-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DWhqRrcWeMj72WXISSBnxIPj4ez39VsWmtewVwc9AqSEYDGSSEF7BrDHKYzL2Uti z3z3wfVwQOmxwhqNmB0qQA== 0001193125-03-002831.txt : 20030430 0001193125-03-002831.hdr.sgml : 20030430 20030430165008 ACCESSION NUMBER: 0001193125-03-002831 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030430 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CABOT OIL & GAS CORP CENTRAL INDEX KEY: 0000858470 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 043072771 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-10447 FILM NUMBER: 03673588 BUSINESS ADDRESS: STREET 1: 1200 ENCLAVE PARKWAY CITY: HOUSTON STATE: TX ZIP: 77077 BUSINESS PHONE: 2815894600 10-Q 1 d10q.txt FORM 10-Q 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 March 31, 2003 [_] 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 ___ --- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No ___ --- As of April 28, 2003, there were 32,188,413 shares of Common Stock, Par Value $.10 Per Share, outstanding. -1- 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 Months Ended March 31, 2003, and 2002 ............................................................. 3 Condensed Consolidated Balance Sheet at March 31, 2003, and December 31, 2002 ................ 4 Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2003, and 2002 ............................................................. 5 Notes to the Condensed Consolidated Financial Statements ..................................... 6 Report of Independent Accountant's Review of Interim Financial Information ................... 17 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .................................................................. 18 Item 3A. Quantitative and Qualitative Disclosures about Market Risk .............................. 26 Item 4. Controls and Procedures ................................................................. 28 Part II. Other Information Item 6. Exhibits and Reports on Form 8-K ........................................................ 29 Signature ............................................................................................. 30 Certifications ........................................................................................ 31
-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 MARCH 31, --------------------------------------- 2003 2002 --------------- ---------------- NET OPERATING REVENUES Natural Gas Production ................................................... $ 78,173 $ 46,506 Brokered Natural Gas ..................................................... 31,850 13,698 Crude Oil and Condensate ................................................. 23,174 13,718 Change in Derivative Fair Value (Note 8) ................................. (544) (616) Other .................................................................... 3,263 1,767 --------------- ---------------- 135,916 75,073 OPERATING EXPENSES Brokered Natural Gas Cost ................................................ 28,261 12,267 Direct Operations - Field and Pipeline ................................... 10,926 12,235 Exploration .............................................................. 13,391 7,056 Depreciation, Depletion and Amortization ................................. 23,507 23,210 Impairment of Unproved Properties ........................................ 2,337 2,337 Impairment of Long-Lived Assets (Note 11) ................................ 87,926 1,063 General and Administrative ............................................... 6,595 5,739 Taxes Other Than Income .................................................. 10,224 6,152 --------------- ---------------- 183,167 70,059 Gain (Loss) on Sale of Assets ............................................. 560 (18) --------------- ---------------- INCOME (LOSS) FROM OPERATIONS ............................................. (46,691) 4,996 Interest Expense and Other ................................................ 5,625 6,226 --------------- ---------------- Loss Before Income Taxes .................................................. (52,316) (1,230) Income Tax Benefit ........................................................ (19,940) (432) --------------- ---------------- NET LOSS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE .................... (32,376) (798) CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 12) .......................... (6,847) - --------------- ---------------- NET LOSS .................................................................. $ (39,223) $ (798) =============== ================ Basic Loss Per Share - Before Cumulative Effect of Accounting Change ...... $ (1.02) $ (0.03) Diluted Loss Per Share - Before Cumulative Effect of Accounting Change .... $ (1.02) $ (0.03) Basic Loss Per Share - Cumulative Effect of Accounting Change............. $ (0.21) $ - Diluted Loss Per Share - Cumulative Effect of Accounting Change............ $ (0.21) $ - Basic Loss Per Share ...................................................... $ (1.23) $ (0.03) Diluted Loss Per Share .................................................... $ (1.23) $ (0.03) Average Common Shares Outstanding ......................................... 31,837 31,604
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, except share amounts)
MARCH 31, DECEMBER 31, -------------- -------------- 2003 2002 -------------- -------------- ASSETS Current Assets Cash and Cash Equivalents .................................... $ 1,223 $ 2,561 Accounts Receivable .......................................... 108,470 70,028 Inventories .................................................. 9,656 15,252 Other ........................................................ 5,480 5,280 -------------- -------------- Total Current Assets ...................................... 124,829 93,121 Properties and Equipment, Net (Successful Efforts Method) ........ 881,783 971,754 Other Assets ..................................................... 7,214 7,013 -------------- -------------- $ 1,013,826 $ 1,071,888 ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts Payable ............................................. $ 88,910 $ 73,578 Accrued Liabilities .......................................... 70,785 48,312 -------------- -------------- Total Current Liabilities ................................. 159,695 121,890 Long-Term Debt ................................................... 338,000 365,000 Deferred Income Taxes ............................................ 161,641 200,207 Other Liabilities ................................................ 55,452 34,134 Stockholders' Equity Common Stock: Authorized -- 80,000,000 Shares of $.10 Par Value Issued and Outstanding -- 32,160,913 Shares and 32,133,118 Shares in 2003 and 2002, Respectively .......... 3,216 3,213 Additional Paid-in Capital ................................... 353,963 353,093 Retained Earnings (Accumulated Deficit) ...................... (28,822) 11,674 Accumulated Comprehensive Loss (Note 9) ...................... (24,935) (12,939) Less Treasury Stock, at Cost: 302,600 Shares in 2003 and 2002 ........................... (4,384) (4,384) -------------- -------------- Total Stockholders' Equity ................................ 299,038 350,657 -------------- -------------- $ 1,013,826 $ 1,071,888 ============== ==============
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 MARCH 31, --------------------------------------- 2003 2002 -------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES Net Loss ..................................................... $ (39,223) $ (798) Adjustment to Reconcile Net Income to Cash Provided by Operating Activities: Cumulative Effect of Accounting Change ................. 6,847 - Depletion, Depreciation and Amortization ............... 23,507 23,210 Impairment of Undeveloped Leasehold .................... 2,337 2,337 Impairment of Long-Lived Assets ........................ 87,926 1,063 Deferred Income Tax Expense ............................ (27,010) (471) (Gain) Loss on Sale of Assets .......................... (560) 18 Exploration Expense .................................... 13,391 7,056 Change in Derivative Fair Value ........................ 544 616 Other .................................................. (139) 1,364 Changes in Assets and Liabilities: Accounts Receivable .................................... (38,442) (924) Inventories ............................................ 5,596 5,495 Other Current Assets ................................... (621) (3,235) Other Assets ........................................... (201) 93 Accounts Payable and Accrued Liabilities ............... 22,988 (6,100) Other Liabilities ...................................... 2,607 (175) -------------- -------------- Net Cash Provided by Operating Activities ........... 59,547 29,549 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures ......................................... (21,321) (41,062) Proceeds from Sale of Assets ................................. 1,602 (2) Exploration Expense .......................................... (13,391) (7,056) -------------- -------------- Net Cash Used by Investing Activities ............... (33,110) (48,120) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt ............................................. 64,000 56,000 Decrease in Debt ............................................. (91,000) (37,000) Sale of Common Stock ......................................... 498 105 Dividends Paid ............................................... (1,273) (1,264) -------------- -------------- Net Cash Provided (Used) by Financing Activities .... (27,775) 17,841 -------------- -------------- Net Decrease in Cash and Cash Equivalents ........................ (1,338) (730) Cash and Cash Equivalents, Beginning of Period ................... 2,561 5,706 -------------- -------------- Cash and Cash Equivalents, End of Period ......................... $ 1,223 $ 4,976 ============== ==============
The accompanying notes are an integral part of these condensed consolidated financial statements. -5- CABOT OIL & GAS CORPORATION NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. FINANCIAL STATEMENT PRESENTATION During interim periods, Cabot Oil & Gas Corporation (the Company) 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 condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring 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 Sections 7 and 11 of the Act. In June 2001, the FASB approved for issuance Statement of Financial Accounting Standard (SFAS) 143, "Accounting for Asset Retirement Obligations." 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 adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, "Adoption of SFAS 143, Accounting for Asset Retirement Obligations," to the financial statements. In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB Statement 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of this statement did not impact the Company's financial position, results of operations or cash flows. See Note 13, "Stock Based Compensation," to the financial statements. In January 2003, the FASB issued Financial Interpretation 46, "Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51" (FIN 46 or Interpretation). FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, -6- and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time there is only one entity that could potentially be a VIE. The Company is evaluating this potential VIE, in which it has a one percent general partner interest and that holds an interest in the Kurten field, to determine if it is a VIE. However, pursuant to the partnership agreement, the limited partner has elected to liquidate the partnership; it is anticipated that this liquidation will be completed prior to the effective date of the Interpretation. See Note 11 for additional information related to the partnership. 2. PROPERTIES AND EQUIPMENT Properties and equipment are comprised of the following:
MARCH 31, DECEMBER 31, 2003 2002 -------------- -------------- (In Thousands) Unproved Oil and Gas Properties .................................. $ 78,940 $ 76,959 Proved Oil and Gas Properties .................................... 1,494,855 1,459,240 Gathering and Pipeline Systems ................................... 137,546 137,137 Land, Building and Improvements .................................. 4,884 4,884 Other ............................................................ 29,450 29,457 -------------- -------------- 1,745,675 1,707,677 Accumulated Depreciation, Depletion and Amortization ............. (863,892) (735,923) -------------- -------------- $ 881,783 $ 971,754 ============== ==============
Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in Accumulated Depreciation, Depletion and Amortization. Total future plug and abandonment costs of $17.1 million and $1.1 million have been reclassified from Accumulated Depreciation, Depletion and Amortization and Other Accrued Liabilities, respectively, at December 31, 2002, to Other Long-Term Liabilities due to the adoption of SFAS 143 (see Note 12). These reclassifications were made to conform to the current period presentation. See Note 11 for information regarding the impairment on the Kurten Field. -7- 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following:
MARCH 31, DECEMBER 31, 2003 2002 -------------- -------------- (In Thousands) Accounts Receivable Trade Accounts ............................................... $ 106,905 $ 65,796 Joint Interest Accounts ...................................... 4,436 6,601 Current Income Tax Receivable ................................ 2,481 2,479 Other Accounts ............................................... 115 619 -------------- -------------- 113,937 75,495 Allowance for Doubtful Accounts .................................. (5,467) (5,467) -------------- -------------- $ 108,470 $ 70,028 ============== ============== Other Current Assets Commodity Hedging Contracts .................................. $ 213 $ 634 Drilling Advances ............................................ 1,545 558 Prepaid Balances ............................................. 1,867 2,131 Restricted Cash and Other Accounts ........................... 1,855 1,957 -------------- -------------- $ 5,480 $ 5,280 ============== ============== Accounts Payable Trade Accounts ............................................... $ 16,236 $ 13,317 Natural Gas Purchases ........................................ 15,856 6,058 Royalty and Other Owners ..................................... 30,070 20,254 Capital Costs ................................................ 10,928 13,900 Taxes Other Than Income ...................................... 3,760 3,076 Drilling Advances ............................................ 3,336 7,254 Wellhead Gas Imbalances ...................................... 2,280 2,817 Other Accounts ............................................... 6,444 6,902 -------------- -------------- $ 88,910 $ 73,578 ============== ============== Accrued Liabilities Employee Benefits ............................................ $ 5,001 $ 8,751 Taxes Other Than Income ...................................... 13,224 9,887 Interest Payable ............................................. 5,153 7,076 Commodity Hedging Contracts - Short-Term ..................... 37,847 20,680 Other Accrued ................................................ 9,560 1,918 -------------- -------------- $ 70,785 $ 48,312 ============== ============== Other Liabilities Postretirement Benefits Other Than Pension ................... $ 1,900 $ 1,843 Accrued Pension Cost ......................................... 9,055 8,486 Commodity Hedging Contracts - Long-Term ...................... 2,789 - Accrued Plugging and Abandonment Liability ................... 35,687 18,151 Taxes Other Than Income and Other ............................ 6,021 5,654 -------------- -------------- $ 55,452 $ 34,134 ============== ==============
-8- 4. LONG-TERM DEBT At March 31, 2003, the Company had $68 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 bank's petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in October 2006 and is subject to renewal. At March 31, 2003, excess capacity totaled $182 million, or 73% of the total available credit line. 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 first three months of the year were based on the year-to-date weighted average shares outstanding of 31,836,505 in 2003 and 31,603,717 in 2002. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. The computation of diluted earnings per share to determine common stock equivalents includes both stock awards and stock options and did not assume conversion of these instruments due to the antidilutive effect on loss per share. Stock awards and stock options excluded from the calculation of diluted loss per share because the effect was antidilutive were 1,561,973 and 1,755,223 for the first quarter of 2003 and 2002, respectively. 6. ENVIRONMENTAL LIABILITY 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. The Company received documents with the notification from the EPA indicating 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 entered into a consent decree, which will require the CNC to pay approximately $27 million toward Site clean up in return for a release from liability. On January 30, 2002, the Company placed $1,283,283 in an escrow account, representing its volumetric share of the CNC/United States settlement. This cash settlement, once released from escrow and paid to the federal government after the consent decree is entered by the court, 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. Most of the CNC, including the Company, have purchased insurance designed to protect the Company from these liabilities not covered by the consent decree. -9- The State of California, a third party, has asserted a claim against the CNC and other companies alleged to have waste at Casmalia for costs the State incurred and will incur at the site. The CNC has presented the claim to its insurer. The ultimate disposition of this claim is unknown. However, given the size of the State's claim and the number of parties allegedly responsible, the Company's share of this claim is expected to be immaterial. The Company has established a reserve that management believes to be adequate to provide for this environmental liability and related legal costs. 7. COMMITMENTS AND CONTINGENCIES Wyoming Royalty Litigation In June 2000, the Company was sued by two overriding royalty owners 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 improperly deducted 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. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district 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. Although management believes that a number of the Company's defenses are supported by Wyoming case law, a recent letter decision handed down by a state district court in another case does not support certain of the defenses. The decision has not been reduced to a formal order and it is not known what effect, if any, the decision will have on the pending cases. In the Company's federal case, the judge recently agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in these cases. The federal judge refused, however, to certify one question on check stub reporting that had been decided adversely to the Company's position in the state district court letter decision. After the federal judge's refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote. The Company is vigorously defending both cases. The Company has a reserve that management believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of these matters. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position. West Virginia Royalty Litigation In December 2001, the Company was sued by two royalty owners 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 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 have 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 1/8th royalty share of the -10- gas sales contract settlement that the Company reached with Columbia in the 1995 Columbia bankruptcy proceeding. The Company had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court. Discovery and pleadings necessary to place the class certification issue before the court have been ongoing. No trial or dispositive motions dates have been set and limited factual discovery is ongoing. The investigation into this claim continues and it is in the discovery phase. The Company is vigorously defending the case. The Company has reserves it believes are adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact the Company's financial position. Texas Title Litigation On January 6, 2003, the Company was served with Plaintiffs' Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in the surface and minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The trial date of May 19, 2003 has been cancelled and a new trial date has not been set. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $12 million. The carrying value of this property is approximately $35 million. Although the investigation into this claim has just begun, the Company intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome. -11- Lease Commitments The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Leases for the Company's offices in Houston and Denver each run for approximately seven more years. Rent expense under such arrangements totaled $1.9 million and $2.1 million for the three months ended March 31, 2003, and 2002, respectively. Most of the other leases expire within five years and may be renewed. Future minimum rental commitments under non-cancelable leases in effect at March 31, 2003, are as follows: (In thousands) ------------------------------------------ 2003 $ 4,193 2004 4,805 2005 4,419 2006 3,732 2007 3,488 Thereafter 5,119 -------- $ 25,756 ======== Minimum rental commitments are not reduced by an insignificant amount of minimum sublease rental income due in the future under non-cancelable subleases. 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 March 31, 2003, the Company had 24 cash flow hedges open: eight natural gas price collar arrangements, 14 natural gas price swap arrangements and two crude oil price collar arrangements. Additionally, the Company had three crude oil price range swaps open at March 31, 2003, that did not qualify for hedge accounting under SFAS 133. At March 31, 2003, a $38.1 million ($23.6 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a $40.6 million derivative liability and a $0.7 million derivative receivable. A charge related to the change in fair value of derivative instruments of $0.5 million is reflected in Operating Income and is comprised of $0.4 million and $0.1 million for gas derivative instruments and oil derivative instruments, respectively, inclusive of the range swaps described below. From time to time the Company enters into crude oil range swaps with counterparties. These derivatives do not qualify for hedge accounting under SFAS 133 and are recorded at fair value at the balance sheet date. At March 31, 2003, the Company had three open crude oil range swap arrangements with an unrealized net loss of $0.8 million reflected in Operating Revenue. -12- 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 three-month periods ended March 31:
THREE MONTHS ENDED ----------------------------------------------------- MARCH 31, 2003 MARCH 31, 2002 ------------------------- ----------------------- (In Thousands) Accumulated Other Comprehensive Income (Loss) - Beginning of Period ......................... $ (12,939) $ 835 Net Loss ........................................ $ (39,223) $ (798) Other Comprehensive Loss (Net of Tax) Reclassification Adjustments for Settled Contracts ........................ (16,131) (1,592) Changes in Fair Value of Outstanding Hedge Positions .......................... 4,135 (7,831) ---------- ---------- ---------- --------- Total Other Comprehensive Loss .................. $ (11,996) $ (11,996) $ (9,423) $ (9,423) ---------- ---------- ---------- --------- Comprehensive Loss .............................. $ (51,219) $ (10,221) ========== ========== Accumulated Comprehensive Loss - End of Period ............................... $ (24,935) $ (8,588) ========== =========
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. -13- 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, consisting of $181.3 million 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 Company recorded a purchase price of approximately $315.6 million, which 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. The remaining $78.0 million of the recorded purchase price reflected a 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. As part of the Cody acquisition, the Company acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. The Company's current interest in Kurten is approximately 25%, including a one percent interest in the partnership. Under the partnership agreement, the Company has the right to a reversionary working interest that would bring its ultimate interest to 50% upon the limited partner reaching payout. Under the partnership agreement, the limited partner has the sole option to trigger a liquidation of the partnership. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner's election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, the Company would not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partners' decision and our decision to proceed with the liquidation, the Company performed an impairment review that resulted in an after-tax charge of $54 million. This impairment charge is reflected in the first quarter of 2003 as an operating expense but does not impact the Company's cash flows. In addition, the Company recorded a downward reserve revision of approximately 16 Bcfe as a result of the loss of the reversionary interest. 12. ADOPTION OF SFAS 143, "ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS" Effective January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. The adoption of SFAS 143 resulted in an increase of total liabilities because more retirement obligations are required to be recognized, an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities will also be recorded for meter stations, pipelines, processing plants and compressors. At January 1, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax cumulative effect of change in accounting principle loss in January 2003 of $6.8 million and recorded a retirement obligation of $35.2 million. There was no impact on the Company's cash flows as a result of adopting SFAS 143. See Note 2 for additional information on plugging and abandonment costs. -14- Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities, accretion expense and revisions of estimated cash flows. The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. QUARTER ENDED MARCH 31, 2002 -------------------------- (In Thousands) (Except Per Share Amounts) Net Loss $ (1,409) -------------- Per Share - Basic ....... $ (0.04) Per Share - Diluted ..... $ (0.04) 13. STOCK BASED COMPENSATION SFAS 123, "Accounting for Stock-Based Compensation", as amended by SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans. The following table illustrates the effect on Net Income and Earnings Per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation. QUARTER ENDED MARCH 31, ----------------------- (In Thousands, Except Per Share Amounts) 2003 2002 - ------------------------------------------------------------------------------- Net Loss, as reported $ (39,223) $ (798) Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax (1,802) (1,469) --------- ---------- Pro forma net loss $ (41,025) $ (2,267) ========= ========== Earnings per share: Basic - as reported $ (1.23) $ (0.03) Basic - pro forma $ (1.29) $ (0.07) Diluted - as reported $ (1.23) $ (0.03) Diluted - pro forma $ (1.29) $ (0.07) -15- The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table. QUARTER ENDED MARCH 31, -------------------------- (In Thousands, Except Per Share Amounts) 2003 2002 - ------------------------------------------------------------------------------- Compensation Expense in Net Income, as reported (1) $ 248 $ 339 Weighted Average Value of Options Granted During the Quarter (2) $ 6.75 $ 6.02 Assumptions Stock Price Volatility 35.4% 35.8% Risk Free Rate of Return 2.5% 3.9% Dividend Rate (per year) 0.16 0.16 Expected Term (in years) 4 4 - ------------------------------------------------------------------------------- (1) Compensation expense is defined as expense related to the vesting of stock grants, net of tax. (2) Calculated using the Black Sholes fair value based method. The fair value of stock options included in the pro forma results for each of the periods presented is not necessarily indicative of future effects on Net Income and Earnings Per Share. -16- 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 March 31, 2003, and the related condensed consolidated statements of operations and cash flows for each of the three-month periods ended March 31, 2003 and March 31, 2002. These interim 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 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, 2002, 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 17, 2003 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, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. As discussed in Notes 1 and 12 to the condensed consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003. PricewaterhouseCoopers LLP Houston, Texas April 25, 2003 -17- ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following review of operations for the first quarter of 2003 and 2002 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, 2002. Overview In the first quarter of 2003, we produced 21.9 Bcfe, a decrease of 3% over the 2002 first quarter. Natural gas production was 17.2 Bcf, down 1.2 Bcf, or 7%, compared to the 2002 first quarter. Oil production was 750 Mbbls, up 82 Mbbls, or 12% over the comparable quarter of last year. Production in the current period decreased slightly from the same period in 2002, which is when we experienced the highest annual production levels in our history. Our current production levels are attributable to drilling successes in the Gulf Coast and Eastern regions. Commodity prices were unusually high during the first quarter of 2003, and our financial results reflected their impact. In the first quarter of 2003, natural gas prices were 80% higher and crude oil prices were 50% higher than in 2002. Although our hedge positions limited the upside in the first quarter, the strong commodity price environment resulted in an increase to gas revenue of $31.7 million, or 68%, and an increase in oil revenue of $9.5 million, or 69%. Operating cash flows were similarly impacted, increasing by $30.0 million, or 102%, over last year. Despite the increase in commodity prices our first quarter resulted in a net loss of $39.2 million, or $1.23 per share. This loss is substantially attributable to an $87.9 million non-cash impairment related to the liquidation of a limited partnership interest in the Kurten field (see Note 11) and a $6.8 million charge from the adoption of SFAS 143 (see Note 12). In the first quarter of 2003, we drilled 25 gross wells (22 development and three exploratory wells) with a success rate of 88% compared to 21 gross wells (17 development and four exploratory wells) and a 95% success rate in the first quarter of 2002. For the full year, we plan to drill 180 gross wells and spend approximately $153.0 million in capital and exploration expenditures compared to 108 gross wells and $126.3 million of capital and exploration expenditures in 2002. Total capital and exploration expenditures were $31.7 million for the first quarter of 2003, compared to $34.5 million for the comparable period in 2002. We remain focused on our strategies of concentrating our capital spending program on projects balancing acceptable risk with the strongest economics. As in the past, we will use a portion of the cash flow from our long-lived Eastern and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountain areas. In addition, we have begun to expand our interest in the offshore Gulf of Mexico. We believe 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 25. 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 first quarter of 2002 into the summer and continued to strengthen through the first quarter of 2003. Prices in the first quarter of 2003 were the result of a higher demand associated with colder than normal winter temperatures, combined with historical low inventory levels. -18- Our primary source of cash during the first quarter of 2003 was from funds generated from operations. Cash was primarily used to fund exploration and development expenditures, reduce debt and to pay dividends. We had a net cash outflow of $1.3 million in the first quarter of 2003. Cash inflows from operating activities totaled $59.5 million in the current quarter. The $34.7 million of capital and exploration expenditures were funded with our operating cash flows. THREE MONTHS ENDED MARCH 31, 2003 2002 -------- -------- (In millions) Cash Flows Provided by Operating Activities .. $ 59.5 $ 29.6 ======== ======== Cash flows from operating activities in the 2003 first quarter were $29.9 million higher than the corresponding quarter of 2002 primarily due to higher natural gas and oil prices. THREE MONTHS ENDED MARCH 31, 2003 2002 --------- --------- (In millions) Cash Flows Used by Investing Activities ..... $ (33.1) $ (48.1) ========= ========= Cash flows used by investing activities in the first quarter of 2003 were substantially attributable to capital and exploration expenditures of $34.7 million, partially offset by proceeds from the sale of certain oil and gas properties of $1.6 million. Cash flows used by investing activities in the first quarter of 2002 were entirely for capital and exploration expenditures of $48.1 million. THREE MONTHS ENDED MARCH 31, 2003 2002 --------- ----------- (In millions) Cash Flows Provided (Used) by Financing Activities ...................................... $ (27.8) $ 17.8 ========= ======== Cash flows used by financing activities in the first quarter of 2003 consist primarily of $27.0 million of borrowing repayments on the revolving credit facility and $1.3 million of dividend payments. Cash flows provided by financing activities in the first quarter of 2002 consist primarily of $19.0 million in increased borrowings on the revolving credit facility. Partially offsetting the use of cash flow by financing activities were proceeds from the exercise of stock options in the first quarter of $0.5 million in 2003 and $0.1 million in 2002. Our 2003 interest expense is expected to be approximately $23.6 million. 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 October 2006. 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 through new debt or equity offerings, if necessary, our capital requirements, including acquisitions. Non-GAAP Financial Measures From time to time management discloses discretionary cash flow and net income and earnings per share, excluding selected items. These non-GAAP financial measure calculations and reconciliations to the most comparable GAAP financial measure for the period are presented with each earnings release of the Company, furnished in Form 8-K to the Securities and Exchange Commission. Discretionary cash flow is defined as Net Income plus non-cash charges and Exploration Expense. Discretionary cash flow is widely accepted as a financial indicator of an oil and gas company's ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary cash flow is presented based on management's belief that this non-GAAP measure is useful information to investors because it is widely used by professional research analysts in -19- the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to Net Income. Net Income excluding selected items and Earnings Per Share excluding selected items is presented based on managements belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a Beneficial Comparison to Similarly adjusted measurements of prior periods. Net Income and Earnings Per Share excluding selected items is not a measure of financial performance under GAAP and should not be considered as an alternative to Net Income and Earnings Per Share, as defined by GAAP. Capitalization Our capitalization information is as follows: MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ (In millions) Debt ........................ $ 338.0 $ 365.0 Stockholders' Equity /(1)/ .. 299.0 350.7 -------- -------- Total Capitalization ........ $ 637.0 $ 715.7 ======== ======== Debt to Capitalization 53.1% 51.0% /(1)/ Includes common stock, net of treasury stock. No shares of preferred stock were outstanding. During the first quarter of 2003, we paid dividends of $1.3 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 while considering projected cash flows for the year. The following table presents major components of capital and exploration expenditures: THREE MONTHS ENDED MARCH 31, 2003 2002 ----------- ----------- (In millions) Capital Expenditures Drilling and Facilities ...... $ 14.5 $ 25.9 Leasehold Acquisitions ....... 2.8 1.0 Pipeline and Gathering ....... 1.0 0.2 Other ........................ 0.0 0.3 -------- -------- 18.3 27.4 Exploration Expenses ............. 13.4 7.1 -------- -------- Total ........................ $ 31.7 $ 34.5 ======== ======== Total capital and exploration expenditures in the first quarter of 2003 decreased $2.8 million compared to the same quarter of 2002, primarily as a result of decreased drilling activity. We plan to drill 180 gross wells in 2003 compared with 108 gross wells drilled in 2002. This 2003 drilling program includes approximately $153.0 million in total capital and exploration expenditures, up -20- from $126.3 million in 2002. Budgeted spending in 2003 includes approximately $89 million for drilling and dry hole exposure, $11 million for lease acquisition and $13 million in geological and geophysical expenses. In addition to the drilling and exploration program, other 2003 capital expenditures are planned primarily for production equipment, workovers, 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. -21- Results of Operations Selected Financial and Operating Data
THREE MONTHS ENDED MARCH 31, -------------------------------- 2003 2002 -------- -------- (In millions, except where noted) Operating Revenues ....................................................... $ 135.9 $ 75.1 Operating Expenses ....................................................... 183.2 70.1 Operating Income (Loss) .................................................. (46.7) 5.0 Interest Expense ......................................................... 5.6 6.2 Net Loss, Before Accounting Change ....................................... (32.4) (0.8) Net Loss ................................................................. (39.2) (0.8) Loss Per Share - Basic, Before Accounting Change ......................... $ (1.02) $ (0.03) Loss Per Share - Diluted, Before Accounting Change ....................... $ (1.02) $ (0.03) Loss Per Share - Basic, Accounting Change................................. $ (0.21) $ 0.00 Loss Per Share - Diluted, Accounting Change............................... $ (0.21) $ 0.00 Loss Per Share - Basic ................................................... $ (1.23) $ (0.03) Loss Per Share - Diluted ................................................. $ (1.23) $ (0.03) Natural Gas Production (Bcf) Gulf Coast .......................................................... 6.7 7.5 West ................................................................ 6.1 6.4 East ................................................................ 4.4 4.5 ------- ------ Total Company ....................................................... 17.2 18.4 ======= ====== Natural Gas Production Sales Prices ($/Mcf) Gulf Coast .......................................................... $ 4.88 $ 2.67 West ................................................................ $ 3.61 $ 2.14 East ................................................................ $ 5.35 $ 2.85 Total Company ....................................................... $ 4.55 $ 2.53 Crude Oil Production (Mbbl) Gulf Coast .......................................................... 696 610 West ................................................................ 48 50 East ................................................................ 6 8 ------- ------- Total Company ....................................................... 750 668 ======= ======= Crude Oil Production Sales Prices ($/Bbl) Gulf Coast .......................................................... $ 30.84 $ 20.57 West ................................................................ $ 32.05 $ 20.97 East ................................................................ $ 25.79 $ 16.41 Total Company ....................................................... $ 30.88 $ 20.55 Brokered Natural Gas Margin Volume (Bcf) ........................................................ 3.9 3.2 Margin ($/Mcf)/(1)/ ................................................. $ 0.92 $ 0.45 (1) Amount represents brokered natural gas revenue less brokered natural gas cost, divided by brokered natural gas volumes.
First Quarters of 2003 and 2002 Compared Net Income and Revenues. We reported a net loss in the first quarter of 2003 of $39.2 million, or $1.23 per share. During the corresponding quarter of 2002, we reported a net loss of $0.8 million, or $0.03 per share. Net operating revenues increased by $60.8 million, or 81% and operating income decreased by $51.7 million. The decrease in operating income was substantially due to the impairment on the Kurten field (Note 11). Natural gas sales made up 58%, or $78.2 million, of operating revenue. The 81% increase in -22- operating revenues was primarily due to an 80% and 50% increase in our realized average natural gas price and crude oil price, respectively, compared to the first quarter of 2002, as well as a 12% increase in crude oil production, partially offset by a 7% decrease in natural gas production. Operating revenues were also impacted by an increase in our brokered natural gas revenues. The average realized total company natural gas production sales price was $4.55 per Mcf for the first quarter of 2003. Due to certain derivative instruments this price was reduced by $1.46 per Mcf. The average Gulf Coast natural gas production sales price increased $2.21 per Mcf, or 83%, to $4.88, increasing operating revenues by approximately $14.8 million. In the Western region, the average natural gas production sales price increased $1.47 per Mcf, or 69%, to $3.61, increasing operating revenues by approximately $9.0 million. The average Eastern region natural gas production sales price increased $2.50 per Mcf, or 88%, to $5.35, increasing operating revenues by approximately $11.0 million. The overall weighted average natural gas production sales price increased $2.02 per Mcf, or 80%, to $4.55, increasing revenues by $34.8 million. Natural gas production volume in the Gulf Coast region was down 0.8 Bcf, or 11%, to 6.7 Bcf primarily due to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. Natural gas production volume in the Western region decreased 0.3 Bcf, or 5%, to 6.1 Bcf primarily due to natural declines and a small drilling program in 2002. Natural gas production volume in the Eastern region was substantially the same as the comparable quarter of 2002 at 4.4 Bcf. The decrease in total natural gas production of 1.2 Bcf, or 7%, resulted in a decrease to natural gas revenue of $3.0 million in the first quarter of 2003. The average realized total company crude oil sales price was $30.88 per Bbl first quarter of 2003. Due to certain derivative instruments this price was reduced by $2.54 per Bbl. The volume of crude oil sold in the quarter increased by 82 Mbbls, or 12%, to 750 Mbbls, increasing operating revenues by $1.7 million. This increase in crude oil production was substantially due to production increases in the Gulf Coast region. Additionally, crude oil prices increased $10.33 per Bbl, or 50%, to $30.88, resulting in an increase to operating revenues of $7.8 million. In total, revenue from crude oil sales increased $9.5 million, or 69%, above the 2002 first quarter. Brokered natural gas revenue increased $18.2 million, or 133%, over the first quarter of last year. The sales price of brokered natural gas rose 89%, resulting in an increase in revenue of $15.0 million, combined with a 24% increase in volume of natural gas brokered this quarter, increasing revenues by $3.2 million. After including the related brokered natural gas costs, we realized a net margin of $3.6 million in the first quarter of 2003 and $1.4 million in the comparable quarter of 2002. Other operating revenues increased $1.5 million to $3.3 million. This change was primarily a result of: . A $0.4 million increase in transportation revenue due to a substantial increase in volumes, offset slightly by a decrease in price. . A $0.8 million increase in natural gas liquids revenue as a result of increased volumes in the current quarter. . A $0.3 million increase in natural gas processing plant revenue. -23- Costs and Expenses. Total costs and expenses from operations increased $113.1 million in the first quarter of 2003 compared to the same quarter of 2002. The primary reasons for this fluctuation are as follows: . Brokered natural gas cost increased $16.0 million, or 130%, from the first quarter of last year. The cost of brokered natural gas rose 86%, resulting in an increase to expense of $13.1 million. Additionally, a 24% increase in volume of natural gas brokered this quarter increased costs by $2.9 million. . Direct operating expense decreased $1.3 million, or 11%. Operating costs have decreased in the Gulf Coast, and to a lesser extent in the Rocky Mountains. The decrease in the Gulf Coast is attributable to timing of expenditures. The decrease in the Rocky Mountains is due to a milder winter, which resulted in less required maintenance, and to a lesser extent, timing of expenditures. On a per unit basis, operating expense declined from $0.54 to $0.50 per Mcfe produced in the first quarter of 2002 and 2003, respectively. . Exploration expense increased $6.3 million, or 90%, primarily as a result of increased spending on geological and geophysical expenses and dry hole expense in 2003. During the first quarter of 2003, we spent an additional $5.2 million on geological and geophysical activities and incurred an additional $0.7 million in dry hole expense. . Impairment of long-lived assets expense increased $86.9 million due to the impairment on the Kurten field (see Note 11). . General and administrative costs increased $0.9 million, or 15%, as a result of an increase in employee fringe benefit expenses. . Taxes other than income increased $4.1 million, or 66%, as a result of higher commodity prices realized this quarter. Interest expense decreased $0.6 million as a result of a lower average level of outstanding debt during the first quarter of 2003 when compared to the first quarter of 2002 and a decline in interest rates on the revolving credit facility. Income tax benefit increased from $0.4 million to $19.9 million in the first quarter of 2002 and 2003, respectively. The increase is due to a comparable increase in our net loss. Recently Issued Accounting Pronouncements In June 2001, the FASB approved for issuance Statement of Financial Accounting Standard (SFAS) 143, "Accounting for Asset Retirement Obligations." 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 adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, "Adoption of SFAS 143, Accounting for Asset Retirement Obligations," to the financial statements. In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB Statement 123, "Accounting for Stock-Based Compensation", to provide alternative methods of transition for a voluntary change to the fair value based -24- method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of this statement did not impact the Company's financial position, results of operations, or cash flows. See Note 13, "Stock Based Compensation," to the financial statements. In January 2003, the FASB issued Financial Interpretation 46, "Consolidation of Variable Interest Entities - An Interpretation of ARB 51" (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time we have only one entity that could potentially be a VIE. We are evaluating this potential VIE, in which we have a one percent general partner interest and that holds an interest in the Kurten field, to determine if it is a VIE. However, pursuant to the partnership agreement, the limited partner has elected to liquidate the partnership; it is anticipated that this liquidation will be completed prior to the effective date of the Interpretation. See Note 11 for additional information related to this partnership. Forward-Looking Information The statements regarding future financial performance and results, market prices 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 and oil on economically attractive terms. The average produced natural gas sales price received in the first three months of 2003 was 80% higher than in 2002 and the average oil sales price was 50% higher than in the comparable period of 2002. The volatility of natural gas prices in recent years remains prevalent in 2003 with wide price swings in day-to-day trading on the NYMEX futures market. Additionally, we have natural gas price swaps and collars in place through December 2004 and oil price collars and range swaps in place through June 2003 and December 2003, respectively, which all offer some protection against price volatility. 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. See Item 3A., "Quantitative and Qualitative Disclosures about Market Risk" for additional information regarding these derivative instruments. We believe our capital resources, supplemented with external financing, if necessary, are adequate to meet our capital requirements. The preceding paragraphs contain forward-looking information. See Forward-Looking Information above. -25- ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price Swaps and Options Our hedging policy is designed to reduce the risk of price volatility for our production in the natural gas, natural gas liquids and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 8 of the Notes to the Interim Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements. 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. Under our Revolving Credit Agreement, the aggregate level of commodity hedging must not exceed 80% of the anticipated future production during the period covered by the hedges. During the first quarter of 2003, natural gas price swaps covered 8,754 Mmcf, or 51% of our first quarter production, fixing the sales price of this gas at an average of $4.47 per Mcf. During the first quarter of 2002, we did not have any natural gas price swaps covering our production. During the first quarter of 2003 and 2002, we did not have any crude oil price swaps covering our production that qualified for hedge accounting. At March 31, 2003, we had open natural gas price swap contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Swaps ----------------------------------------------- Volume Weighted Unrealized in Average Loss Contract Period Mmcf Contract Price (In Thousands) - ---------------------------------------------------------------------------------------------------- As of March 31, 2003 Natural Gas Price Swaps on Production in: Second Quarter 2003 7,950 $ 4.31 Third Quarter 2003 8,037 4.31 Fourth Quarter 2003 8,037 4.31 ----------------------------------------------- Nine Months Ended December 31, 2003 24,024 $ 4.31 $ 25,850 First Quarter 2004 2,089 $ 4.42 Second Quarter 2004 2,089 4.42 Third Quarter 2004 2,112 4.42 Fourth Quarter 2004 2,112 4.42 ----------------------------------------------- Full Year 2004 8,402 $ 4.42 $ 5,153
From time to time we enter into crude oil range swaps with counterparties. These derivatives do not qualify for hedge accounting under SFAS 133 and are recorded at fair value at the balance sheet date. At March 31, 2003, these instruments resulted in an unrealized net loss of $0.8 million recognized in operating revenue. -26- Hedges on Production - Options Throughout 2002 and the first quarter of 2003, 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 natural gas and crude oil collars. Under the 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 2003 and 2004 natural gas price collar hedges included several collar arrangements based on eight price indexes at which we sell a portion of our production. During the first quarter of 2003, natural gas price collars covered 3,333 Mmcf, or 19% of our first quarter production, with a weighted average floor of $4.46 per Mcf and a weighted average ceiling of $5.35 per Mcf. During the first quarter of 2002, natural gas price collars covered 12,109 Mmcf, or 66% of our production, with a weighted average price floor of $2.68 per Mcf and a weighted average price ceiling of $3.53 per Mcf. At March 31, 2003, we had open natural gas price collar contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Collars ----------------------------------------------- Volume Weighted Unrealized in Average Loss Contract Period Mmcf Ceiling / Floor (In Thousands) - --------------------------------------------------------------------------------------------------- As of March 31, 2003 Natural Gas Price Collars on Production in: Second Quarter 2003 4,237 $5.42 / $4.46 Third Quarter 2003 4,283 $5.42 / $4.46 Fourth Quarter 2003 4,283 $5.42 / $4.46 ----------------------------------------------- Nine Months Ended December 31, 2003 12,803 $5.42 / $4.46 $ 6,636 First Quarter 2004 2,955 $5.78 / $4.32 Second Quarter 2004 2,955 $5.78 / $4.32 Third Quarter 2004 2,988 $5.78 / $4.32 Fourth Quarter 2004 2,988 $5.78 / $4.32 ----------------------------------------------- Full Year 2004 11,886 $5.78 / $4.32 $ 1,420
We have 2003 crude oil price collars in place for the months of January through June, covering 362 Mbbls of production with a weighted average price floor of $24.75 per Mbbl and a weighted average price ceiling of $28.86 per Mbbl. At March 31, 2003, we have no open crude oil price collar arrangements to cover our 2004 production. 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 25. -27- ITEM 4. Controls and Procedures Within the 90-day period prior to the date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission's rules and forms, of information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation. -28- PART II. OTHER INFORMATION ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits 4.3 - Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). (a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). (b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000). (c) Amendment No. 3 to the Rights Agreement dated January 1, 2003. 10.16 - Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001 ). (a) First Amendment to the Cabot Oil & Gas Corporation Second Amended and Restated 1994 Non-Employee Director Stock Option Plan dated March 17, 2003. 15.1 - Awareness letter of PricewaterhouseCoopers LLP 15.2 - Consent of Brown, Drew & Massey, LLP (b) Reports on Form 8-K Item 5: Other Events filing made on February 13, 2003, includes Item 7. Press Release dated February 13, 2003, and titled "Cabot Oil & Gas Announces First Quarter Impairment and SFAS 143 Adoption." -29- 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) April 30, 2003 By: /s/ Dan O. Dinges ------------------------------------------- Dan O. Dinges Chairman of the Board, Chief Executive Officer and President (Principal Executive Officer) April 30, 2003 By: /s/ Scott C. Schroeder ------------------------------------------- Scott C. Schroeder Vice President and Chief Financial Officer (Principal Financial Officer) April 30, 2003 By: /s/ Henry C. Smyth ------------------------------------------- Henry C. Smyth Vice President, Controller and Treasurer (Principal Accounting Officer) -30- CERTIFICATIONS I, Dan O. Dinges, certify that: 1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 30, 2003 /s/ Dan O. Dinges -------------------------------------- Dan O. Dinges Chairman of the Board, Chief Executive Officer and President -31- I, Scott C. Schroeder, certify that: 1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 30, 2003 /s/ Scott C. Schroeder ------------------------------------------ Scott C. Schroeder Vice President and Chief Financial Officer -32- EX-4.3 (C) 3 dex43c.txt RIGHTS AGREEMENT Exhibit 4.3(c) AMENDMENT TO RIGHTS AGREEMENT This Amendment, dated as of January 1, 2003 (this "Amendment"), to the Rights Agreement, dated as of March 28, 1991, as amended and restated as of December 8, 2000 (the "Rights Agreement"), is among Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), Fleet National Bank, formerly known as The First National Bank of Boston and as BankBoston, N.A. (the "Former Rights Agent"), and The Bank of New York (the "New Rights Agent"). WHEREAS, the Company and the Former Rights Agent entered into the Rights Agreement specifying the terms of the Rights (as defined therein); WHEREAS, the Former Rights Agent is resigning as Rights Agent and the Company desires to appoint the New Rights Agent as successor Rights Agent; WHEREAS, the Company desires to amend the Rights Agreement in accordance with Section 27 of the Rights Agreement to reflect the succession of the New Rights Agent to the position of Rights Agent and make a related change to the Rights Agreement; NOW, THEREFORE, in consideration of the premises and mutual agreements set forth herein and in the Rights Agreement, the parties hereby agree as follows: Section 1. Definitions. Capitalized terms used and not otherwise defined herein shall have the meaning assigned to such terms in the Rights Agreement. Section 2. Amendment to Rights Agreement. The definition of "Business Day" in Section 1 of the Rights Agreement is hereby amended to read in its entirety as follows: "Business Day" shall mean any day other than a Saturday, Sunday or a day on which banking institutions in the State of New York are authorized or obligated by law or executive order to close. Section 3. Successor Rights Agent. The Former Rights Agent hereby resigns as Rights Agent, the Company hereby appoints the New Rights Agent as the Rights Agent under the Rights Agreement pursuant to Section 21 of the Rights Agreement, and the New Rights Agent hereby accepts such appointment. Such resignation and appointment are effective as of the date of this Amendment. Section 4. Miscellaneous. (a) The term "Agreement" as used in the Rights Agreement shall be deemed to refer to the Rights Agreement as amended hereby. (b) This Amendment shall be effective as of the date first above written, and, except as set forth herein, the Rights Agreement shall remain in full force and effect and shall be otherwise unaffected hereby. 1 (c) This Amendment may be executed in two or more counterparts, each of which shall be deemed to be an original, but all for which together shall constitute one and the same instrument. (d) This Amendment shall be deemed to be a contract made under the laws of the State of Delaware and for all purposes shall be governed by and construed in accordance with the laws of such State applicable to contracts to be made and performed entirely within such State. (e) Except to the extent specifically amended hereby, the provisions of the Rights Agreement shall remain unmodified, and the Rights Agreement as amended hereby is confirmed as being in full force and effect. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the day and year first above written. CABOT OIL & GAS CORPORATION By:___________________________________________ Lisa A. Machesney Its: Vice President ------------------------------------------ EQUISERVE TRUST COMPANY N.A. By:___________________________________________ Its:__________________________________________ THE BANK OF NEW YORK By:___________________________________________ Its:__________________________________________ 2 EX-10.16 (A) 4 dex1016a.txt SECOND AMEMDED AND RESTATED 1994 NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN Exhibit 10.16(a) FIRST AMENDMENT TO THE CABOT OIL & GAS CORPORATION SECOND AMENDED AND RESTATED 1994 NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN First Amendment Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), having established the Cabot Oil & Gas Corporation Second Amended and Restated 1994 Non-employee Director Stock Option Plan (the "Plan") and, having reserved the right under Section 12 thereof to amend the Plan, does hereby amend the Plan, effective as of March 1, 2003, to read as follows: 1. Section 7 of the Plan is hereby amended by replacing clause (c) of Section 7 in its entirety as follows: "(c) the later of (i) the expiration of three months following the date on which the Optionee ceases to be a Non-employee Director for any reason other than death, disability or mandatory retirement or (ii) in the case of an Optionee who ceases service as a Non-employee Director by resigning from the Board of Directors within the six month period immediately preceding the date of the Company's annual meeting of stockholders for the year 2003, the expiration of six months following the effective date of the Optionee's resignation from the Board of Directors." 2. Section 8(c) of the Plan is hereby amended by adding the following language to the end thereof: "; provided, however, for purposes of this Section 8(c), an Optionee who ceases service as a Non-employee Director by resigning from the Board of Directors within the six month period immediately preceding the date of the Company's annual meeting of stockholders for the year 2003 shall, with respect to each outstanding Option previously granted to such Optionee under the Plan, be deemed to have ceased his or her service in the capacity of a director of the Company on May 31, 2003." 1 IN WITNESS WHEREOF, the Company has caused this amendment to be executed by its duly authorized officers this 17/th/ day of March, 2003, but effective as the date specified herein. CABOT OIL & GAS CORPORATION By:________________________________________ Name:______________________________________ Title:_____________________________________ 2 EX-15.1 5 dex151.txt AWARENESS LETTER OF PRICEWATERHOUSECOOPERS LLP EXHIBIT 15.1 Securities and Exchange Commission 450 Fifth Street, NW Washington, D.C. 20549 Re: Cabot Oil & Gas Corporation Registration Statements on Form S-8 and Form S-3 Commissioners: We are aware that our report dated April 25, 2003 on our review of the interim financial information of Cabot Oil & Gas Corporation (the "Company") as of and for the period ended March 31, 2003 and included in the Company's quarterly report on Form 10-Q for the quarter then ended is incorporated by reference in its Registration Statements on Form S-8 filed with the Securities and Exchange Commission on June 23, 1990, November 1, 1993, May 20, 1994, May 23, 2000 and July 11, 2002 and Form S-3 filed with the Securities and Exchange Commission on July 27, 1999. Very truly yours, /s/ PricewaterhouseCoopers LLP Houston, Texas April 25, 2003 -33- EX-15.2 6 dex152.txt CONSENT OF BROWN, DREW & MASSEY, LLP EXHIBIT 15.2 CONSENT OF COUNSEL We hereby consent to the incorporation by reference in the Registration Statements of Cabot Oil & Gas Corporation (the "Company") on Form S-3 (File Nos. 333-68350 and 333-83819) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 33-71134 and 33-53723) of the references to the opinion of our firm dated April 25, 2003 that appear in the interim financial information of Cabot Oil & Gas Corporation as of and for the period ended March 31, 2003 and included in the Company's quarterly report on Form 10-Q for the quarter then ended. /s/ Tom Reese Brown, Drew & Massey, LLP Casper, Wyoming April 24, 2003 -----END PRIVACY-ENHANCED MESSAGE-----