 -------- -------- Total Capitalization ..................$ 744.0 $ 739.6 ======== ======== Debt to Capitalization ................ 53.4% 53.1% /(1)/ Includes common stock, net of treasury stock. During the first six months of 2002, we paid dividends of $2.5 million on the Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company. Capital and Exploration Expenditures On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations, and budget such capital expenditures based upon projected cash flows for the year. The following table presents major components of capital and exploration expenditures: SIX MONTHS ENDED JUNE 30, 2002 2001 ---------- ----------- (In millions) Capital Expenditures Drilling and Facilities ............$ 42.1 $ 52.7 Leasehold Acquisitions ............. 2.5 14.0 Pipeline and Gathering ............. 1.2 1.3 Other .............................. 0.3 0.1 -------- -------- 46.1 68.1 -------- -------- Proved Property Acquisitions ........... 2.8 6.2 Exploration Expenses ................... 17.9 25.3 -------- -------- Total ..............................$ 66.8 $ 99.6 ======== ======== Total capital and exploration expenditures in the first six months of 2002 decreased $32.8 million compared to the same period of 2001, primarily as a result of planned decreases in drilling, leasehold acquisition costs and other capital projects in response to lower commodity prices. We plan to drill 111 gross wells in 2002 compared with 208 gross wells drilled in 2001. This 2002 drilling program includes $104.7 million in total capital and exploration expenditures, down from $453.4 million in 2001, which was our largest capital program to date and included the acquisition of Cody Company. Expected spending in 2002 includes $62.6 million for drilling and dry hole exposure, $7.8 million for lease acquisition and $9.9 million in geological and geophysical expenses. In addition to the drilling and exploration program, other 2002 capital expenditures are planned primarily for production equipment and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. -15- Results of Operations Selected Financial and Operating Data THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------------- ------------------------ 2002 2001 2002 2001 -------- -------- --------- -------- (In millions, except where noted) Net Operating Revenues ................................ $ 89.6 $ 107.6 $ 164.7 $ 262.5 Operating Expenses .................................... 80.2 80.6 150.2 167.0 Operating Income ...................................... 9.9 27.0 14.8 95.5 Interest Expense ...................................... 6.3 4.7 12.6 9.4 Net Income ............................................ 2.1 13.6 1.3 52.7 Earnings Per Share - Basic ............................ $ 0.07 $ 0.46 $ 0.04 $ 1.79 Earnings Per Share - Diluted .......................... $ 0.07 $ 0.45 $ 0.04 $ 1.76 Natural Gas Production (Bcf) Gulf Coast ....................................... 7.7 4.7 15.2 9.5 West ............................................. 6.4 6.4 12.8 12.8 Appalachia ....................................... 4.4 4.2 8.9 8.3 ------- ------- -------- ------- Total Company .................................... 18.5 15.3 36.9 30.6 Natural Gas Production Sales Prices ($/Mcf) Gulf Coast ....................................... $ 3.35 $ 5.16 $ 2.99 $ 6.26 West ............................................. $ 2.40 $ 4.11 $ 2.27 $ 5.10 Appalachia ....................................... $ 3.31 $ 5.44 $ 3.08 $ 5.94 Total Company .................................... $ 2.99 $ 4.79 $ 2.76 $ 5.68 Crude/Condensate Volume (MBbl) .................................... 717 394 1,385 798 Price ($/Bbl) .................................... $ 24.19 $ 27.86 $ 22.43 $ 28.21 Brokered Natural Gas Margin Volume (Bcf) ..................................... 5.9 5.6 9.1 10.4 Margin ($/Mcf) ................................... $ 0.19 $ 0.17 $ 0.28 $ 0.21 The table below presents the after-tax effect of certain selected items on our results of operations for the three- and six-month periods ended June 30, 2002. THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2002 JUNE 30, 2002 ------------------------- ------------------------- Amount per share Amount per share ---------- --------- ----------- --------- (In millions, except per share amounts) Net Income Before Selected Items ....................... $ 4.7 $ 0.15 $ 4.9 $ 0.16 Retirement of Chief Executive Officer ................. (2.2) (0.07) (2.2) (0.07) Impairment of Long-Lived Assets ....................... -- -- (0.7) (0.03) Change in Derivative Fair Value ....................... (0.4) (0.01) (0.7) (0.02) ------- -------- -------- -------- Net Income (as reported) ............................... $ 2.1 $ 0.07 $ 1.3 $ 0.04 ======= ======== ======== ======== The selected items in 2002 include the change in derivative fair value during the six months ended June 30, 2002 (Note 9), charges related to the retirement of the Chief Executive Officer (Note 10) and an impairment taken during the first quarter. -16- The table below presents the after-tax effect of certain selected items on our results of operations for the three- and six-month periods ended June 30, 2001. THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, 2001 JUNE 30, 2001 ------------------------ ----------------------- Amount per share Amount per share --------- --------- --------- --------- (In millions, except per share amounts) Net Income Before Selected Items .............. $ 16.7 $ 0.56 $ 51.9 $ 1.76 Change in Derivative Fair Value .............. (3.1) (0.10) 0.8 0.03 ------- -------- -------- -------- Net Income (as reported) ...................... $ 13.6 $ 0.46 $ 52.7 $ 1.79 ======= ======== ======== ======== The selected item in 2001 is the change in derivative fair value during the six months ended June 30, 2001 related to the adoption SFAS 133 on January 1, 2001. See Note 9 for further discussion. The discussion below excludes the impact of these selected items. Second Quarters of 2002 and 2001 Compared Net Income and Revenues. We reported net income before the selected items in the second quarter of 2002 of $4.7 million, or $0.15 per share. During the corresponding quarter of 2001, we recorded net income excluding selected items of $16.7 million, or $0.56 per share. Operating revenues decreased by $22.4 million and operating income decreased by $18.0 million. Natural gas made up 61%, or $55.3 million, of net operating revenue in 2002. The decrease in net operating revenues was driven by declines in realized commodity prices of 38% for natural gas and 13% for oil. Net income and operating income were similarly impacted by the reduction in commodity prices. The average Gulf Coast natural gas production sales price decreased $1.81 per Mcf, or 35%, to $3.35, decreasing net operating revenues by approximately $13.9 million. In the Western region, the average natural gas production sales price decreased $1.71 per Mcf, or 42%, to $2.40, decreasing net operating revenues by approximately $10.9 million. The average Appalachian natural gas production sales price decreased $2.13 per Mcf, or 39%, to $3.31, decreasing net operating revenues by approximately $9.4 million. The overall weighted average natural gas production sales price decreased $1.80 per Mcf, or 38%, to $2.99, decreasing revenues by $34.2 million. Sales of approximately 70% of our natural gas production for the quarter were covered by a series of natural gas price collars that limited our exposure to movements in commodity prices. However, index prices rose above the ceiling of most of these collars for April through June of 2002. The resulting $3.3 million hedge loss decreased our realized natural gas price for the quarter by $0.18 per Mcf. These collar arrangements cover 149 Mcf of natural gas production per day and remain in place through August 2002. Natural gas production volume in the Gulf Coast region was up 3.0 Bcf, or 64%, to 7.7 Bcf primarily due to the acquisition of Cody Company in August 2001 and new production brought on line in south Texas. Natural gas production volume in the Western region remained at 6.4 Bcf. Natural gas production volume in the Appalachian region was up 0.2 Bcf, or 5%, to 4.4 Bcf. The 3.2 Bcf, or 21%, improvement in total natural gas production increased revenue by $16.1 million in the second quarter of 2002. Brokered natural gas revenue decreased $11.6 million, or 42%, over the second quarter of last year. The sales price of brokered natural gas declined 46%, resulting in a decrease in revenue of $13.1 million, only partially offset by a 6% rise in volume of natural gas brokered this quarter, improving revenues by $1.5 million. After including the related brokered natural gas costs, we realized a net margin of $1.1 million in the second quarter of 2002 and $1.0 million in the comparable quarter of 2001. Crude oil prices decreased $3.67 per Bbl, or 13%, to $24.19, resulting in a decrease to net operating revenues of approximately $2.6 million. In addition, the volume of crude oil sold in the quarter increased by 323 Mbbls, or 82%, to 717 Mbbls, boosting net operating revenues by $9.0 million. This improvement in volume is primarily in the Gulf Coast, which had the benefit of both the August 2001 Cody acquisition and increased production resulting from the 2001 drilling program. -17- Other net operating revenues increased $0.9 million to $1.8 million, both as a result of transportation revenues from a new pipeline in the Rocky Mountains area in 2002 and a decrease in revenue reductions related to payouts on certain fields. Costs and Expenses. Excluding the second quarter 2002 costs incurred in connection with the retirement of the Chief Executive Officer in May 2002, total costs and expenses from operations decreased $4.0 million, or 5%, in the second quarter of 2002 compared to the same period of 2001. The primary reasons for this fluctuation are as follows: . Brokered natural gas cost decreased $11.7 million, or 45%, over the second quarter of last year. The price per Mcf of brokered natural gas decreased 48%, resulting in a decrease to expense of $13.2 million, offset by a 6% increase in volume of natural gas brokered this quarter, increasing costs by $1.5 million. After including the related brokered natural gas revenues, we realized a net margin of $1.1 million in the second quarter of 2002 and $1.0 million in the comparable quarter of 2001. . Direct operating expense increased $2.3 million, or 24%, primarily as a result of costs associated with operating the properties acquired in the Cody acquisition in August 2001. Additionally, operating costs have increased in the Gulf Coast, and to a lesser extent in the Rocky Mountains, where we are have more active properties than in prior quarters. On a per unit basis, operating expense has declined slightly from $0.54 per Mcf in the second quarter of 2001 to $0.52 per Mcf in 2002. . Exploration expense decreased $3.7 million, or 26%, primarily as a result of a $4.9 million decline in dry hole expense from the comparable quarter of 2001. However, geological and geophysical expense, primarily related to the acquisition and processing of seismic data, increased $1.6 million for the quarter. Delay rental payments also declined slightly for the quarter. These changes are consistent with the 2002 budget and the more active 2001 drilling program. . Depreciation, depletion, amortization and impairment expense increased $8.1 million, or 46%, due to the increase in natural gas and oil production in the quarter, as well as the stronger influence of the higher cost Gulf Coast region. Equivalent production in this region has increased 75% from last year's second quarter including amounts attributable to the Cody Company properties. On a per unit basis, DD&A for the second quarter was $1.00 per Mcf in 2001 and $1.13 per Mcf in 2002. . General and administrative costs rose $0.3 million, or 5%, primarily as a result of costs associated with certain non-cash compensation programs. . Taxes other than income rose $0.8 million, or 11%, as a result of higher natural gas and oil production this quarter. Interest expense increased $1.6 million as a result of a higher average level of outstanding debt during the second quarter of 2002 when compared to the second quarter of 2001. The new debt was primarily related to the Cody Company acquisition. Income tax expense decreased $7.6 million due to the comparable decrease in earnings before income tax excluding the selected items. Six Months of 2002 and 2001 Compared Net Income and Revenues. Excluding the selected items, we reported net income in the first half of 2002 of $4.9 million, or $0.16 per share. During the corresponding half of 2001, we had net income excluding selected items of $51.9 million, or $1.76 per share. Operating revenues and operating income decreased $95.4 million and $73.6 million, respectively. Natural gas made up 62%, or $101.8 million, of net operating revenue in 2002. The decrease in net operating revenues was driven primarily by a 51% decrease in the average natural gas price and by a 20% decrease in the average oil price. Net income and operating income were similarly impacted by the decline in commodity prices. The average Gulf Coast natural gas production sales price decreased $3.27 per Mcf, or 52%, to $2.99, decreasing net operating revenues by approximately $49.7 million. In the Western region, the average natural gas production sales price decreased $2.83 per Mcf, or 55%, to $2.27, decreasing net operating revenues by approximately $36.2 million. The average Appalachian natural gas production -18- sales price decreased $2.86 per Mcf, or 48%, to $3.08, decreasing net operating revenues by approximately $25.5 million. The overall weighted average natural gas production sales price decreased $2.92 per Mcf, or 51%, to $2.76, decreasing revenues by $111.4 million. Natural gas production volume in the Gulf Coast region was up 5.7 Bcf, or 60%, to 15.2 Bcf due both to the August 2001 Cody acquisition and to new production brought on line in south Texas. Natural gas production volume in the Western region remained at 12.8 Bcf. Natural gas production volume in the Appalachian region was up 0.6 Bcf, or 7%, to 8.9 Bcf, as a result of an increase in drilling activity in the region during 2001. The 6.3 Bcf, or 21%, rise in total natural gas production increased revenue by $39.1 million in the first half of 2002. The volume of crude oil sold in the first six months of the year increased by 587 Mbbl, or 74%, to 1,385 Mbbl, increasing net operating revenues by $16.6 million. Our increased crude oil sales volumes were primarily from the Gulf Coast region, which had the benefit of both the August 2001 Cody acquisition and increased production resulting from the 2001 drilling program. Crude oil prices decreased $5.78 per Bbl, or 20%, to $22.43, resulting in a decrease to net operating revenues of approximately $8.0 million. Brokered natural gas revenue decreased $33.3 million, or 53%, over the first half of last year. The sales price of brokered natural gas declined 46%, resulting in a decrease in revenue of $25.1 million, combined with a 13% decrease in volume of natural gas brokered this period, which reduced revenues by $8.2 million. After including the related brokered natural gas costs, we realized a net margin of $2.5 million in the first half of 2002 and $2.2 million in the comparable period of 2001. Other operating revenues increased $1.6 million to $3.6 million, both as a result of transportation revenues from a new pipeline in the Rocky Mountains area in 2002 and a decrease in revenue reductions related to payouts on certain fields. Costs and Expenses. Excluding the selected items, total costs and expenses from operations decreased $21.4 million, or 13%, due primarily to the following: . Brokered natural gas cost decreased $33.6 million, or 56%, over the first half of last year. The cost of brokered natural gas dropped 49%, resulting in a decrease to expense of $25.7 million, combined with a 13% decrease in volume of natural gas brokered this quarter, reducing costs by $7.9 million. After including the related brokered natural gas revenues we realized a net margin of $2.5 million in the first half of 2002 and $2.2 million in the comparable period of 2001. . Direct operating expense increased $6.3 million, or 35%, primarily as a result of costs associated with operating the properties acquired in the Cody acquisition in August 2001. Additionally, operating costs have increased in the Gulf Coast, and to a lesser extent in the Rocky Mountains and East, where we are have more active properties than in prior quarters. On a per unit basis, operating expense has increased slightly from $0.50 per Mcf in the first half of 2001 to $0.53 per Mcf in 2002. . Exploration expense decreased $7.4 million, or 29%, primarily as a result of a $5.4 million decline in dry hole expense from the comparable period of 2001. Delay rental payments were $1.0 million lower than in 2001 as wells have been drilled on certain Gulf Coast leases, and due to the fact that certain leases have been released. Geological and geophysical expense, primarily related to the acquisition and processing of seismic data, has decreased $0.5 million for the period. These changes are consistent with the 2002 budget and the more active 2001 drilling program. . Depreciation, depletion and amortization expense increased $16.3 million, or 46%, due to the increase in natural gas and oil production and the stronger influence of the higher cost Gulf Coast region. Equivalent production in this region has increased 69% from last year including amounts attributable to the Cody Company properties. On a per unit basis, DD&A for the first half of the year was $0.98 per Mcf in 2001 and $1.13 per Mcf in 2002. . General and administrative expenses were up slightly from the same period of 2001 excluding the selected item related to the retirement of the Chief Executive Officer in May 2002. . Taxes other than income declined $3.0 million, or 18%, as a result of lower commodity prices realized this year. -19- Interest expense increased $3.1 million as a result of a higher average level of outstanding debt during the first half of 2002 when compared to 2001. The new debt was primarily related to the Cody Company acquisition. Income tax expense decreased $29.8 million due to the comparable decrease in earnings before income tax excluding the selected items. Forward-Looking Information The statements regarding future financial performance and results, market prices, impact of the Cody Company acquisition and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Conclusion Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to market gas on economically attractive terms. The average produced natural gas sales price received in the first six months of 2002 was more than 50% lower than in 2001. The volatility of natural gas prices in recent years remains prevalent in 2002 with wide price swings in day-to-day trading on the NYMEX futures market. Additionally, we have natural gas price collars covering 149 Mcf per day in place through August 2002 and oil price collars covering 4 Mbbls per day in place through December 2002, which both offer some protection against falling prices and remove some benefit of rising prices. Given this continued price volatility, we cannot predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, we cannot assure you that our operations will provide cash sufficient to fully fund our planned capital expenditures. We believe our capital resources, supplemented with external financing, if necessary, are adequate to meet our capital requirements. The preceding paragraph contains forward-looking information. See Forward-Looking Information above. -20- ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price Swaps and Options Hedges on Production - Swaps From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During the first half of 2002, we did not have any natural gas price swaps covering our production. During the first half of 2001, natural gas price swaps covered 498 Mmcf, fixing the sales price of this gas at $3.97 per Mcf. We entered into no oil price swaps covering the first half of 2002 or 2001. The natural gas price swap arrangement that we entered into during the third quarter of 2000 covered a portion of production over the period of October 2000 through September 2003. However, the counterparty declared bankruptcy in December 2001. Based on the terms of the natural gas swap contract, this action resulted in the cancellation of the contract. At the time of cancellation, the contract's value was less than $0.2 million. Hedges on Production - Options In December 2000, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of costless collars. Under the costless collar arrangements, if the index rises above the ceiling price, we pay the counterparty. If the applicable index falls below the floor, the counterparty pays us. The 2001 natural gas price hedges included several costless collar arrangements based on eight price indexes at which we sold a portion of our production. These hedges were in place for the months of February through October 2001 and covered 13,409 Mmcf, or 44%, of our natural gas production for the first half of 2001. All indexes were within the collars during February, however some fell below the floor during the period of March, and all indexes were below the collars in May and June resulting in $4.8 million cash revenue for the first six months of 2001. This gain improved our realized natural gas price for the first half of 2001 by $0.16 per Mcf. Again in December of 2001, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our 2002 production through the use of natural gas price collar arrangements. The natural gas price hedges included several collar arrangements based on nine price indexes at which we sell a portion of our production. These hedges were in place for the months of January through April 2002 and covered 66% of our natural gas production during this period. These collars had a ceiling of $3.53 per Mcf and a floor of $2.68 per Mcf. A premium totaling $0.9 million was paid to purchase these collar arrangements. The indexes were below the floor during February and March during which time we realized a $2.4 million cash gain. However, the indexes rose above the ceiling for April 2002, resulting in a $0.5 million cash loss. The $1.9 million net gain increased our realized gas price for the first six months of 2002 by $0.05 per Mcf. In March 2002, we entered into another series of natural gas collars that cover approximately 77% of our anticipated production during the months of May through August 2002. These collars have a ceiling of $3.17 per Mcf and a floor of $2.54 per Mcf. These natural gas price hedges are similar to those in place during the first four months of 2002, but no premium was paid to enter into these collars. During the first half of 2002, these collars covered 9,067 Mcf of production. The indexes were above the ceiling during May and June and the resulting $2.8 million cash loss reduced our realized gas price for the first six months of 2002 by $0.08 per Mcf. Also in the first quarter of 2002, we entered into a crude oil price collar arrangement that covers approximately 46% of our production during the period from March through December 2002. This collar is based on NYMEX settlements, and has a ceiling of $23.00 per barrel and a floor of $20.00 per barrel. The index was above the ceiling for each month March through June 2002. The resulting $1.4 million cash loss reduced our realized oil price by $0.98 per barrel. -21- In accordance with the latest guidance from the FASB's Derivative Implementation Group, we test the effectiveness of the combined intrinsic and time values and the effective portion of each will be recorded as a component of Other Comprehensive Income. Any ineffective portion will be recorded as a gain or loss in the current period. We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See Forward-Looking Information on page 20. -22- PART II. OTHER INFORMATION ITEM 2. Changes in Securities and Use of Proceeds On July 1, 2002, the Company filed with the Secretary of State of the State of Delaware (i) an amendment to its Certificate of Incorporation and (ii) a Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock. These filings (i) eliminated the Company's Class B Common Stock from the Company's Certificate of Incorporation and changed the name of the Company's Class A Common Stock to simply "Common Stock" and (ii) increased the authorized Common Stock from the 40,000,000 shares of Class A Common Stock previously authorized to 80,000,000 shares of Common Stock, par value $.10 per share. Each issued share of Class A Common Stock prior to the filing of the amendment to the Certificate of Incorporation is now a share of Common Stock. ITEM 4. Submission of Matters to a Vote of Security Holders On May 2, 2002, the Company held its Annual Meeting of Stockholders. At this meeting, the Company's stockholders voted on three matters: .. the election of three directors, .. the approval of the an amendment to the Company's Certificate of Incorporation to eliminate the Class B Common Stock from the Certificate of Incorporation and change the name of the Class A Common Stock to simply "Common Stock" and increase the authorized Common Stock from the 40,000,000 shares of Class A Common Stock currently authorized to 80,000,000 shares of Common Stock, and .. the ratification of the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2002 fiscal year. Of the total outstanding shares, 28,984,156, or 92%, were voted. There were no broker nonvotes. Shareholders voted to re-elect three directors by the following vote: Dan O. Dinges ------------- Votes cast in favor: 28,798,183 Votes withheld: 185,973 Arthur L. Smith --------------- Votes cast in favor: 28,708,781 Votes withheld: 275,375 William P. Vititoe ------------------ Votes cast in favor: 28,795,939 Votes withheld: 188,217 The terms of office of directors Robert F. Bailey, Henry O. Boswell, John G.L Cabot, James G. Floyd, C. Wayne Nance, and P. Dexter Peacock continued beyond the meeting date. Charles P. Siess retired from the Board of Directors immediately following the 2002 Annual Meeting of Stockholders in accordance with the Board's mandatory retirement policy. Ray R. Seegmiller retired from the Board of Directors immediately following the 2002 Annual Meeting of Stockholders in connection with his retirement as Chief Executive Officer. The second item presented for a vote before the stockholders was approval of an amendment to the Company's Certificate of Incorporation with respect to the Common Stock, as described above. Of the votes received, 26,903,764 were in favor of the approval, 2,072,467 were against, and 7,925 abstained. The last item presented for a vote before the stockholders was the ratification of the appointment of PricewaterhouseCoopers LLP, independent certified public accountants, as auditors of the Company for its 2002 fiscal year. Of the votes received, 28,296,119 were in favor of the ratification, 683,910 were against, and 4,127 abstained. -23- ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits 3.1 -- Certificate of Amendment of Certificate of Incorporation (Form 8-K July 2, 2002 Exhibit 3.1). 3.2 -- Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K July 2, 2002 Exhibit 3.2). 15.1 -- Awareness letter of independent accountants. (b) Reports on Form 8-K . A Form 8-K Item 5 was filed on July 2, 2002. The Form 8-K reported that the Company had filed documents with the Secretary of State of the State of Delaware that eliminated the Class B Common Stock from the Certificate of Incorporation and changed the name of the Class A Common Stock to simply "Common Stock" and increased the authorized Common Stock from the 40,000,000 shares of Class A Common Stock previously authorized to 80,000,000 shares of Common Stock. . An 8-K/A was filed on July 3, 2002 to complete a date left blank in the July 2nd Form 8-K. -24- SIGNATURE 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. CABOT OIL & GAS CORPORATION (Registrant) July 26, 2002 By: /s/ Scott C. Schroeder ------------------------------------ Scott C. Schroeder Vice President, Chief Financial Officer and Treasurer (Executive Officer Duly Authorized to Sign on Behalf of the Registrant) By: /s/ Henry C. Smyth ------------------------------------ Henry C. Smyth Vice President and Controller (Principal Accounting Officer) -25-