Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, Texas 77079 Telephone: 281/589-4600 Facsimile: 281/589-4912 August 11, 1999 Securities & Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 RE: Cabot Oil & Gas Corporation Form 10-Q for the quarter ending June 30, 1999 Ladies and Gentlemen: On behalf of Cabot Oil & Gas Corporation, transmitted herewith for filing under the Securities and Exchange Act of 1934, as amended, is a copy of the Company's June 30, 1999 Form 10-Q. Pursuant to Rule 302 of Regulation S-T, the Form 10-Q has been executed by typing the name of the signature. This filing has been effected through the Securities and Exchange Commission's EDGAR electronic filing system. Please contact the undersigned at (281) 589-4642 with any questions or statements you may have regarding this filing. Sincerely, JILL RIBBECK Manager, Financial Reporting ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ------------ FORM 10-Q ( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1999 ( ) 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) 15375 Memorial Drive, Houston, Texas 77079 (Address of principal executive offices including Zip Code) (281) 589-4600 (Registrant's telephone number) No Change (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] As of July 30, 1999, there were 24,746,145 shares of Class A Common Stock, Par Value $.10 Per Share, outstanding. ================================================================================ CABOT OIL & GAS CORPORATION INDEX TO FINANCIAL STATEMENTS Page ---- Part I. Financial Information Page Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 1999 and 1998...................... 3 Condensed Consolidated Balance Sheet at June 30, 1999 and December 31, 1998.................................................. 4 Condensed Consolidated Statement of Cash Flows for the Three and Six Months Ended June 30, 1999 and 1998...................... 5 Notes to Condensed Consolidated Financial Statements.................... 6 Independent Accountant's Report on Review of Interim Financial Information................................ 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 9 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders.............. 18 Item 6. Exhibits and Reports on Form 8-K................................. 18 Signature ................................................................. 19 2 CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) (In Thousands, Except Per Share Amounts) THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, 1999 1998 1999 1998 -------- -------- -------- -------- NET OPERATING REVENUES Natural Gas Production...................... $ 35,339 $ 37,252 $ 65,958 $ 72,423 Crude Oil and Condensate.................... 3,842 1,911 6,492 4,248 Brokered Natural Gas Margin................. 1,056 1,143 1,939 2,536 Other....................................... 824 1,361 1,952 3,251 -------- -------- -------- -------- 41,061 41,667 76,341 82,458 OPERATING EXPENSES Direct Operations........................... 7,762 7,532 15,609 14,497 Exploration................................. 2,015 2,978 4,440 6,379 Depreciation, Depletion and Amortization.... 14,816 10,316 27,795 20,083 Impairment of Unproved Properties........... 696 1,110 1,953 1,806 General and Administrative.................. 4,426 5,824 8,717 11,325 Taxes Other Than Income..................... 4,165 4,036 7,803 7,834 -------- -------- -------- -------- 33,880 31,796 66,317 61,924 Gain on Sale of Assets........................ 974 5 975 57 -------- -------- -------- -------- INCOME FROM OPERATIONS........................ 8,155 9,876 10,999 20,591 Interest Expense.............................. 6,450 4,579 13,168 8,834 -------- -------- -------- -------- Income/(Loss) Before Income Taxes............. 1,705 5,297 (2,169) 11,757 Income Tax Expense/(Benefit).................. 745 2,163 (687) 4,780 -------- -------- -------- -------- NET INCOME/(LOSS)............................. 960 3,134 (1,482) 6,977 Dividend Requirement on Preferred Stock....... 850 851 1,701 1,701 -------- -------- -------- -------- Net Income/(Loss) Applicable to Common Stockholders......................... $ 110 $ 2,283 $ (3,183) $ 5,276 ======== ======== ======== ======== Basic Earnings/(Loss) Per Share Applicable to Common Stockholders........... $ -- $ 0.09 $ (0.13) $ 0.21 Diluted Earnings/(Loss) Per Share Applicable to Common Stockholders........... $ -- $ 0.09 $ (0.13) $ 0.21 Average Common Shares Outstanding............. 24,702 24,828 24,684 24,756 The accompanying notes are an integral part of these condensed consolidated financial statements. 3 CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) (In Thousands) JUNE 30, DECEMBER 31, 1999 1998 -------- -------- ASSETS Current Assets Cash and Cash Equivalents.............................. $ 1,904 $ 2,200 Accounts Receivable.................................... 43,518 55,799 Inventories............................................ 8,231 9,312 Other.................................................. 4,132 3,804 -------- -------- Total Current Assets................................ 57,785 71,115 Properties and Equipment (Successful Efforts Method).... 622,453 629,908 Other Assets............................................ 2,306 3,137 -------- -------- $682,544 $704,160 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current Portion of Long-Term Debt...................... $ 16,000 $ 16,000 Accounts Payable....................................... 43,979 66,628 Accrued Liabilities.................................... 14,580 16,406 -------- -------- Total Current Liabilities........................... 74,559 99,034 Long-Term Debt.......................................... 334,000 327,000 Deferred Income Taxes................................... 85,150 85,952 Other Liabilities....................................... 9,908 9,506 Stockholders' Equity Preferred Stock: Authorized - 5,000,000 Shares of $.10 Par Value Issued and Outstanding - 6% Convertible Redeemable Preferred; $50 Stated Value; 1,134,000 Shares in 1999 and 1998..................................... 113 113 Common Stock: Authorized - 40,000,000 Shares of $.10 Par Value Issued and Outstanding - 25,040,135 Shares and 24,959,897 Shares in 1999 and 1998, Respectively..... 2,504 2,496 Additional Paid-in Capital............................. 253,492 252,073 Accumulated Deficit.................................... (72,798) (67,630) Less Treasury Stock, At Cost: 302,600 Shares in 1999 and 1998...................... (4,384) (4,384) -------- -------- Total Stockholders' Equity........................... 178,927 182,668 -------- -------- $682,544 $704,160 ======== ======== The accompanying notes are an integral part of these condensed consolidated financial statements. 4 CABOT OIL & GAS CORPORATION CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In Thousands) THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, 1999 1998 1999 1998 -------- -------- -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income/(Loss)................................ $ 960 $ 3,134 $ (1,482) $ 6,977 Adjustment to Reconcile Net Income/(Loss) to Cash Provided by Operating Activities: Depletion, Depreciation and Amortization..... 14,816 10,316 27,795 20,083 Impairment of Undeveloped Leasehold.......... 696 1,110 1,953 1,806 Deferred Income Taxes........................ 670 2,289 (802) 4,577 Gain on Sale of Assets....................... (974) (5) (975) (57) Exploration Expense.......................... 2,015 2,978 4,440 6,379 Other........................................ 516 791 1,257 1,280 Changes in Assets and Liabilities: Accounts Receivable.......................... 3,700 3,587 12,281 16,283 Inventories.................................. (257) (2,498) 1,081 (1,872) Other Current Assets......................... (528) (2,113) (327) (2,132) Other Assets................................. 206 158 831 159 Accounts Payable and Accrued Liabilities..... 978 (1,657) (14,553) (6,325) Other Liabilities............................ (962) (564) 403 (680) -------- -------- -------- -------- Net Cash Provided by Operating Activities...................... 21,836 17,526 31,902 46,478 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures............................. (14,850) (36,727) (41,363) (68,111) Proceeds from Sale of Assets..................... 9,375 159 9,376 669 Exploration Expense.............................. (2,015) (2,978) (4,440) (6,379) -------- -------- -------- -------- Net Cash Used by Investing Activities.......... (7,490) (39,546) (36,427) (73,821) -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Sale of Common Stock............................. 729 1,238 916 2,134 Increase in Debt................................. 25,000 39,000 66,000 65,000 Decrease in Debt................................. (38,000) (16,000) (59,000) (34,000) Dividends Paid................................... (1,850) (1,845) (3,687) (3,682) -------- -------- -------- -------- Net Cash Provided/(Used) by Financing Activities.......................... (14,121) 22,393 4,229 29,452 -------- -------- -------- -------- Net Increase/(Decrease) in Cash and Cash Equivalents.............................. 225 373 (296) 2,109 Cash and Cash Equivalents, Beginning of Period............................... 1,679 3,520 2,200 1,784 -------- -------- -------- -------- Cash and Cash Equivalents, End of Period..................................... $ 1,904 $ 3,893 $ 1,904 $ 3,893 ======== ======== ======== ======== The accompanying notes are an integral part of these condensed consolidated financial statements. 5 CABOT OIL & GAS CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. FINANCIAL STATEMENT PRESENTATION During interim periods, the Company follows the accounting policies set forth in its Annual Report to Stockholders and its Report on Form 10-K filed with the Securities and Exchange Commission. Users of financial information produced for interim periods are encouraged to refer to the footnotes contained in the Annual Report to Stockholders when reviewing interim financial results. In the opinion of management, the accompanying interim financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, reassessed and documented pursuant to the provisions of SFAS 133. This statement was initially effective for financial statements for fiscal years beginning after June 15, 1999. However, in June 1999, the Financial Accounting Standards Board issued SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of Effective Date of SFAS 133," which delayed the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. The Company has not yet completed its evaluation of the impact of the provisions of SFAS No. 133. 2. PROPERTIES AND EQUIPMENT Properties and equipment are comprised of the following: JUNE 30, DECEMBER 31, 1999 1998 ---------- ---------- (In thousands) Unproved Oil and Gas Properties.........................$ 42,083 $ 42,426 Proved Oil and Gas Properties........................... 934,498 921,463 Gathering and Pipeline Systems.......................... 126,289 121,999 Land, Building and Improvements......................... 4,355 4,200 Other................................................... 22,537 20,468 ---------- ---------- 1,129,762 1,110,556 Accumulated Depreciation, Depletion and Amortization.... (507,309) (480,648) ---------- ---------- $ 622,453 $ 629,908 ========== ========== 3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following: JUNE 30, DECEMBER 31, 1999 1998 -------- -------- (In thousands) Accounts Receivable Trade Accounts.................................. $ 38,020 $ 41,397 Joint Interest Accounts......................... 3,561 6,712 Insurance Recoveries............................ 1,242 5,539 Current Income Tax Receivable................... -- 502 Other Accounts.................................. 1,052 2,123 -------- -------- 43,875 56,273 Allowance for Doubtful Accounts.................. (357) (474) -------- -------- $ 43,518 $ 55,799 ======== ======== 6 JUNE 30, DECEMBER 31, 1999 1998 -------- -------- (In thousands) Accounts Payable Trade Accounts.................................. $ 10,027 $ 13,229 Natural Gas Purchases........................... 11,506 17,031 Wellhead Gas Imbalances......................... 2,087 1,945 Royalty and Other Owners........................ 11,869 8,987 Capital Costs................................... 4,616 20,165 Dividends Payable............................... 851 851 Taxes Other Than Income......................... 1,463 1,017 Drilling Advances............................... -- 900 Other Accounts.................................. 1,560 2,503 -------- -------- $ 43,979 $ 66,628 ======== ======== Accrued Liabilities Employee Benefits............................... $ 3,107 $ 4,479 Taxes Other Than Income......................... 8,002 7,357 Interest Payable................................ 2,486 2,406 Other Accrued................................... 985 2,164 -------- -------- $ 14,580 $ 16,406 ======== ======== Other Liabilities Postretirement Benefits Other Than Pension...... $ 532 $ 316 Accrued Pension Cost............................ 5,639 4,941 Taxes Other Than Income and Other............... 3,737 4,249 -------- -------- $ 9,908 $ 9,506 ======== ======== 4. LONG-TERM DEBT At June 30, 1999, the Company had $202 million outstanding under its facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time-to-time on the basis of the projected present value (as determined by the banks' petroleum engineer incorporating certain assumptions provided by the lender) of estimated future net cash flows from proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in December 2003 and is subject to renewal. 5. EARNINGS PER SHARE Basic earnings per share for the second quarter were $0.00 and $0.09 in 1999 and 1998, respectively, and were based on the weighted average shares outstanding of 24,702,075 in 1999 and 24,828,099 in 1998. Basic earnings/(loss) per share for the first six months of the year were $(0.13) and $0.21 in 1999 and 1998, respectively. Diluted earnings/(loss) per share were $0.00 and $0.09 in the second quarter, and $(0.13) and $0.21 for the first six months in 1999 and 1998, respectively. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. Common stock equivalents include both stock awards and stock options, and totaled 271,367 and 549,249 in 1999 and 1998, respectively. The Company reported a loss for the six months ended June 30, 1999, and accordingly the potential effect of dilutive stock options were not included in the computation of diluted earnings per share. 7 Independent Accountant's Report To the Board of Directors and Shareholders Cabot Oil & Gas Corporation: We have reviewed the accompanying condensed consolidated balance sheet and the related condensed consolidated statements of operations and cash flows of Cabot Oil & Gas Corporation (the "Company") as of June 30, 1999, and for the three-month and six-month periods ended June 30, 1999 and 1998. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated financial statements for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet as of December 31, 1998, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended (not presented herein); and, in our report dated February 26, 1999, 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, 1998, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Houston, Texas August 6, 1999 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for the first six months of 1999 and 1998 should be read in conjunction with the Condensed Consolidated Financial Statements of the Company and the Notes thereto included elsewhere in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management's Discussion and Analysis included in the Company's Form 10-K for the year ended December 31, 1998. OVERVIEW As a result of unseasonably mild temperatures, natural gas prices for the first half of 1999 were substantially below those of the same period last year. This decline in gas price was the primary cause of the $6.1 million reduction in net revenues and, along with increased depreciation, depletion and amortization (DD&A) and higher interest expense, largely contributed to the net loss available to common shareholders of $3.2 million, an $8.5 million decline from 1998. Operating cash flows were similarly impacted, declining $14.6 million due to lower natural gas prices, higher interest expenses and changes in working capital. The Company drilled 26 gross wells with a success rate of 85% compared to 84 gross wells and an 86% success rate in the first six months of 1998. Total capital and exploration expenditures were $34.8 million for the first six months of 1999, compared to $75.1 million for the comparable period in 1998. The Company reduced the 1999 capital and exploration expenditures in response to the weak energy price environment in 1999 and in the fourth quarter of 1998. However, the Company front-end loaded the 1999 development and exploration plan to maximize production from this year's drilling program, and to provide more flexibility to drill more wells should cash flows improve later in the year. Accordingly, the Company has increased its capital and exploration expenditures budget by approximately $23 million due to the improving natural gas prices in July and August. For the full year, the Company now plans to drill approximately 76 gross wells and spend approximately $68.1 million in capital and exploration expenditures compared to 205 gross wells and $225.9 million in 1998. Natural gas production was 33.1 Bcf, up 1.0 Bcf compared to the first half of 1998. This production increase was due primarily to production from the Southern Louisiana properties acquired from Oryx Energy Company in the fourth quarter of 1998 (the "Oryx Acquisition"), as well as new production brought on by the 1998 drilling program of 205 gross (143.7 net) wells. The Company's strategic pursuits are sensitive to energy commodity prices, particularly the price of natural gas. As a result of unseasonably warm weather, the Company's realized gas price for the first quarter ($1.91 per Mcf) was the lowest quarterly price since 1995. In the second quarter, gas prices recovered somewhat to $2.08 per Mcf, bringing the year-to-date average price to $1.99 per Mcf. As the third quarter begins, gas prices continue to strengthen. However, there is considerable uncertainty about the level of natural gas prices for the remainder of this year and beyond. The Company remains focused on its strategies to grow through the drill bit, from synergistic acquisitions and from exploitation of its marketing abilities. Management believes that these strategies are appropriate in the current industry environment, enabling the Company to add shareholder value over the long term. The preceding paragraphs, discussing the Company's strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 17. 9 FINANCIAL CONDITION CAPITAL RESOURCES AND LIQUIDITY The Company's capital resources consist primarily of cash flows from its oil and gas properties and asset-based borrowing supported by its oil and gas reserves. The Company's level of earnings and cash flows depend on many factors, including the price of oil and natural gas and its ability to control and reduce costs. Demand for oil and natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. Natural gas prices were unseasonably low during much of 1998 and into the first four months of 1999. In late spring and into the summer, prices began to show improvement bringing the second quarter realized gas price up $0.17 per Mcf to $2.08 compared to the first quarter price of $1.91, but this second quarter price was down $0.16 per Mcf compared to $2.24 from the comparable 1998 period. The primary sources of cash for the Company during the first half of 1999 were from funds generated from operations, increased borrowings on the revolving credit facility, and proceeds from the sale of non-strategic oil and gas properties. Primary uses of cash were funds used in exploration and development expenditures and dividends. The Company had a net cash outflow of $0.3 million in the first half of 1999. Net cash inflow from operating and financing activities totaled $36.1 million through June 1999, sufficiently funding the $45.8 million of capital and exploration expenditures when combined with the $9.4 million of cash proceeds from the sale of non-strategic oil and gas properties. SIX MONTHS ENDED JUNE 30, 1999 1998 ------ ------ (In millions) Cash Flows Provided by Operating Activities.............. $ 31.9 $ 46.5 ====== ====== Cash flows from operating activities in the 1999 first half were lower by $14.6 million compared to the corresponding half of 1998 primarily due to lower natural gas prices, higher interest expense and changes in working capital. SIX MONTHS ENDED JUNE 30, 1999 1998 ------ ------ (In millions) Cash Flows Used by Investing Activities.................. $ 36.4 $ 73.8 ====== ====== Cash flows used by investing activities in the first half of 1999 were attributable to capital and exploration expenditures of $45.8 million, offset by the receipt of $9.4 million in proceeds received from the sale of non-strategic oil and gas properties. Cash flows used by investing activities in the first six months of 1998 were substantially attributable to capital and exploration expenditures of $74.5 million, offset by the receipt of $0.7 million in proceeds from the sale of certain oil and gas properties. SIX MONTHS ENDED JUNE 30, 1999 1998 ------ ------ (In millions) Cash Flows Provided by Financing Activities.............. $ 4.2 $ 29.5 ====== ====== Cash flows provided by financing activities in the first half of 1999 were attributable to increases in borrowings on the Company's revolving credit facility, offset by the payment of $3.7 million in dividends during the period. In 1998, cash flows provided by financing activities were primarily increases in borrowings on the Company's revolving credit facility. The cash from the increased borrowings was used primarily to fund capital and exploration expenditures. During the first six months of 1998, these expenditures included $5 million for leasehold acquisitions as part of the Company's joint exploration program with Union Pacific Resources Group, Inc. as well as $6.6 million for the purchase of 9.3 Bcfe of proved reserves in the Mid-Continent during the second quarter. 10 Under the Company's revolving credit facility, the available credit line, 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 runs to December 2003. Management believes that the Company has the ability to finance, if necessary, its capital requirements, including acquisitions. The Company's 1999 interest expense is projected to be approximately $27 million. In May 2000, a $16 million principal payment is due on the 10.18% Notes. This amount is reflected as "Current Portion of Long-Term Debt" on the Company's balance sheet. This payment is expected to be made with cash from operations and, if necessary, from increased borrowings on the revolving credit facility. YEAR 2000 ("Y2K") Many computer systems have been built using software that processes transactions using two digits to represent the year. This type of software will generally require modifications to function properly with dates after December 31, 1999 (or, to become "Y2K Compliant"). The same issue applies to microprocessors embedded in machinery and equipment, such as gas compressors and pipeline meters. The impact of failing to identify those computer systems (operated by the Company or its business partners) that are not Y2K compliant and correct the problem could be significant to the Company's ability to operate and report results, as well as potentially expose the Company to third-party liability. The Company has begun making the necessary modifications to its computer systems and embedded microprocessors in preparation for the Year 2000. This project is on schedule and the Company believes that the total related costs will be approximately $2.1 million, funded by cash from operations or borrowings on the revolving credit facility, when completed in 1999. Of the total project cost, $1.8 million is attributable to the purchase of new software and equipment that will be capitalized. The remaining $0.3 million is being expensed and is not expected to have a material impact on the Company's financial position or operating results. To date, the Company has incurred $0.2 million of expense, all recorded in 1998, and $1.6 million in capital cost, $1.4 million of which was incurred this year. The Company has reviewed the compliance of field equipment including compressor stations, gas control systems and data logging equipment. Most equipment reviewed was found to be compliant, and, where necessary, microprocessor chips were replaced at a total cost of less than $0.1 million. Additionally, the Company has contacted its significant customers and suppliers in order to determine the Company's exposure to their potential failure to become Y2K compliant. Although the Company is not aware of any Y2K compliance problems with any of its customers or suppliers, there can be no guarantee that the systems of these companies will operate without interruption in the new millennium. The Company has an internal committee that not only identifies and responds to these issues, but also is developing a contingency plan in the event that a significant problem arises after the turn of the century. Management expects the contingency plan to be substantially complete in the third quarter of 1999. Additionally, the Company has engaged outside consultants to review the Company's plans and provide feedback relating to the status of the plan implementation. At this time, the Company does not anticipate that the arrival of the Year 2000 will materially impact its financial position or results of operations. The project costs and timetable for Y2K compliance are based on management's best estimates. In developing these estimates, assumptions were made regarding future events including, among other things, the availability of certain resources and the continued cooperation of the Company's customers and suppliers. Actual costs and timing may differ from management's estimates due to unexpected difficulties in obtaining trained personnel, locating and correcting relevant computer code and other factors. 11 CAPITALIZATION Capitalization information on the Company is as follows: JUNE 30, DECEMBER 31, 1999 1998 ------- ------- (In millions) Long-Term Debt................................. $ 334.0 $ 327.0 Current Portion of Long-Term Debt.............. 16.0 16.0 ------- ------- Total Debt................................... 350.0 343.0 ------- ------- Stockholders' Equity Common Stock (net of Treasury Stock).......... 122.2 126.0 Preferred Stock............................... 56.7 56.7 ------- ------- Total........................................ 178.9 182.7 ------- ------- Total Capitalization........................... $ 528.9 $ 525.7 ======= ======= Debt to Capitalization......................... 66.2% 65.2% During the first half of 1999, the Company paid dividends of $2.0 million on the Common Stock and $1.7 million on the 6% convertible redeemable preferred stock. A regular dividend of $0.04 per share of Common Stock was declared for the quarter ending June 30, 1999, to be paid August 27, 1999, to shareholders of record as of August 13, 1999. The increase in debt was largely attributable to the partial funding of the accelerated drilling program and working capital requirements. CAPITAL AND EXPLORATION EXPENDITURES On an annual basis, the Company generally funds most of its capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations, and budgets such capital expenditures based upon projected cash flows for the year. The following table presents major components of capital and exploration expenditures: SIX MONTHS ENDED JUNE 30, 1999 1998 ------ ------ (In millions) Capital Expenditures Drilling and Facilities..................... $ 20.8 $ 50.0 Leasehold Acquisitions...................... 4.7 9.3 Pipeline and Gathering ..................... 2.0 2.0 Other....................................... 2.3 1.1 ------ ------ 29.8 62.4 ------ ------ Proved Property Acquisitions................ 0.6 6.3 Exploration Expenses.......................... 4.4 6.4 ------ ------ Total....................................... $ 34.8 $ 75.1 ====== ====== Total capital and exploration expenditures in the first half of 1999 decreased $40.3 million compared to the same period of 1998, primarily as a result of the reduced 1999 drilling program. Additionally, in the first quarter of 1998, the Company made an initial expenditure of $5 million for leasehold acquisitions as part of its joint exploration program with Union Pacific Resources Group, Inc. In the second quarter of 1998, the Company also purchased 9.3 Bcfe of proved reserves in the Mid-Continent for $6.6 million. 12 In reaction to lower energy commodity prices, the 1999 budgeted capital and exploration expenditures are down 53% compared to 1998 expenditures after excluding proved property acquisitions. Following the recent improvements in oil and gas prices, the Company's Board of Directors approved increases in the 1999 capital and exploration expenditures budget from $44.9 million to $68.1 million. This new budget includes $39.5 million for drilling and facilities, $11.6 million for exploration expenses, and $4.7 million for pipelines. The Company plans to drill 76 gross wells in 1999 compared with 205 gross wells drilled in 1998. The Company will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. GAS PRICE SWAPS The Company has entered into limited natural gas swap agreements since December 31, 1998, and, accordingly, there have been no material changes in the Company's open natural gas price swap positions. At June 30, 1999, the Company had open natural gas price swap contracts as follows: Swap Purchases -------------------------------------------- Volume Weighted Unrealized in Average Gain (Loss) Period MMBtu Contract Price ($ Millions) - ---------------------------------------------------------------------------- 1999 2,155,000 $2.01 $ 0.5 1st Quarter 2000 450,000 2.13 (0.1) CONCLUSION The Company's financial results depend upon many factors, particularly the price of natural gas and oil, and its ability to market gas on economically attractive terms. The average produced natural gas sales price received in the first half of 1999 was down 12% over the first half of 1998, however, natural gas prices for July and August have improved significantly. Accordingly, the volatility of natural gas prices in recent years remains prevalent in 1999 with wide price swings in day-to-day trading on the Nymex futures market. Given this continued price volatility, management cannot predict with certainty what pricing levels will be for the remainder of 1999. Because future cash flows are subject to such variables, there can be no assurance that the Company's operations will provide cash sufficient to fully fund its planned capital expenditures. The Company believes its capital resources, supplemented, if necessary, with external financing, are adequate to meet its capital requirements. The preceding paragraphs contains forward-looking information. See Forward-Looking Information on page 17. 13 RESULTS OF OPERATIONS For the purpose of reviewing the Company's results of operations, "Net Income/(Loss)" is defined as net income or loss applicable to common shareholders. SELECTED FINANCIAL AND OPERATING DATA THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, --------------- ---------------- 1999 1998 1999 1998 ------ ------ ------ ------ (In millions, except where noted) Net Operating Revenues..................... $ 41.1 $ 41.7 $ 76.3 $ 82.5 Operating Expenses......................... 33.9 31.8 66.3 61.9 Operating Income........................... 8.2 9.9 11.0 20.6 Interest Expense........................... 6.5 4.6 13.2 8.8 Net Income/(Loss).......................... 0.1 2.3 (3.2) 5.3 Earnings/(Loss) Per Share - Basic.......... $ 0.00 $ 0.09 $ (0.13) $ 0.21 Earnings/(Loss) Per Share - Diluted........ $ 0.00 $ 0.09 $ (0.13) $ 0.21 Natural Gas Production (Bcf) Appalachia............................... 5.2 5.6 10.8 10.7 West..................................... 7.4 7.6 14.8 15.1 Gulf Coast............................... 4.4 3.4 7.5 6.3 ------ ------ ------ ------ Total Company............................ 17.0 16.6 33.1 32.1 Natural Gas Production Sales Prices ($/Mcf) Appalachia............................... $ 2.31 $ 2.60 $ 2.28 $ 2.68 West..................................... $ 1.86 $ 1.96 $ 1.79 $ 1.95 Gulf Coast............................... $ 2.16 $ 2.29 $ 1.99 $ 2.27 Total Company............................ $ 2.08 $ 2.24 $ 1.99 $ 2.26 Crude/Condensate Volume (MBbl)............................ 237 141 467 297 Price ($/Bbl)............................ $16.20 $13.55 $13.90 $14.30 Brokered Natural Gas Margin Volume (Bcf)............................. 10.2 8.8 22.9 19.4 Margin ($/Mcf)........................... $ 0.10 $ 0.13 $ 0.08 $ 0.13 SECOND QUARTERS OF 1999 AND 1998 COMPARED Net Income and Revenues. The Company reported net income in the second quarter 1999 of $0.1 million, or $0.00 per share. During the corresponding quarter of 1998, the Company reported net income of $2.3 million, or $0.09 per share. Operating revenues decreased by $0.6 million while operating income decreased by $1.7 million. Natural gas made up 86%, or $35.3 million, of net operating revenue. The decrease in net operating revenues was driven primarily by a 7% decrease in the average natural gas price. Net income and operating income were similarly impacted by the decrease in the average natural gas price, along with increased depreciation, depletion and amortization expense as discussed below. Net income was further affected by a $1.9 million increase in interest expense related to increased debt as discussed below. These decreases were partially offset by a net gain from the sale of non-strategic properties. 14 Natural gas production volume in the Appalachian Region was down 0.4 Bcf to 5.2 Bcf, as a result of a decrease in drilling activity in the Region in 1999. Natural gas production volume in the Western Region was down 0.2 Bcf to 7.4 Bcf, primarily due to lower levels of drilling activity in the Anadarko area during 1998 and 1999. Natural gas production volume in the Gulf Coast Region was up 1.0 Bcf to 4.4 Bcf primarily due to production from the Southern Louisiana properties acquired in December 1998 and recent discoveries in the Kacee field in South Texas. The average Appalachian natural gas production sales price decreased $0.29 per Mcf, or 11%, to $2.31, decreasing net operating revenues by $1.5 million on 5.2 Bcf of production. In the Western Region, the average natural gas production sales price decreased $0.10 per Mcf, or 5%, to $1.86, decreasing net operating revenues by $0.7 million on 7.4 Bcf of production. In the Gulf Coast Region, the average natural gas production sales price decreased $0.13 per Mcf, or 6%, to $2.16, decreasing net operating revenues by $0.6 million on 4.4 Bcf of production. The overall weighted average natural gas production sales price decreased $0.16 per Mcf, or 7%, to $2.08. The volume of crude oil sold by the Company in the second quarter of the year increased by 96 Mbbl, or 68%, to 237 Mbbl, increasing net operating revenues by $1.3 million. The volume increase was largely due to production from the Southern Louisiana properties acquired in the fourth quarter of 1998. Crude oil prices increased $2.65 per Bbl, or 20%, to $16.20, resulting in an increase to net operating revenues of approximately $0.6 million. The brokered natural gas margin decreased $0.1 million to $1.1 million primarily due to a $0.03 per Mcf decrease in the net margin to $0.10 per Mcf. Offsetting this margin reduction, the quarterly volume of brokered gas increased 16%, or 1.4 Bcf, contributing $0.2 million to revenue. Other net operating revenues decreased $0.5 million to $0.8 million due primarily to a reduction in revenues from the monetized value of the Section 29 tax credits on certain tight sands wells, natural gas transportation and sales of natural gas liquids. COSTS AND EXPENSES. Total costs and expenses from operations increased $2.1 million in the second quarter of 1999 compared to the same quarter of 1998. The primary reasons for this fluctuation are as follows: - Direct operating expense increased $0.2 million, or 3%, primarily as a result of the incremental quarterly cost of operating the Southern Louisiana properties acquired in December 1998 partially offset by lower employee related expenses. - Exploration expense decreased $1.0 million, or 32%, primarily as a result of a reduction in dry hole costs from the 1998 second quarter, or one dry hole in the second quarter of 1999 compared to six dry holes in the second quarter of 1998. - Depreciation, depletion, amortization and impairment expense increased $4.1 million, or 36%, in part due to the costs associated with the properties in the Oryx Acquisition, as well as higher finding costs in 1998 on certain fields in the Gulf Coast Region, largely related to drilling and mechanical difficulties. A 5% increase in total Company natural gas equivalent production, including a 44% production increase in the higher cost Gulf Coast Region, was the other major component of the DD&A increase. - General and administrative expenses decreased $1.4 million, or 24%, due to lower accruals on certain incentive plans and non-cash stock awards, along with decreases in salaries and wages associated with reduced headcount and in travel and related costs. - Gain on sale of assets increased $1.0 million due to the sale of certain non-strategic properties in the Gulf Coast Region's Provident City field. 15 Interest expense increased $1.9 million as a result of a higher average level of outstanding debt during the second quarter of 1999 when compared to the second quarter of 1998, primarily due to the debt incurred for the Oryx Acquisition. Income tax expense was down $1.4 million due to the comparable decrease in earnings before income tax. SIX MONTHS OF 1999 AND 1998 COMPARED Net Income and Revenues. The Company reported a net loss in the first half of 1999 of $3.2 million, or $0.13 per share. During the corresponding half of 1998, the Company reported net income of $5.3 million, or $0.21 per share. Operating income and operating revenues decreased $9.6 million and $6.1 million, respectively. Natural gas made up 86%, or $66.0 million, of net operating revenue. The decrease in net operating revenues was driven primarily by a 12% decrease in the average natural gas price, partially offset by a 3% increase in natural gas production as discussed below. Net income and operating income were similarly impacted by the decrease in natural gas prices, and reduced further by increases in operating expenses as discussed below. Net income was further affected by a $4.3 million increase in interest expense related to increased debt as discussed below. These decreases were partially offset by a net gain from the sale of non-strategic properties. Natural gas production volume in the Appalachian Region was up 0.1 Bcf to 10.8 Bcf. Natural gas production volume in the Western Region was down 0.3 Bcf to 14.8 Bcf due primarily lower levels of drilling activity in the Anadarko area during 1998 and into 1999. Natural gas production volume in the Gulf Coast Region was up 1.2 Bcf, or 20%, to 7.5 Bcf primarily due to production from the Oryx Acquisition and recent discoveries in the Kacee field in South Texas. Production growth in the Gulf Coast Region was reduced as a result of drilling and mechanical difficulties encountered in the Beaurline field in 1998. The production from these wells, interrupted during the middle of the third and fourth quarters due to mechanical failures, averaged 17.5 Mmcf per day for the nine months ended September 30, 1998. Production from certain of the replacement wells commenced in the first quarter with the final replacement well completed late in the second quarter of 1999. The field's total proved reserves remained substantially intact. The average Appalachian natural gas production sales price decreased $0.40 per Mcf, or 15%, to $2.28, decreasing net operating revenues by approximately $4.3 million on 10.8 Bcf of production. In the Western Region, the average natural gas production sales price decreased $0.16 per Mcf, or 8%, to $1.79, decreasing net operating revenues by approximately $2.4 million on 14.8 Bcf of production. The average Gulf Coast natural gas production sales price decreased $0.28 per Mcf, or 12%, to $1.99, decreasing net operating revenues by approximately $2.1 million on 7.5 Bcf of production. The overall weighted average natural gas production sales price decreased $0.27 per Mcf, or 12%, to $1.99. The volume of crude oil sold by the Company in the first six months of the year increased by 170 Mbbl, or 57%, to 467 Mbbl, increasing net operating revenues by $2.4 million. The volume increase was largely due to production from the Oryx Acquisition. Crude oil prices decreased $0.40 per Bbl, or 3%, to $13.90, resulting in a decrease to net operating revenues of approximately $0.2 million. The brokered natural gas margin decreased $0.6 million to $1.9 million. The primary cause was a $0.05 per Mcf reduction to net margin that resulted in a $1.1 million revenue decrease. Offsetting the effect of the lower margin, was a 3.5 Bcf volume increase, which resulted in a $0.5 million increase in brokered natural gas margin. Other net operating revenues decreased $1.3 million to $2.0 million due to a $0.4 million reduction in revenues from the monetized value of the Section 29 tax credits on certain tight sands wells along with reductions in transportation revenue and natural gas liquids sales of $0.3 million and $0.4 million, respectively, due to lower activity levels in the first six months of 1999. 16 COSTS AND EXPENSES. Total costs and expenses from operations increased $4.4 million, or 7%, due primarily to the following: - Direct operating expense increased $1.1 million, or 8%, as a result of the incremental cost of operating the Oryx Acquisition properties. - Exploration expense decreased $1.9 million, or 30%, primarily as a result of a reduction in dry hole costs from the first half of 1998, or two dry holes in the first six months of 1999 compared to seven dry holes in the comparable period of 1998. - Depreciation, depletion, amortization and impairment expense increased $7.9 million, or 36%, in part due to the costs associated with the Oryx Acquisition properties, as well as higher finding costs in 1998 on certain fields in the Gulf Coast Region, largely related to drilling and mechanical difficulties. A 5% increase in total Company natural gas equivalent production, including a 34% production increase in the higher cost Gulf Coast Region, was the other major component of the DD&A increase. - General and administrative expenses decreased $2.6 million, or 23%, due to lower accruals on certain incentive plans and non-cash stock awards, along with decreases in salaries and wages associated with reduced headcount and in travel and related costs. - Gain on sale of assets increased $0.9 million due to the sale of certain non-strategic properties in the Gulf Coast Region's Provident City field. Interest expense increased $4.3 million as a result of a higher average level of outstanding debt during the first half of 1999 when compared to the first half of 1998, primarily due to the debt incurred for the Oryx Acquisition in December 1998 and to partially fund the 1998 drilling program. Income tax expense was down $5.5 million due to the comparable decrease in earnings before income tax. * * * FORWARD-LOOKING INFORMATION The statements regarding future financial performance and results, market prices, financing and capital activities, including drilling activities 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 the Company's 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. 17 PART II. OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On May 11, 1999, the Company held its Annual Meeting of Stockholders. In connection with this meeting, the Company's stockholders voted on two matters: the election of three directors and the ratification of the appointment of PricewaterhouseCoopers LLP as the Company's independent auditors. Of the total outstanding shares, 23,093,907, or 92%, were voted. Shareholders approved the re-election of three directors by the following vote: Samuel W. Bodman -------------------------------- Votes cast in favor: 23,002,396 Votes withheld: 91,511 Ray R. Seegmiller -------------------------------- Votes cast in favor: 23,008,643 Votes withheld: 85,264 William P. Vititoe -------------------------------- Votes cast in favor: 23,003,850 Votes withheld: 90,057 The terms of office of directors Robert F. Bailey, Henry O. Boswell, John G.L. Cabot, William R. Esler, William H. Knoell, C. Wayne Nance, P. Dexter Peacock and Charles P. Siess continued beyond the meeting date. The other item presented for a vote before the stockholders was the ratification of the appointment of PricewaterhouseCoopers LLP as the Company's independent certified public accountants. Of the votes received, 23,081,966 were in favor of the ratification, 3,128 were against, and 8,813 abstained. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 15.1 - Awareness letter of independent accountants. 27 - Article 5. Financial Data Schedule for Second Quarter 1999 Form 10-Q (b) Reports on Form 8-K None 18 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) By: /s/ Ray R. Seegmiller August 11, 1999 --------------------------------------------- Ray R. Seegmiller, Chairman of the Board, Chief Executive Officer and President (Principal Executive Officer Duly Authorized to Sign on Behalf of the Registrant) By: /s/ Paul F. Boling --------------------------------------------- Paul F. Boling, Vice President - Finance (Principal Financial Officer) By: /s/ Henry C. Smyth --------------------------------------------- Henry C. Smyth, Controller (Principal Accounting Officer) 19 EXHIBIT 15.1 PricewaterhouseCoopers LLP Awareness Letter Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D. C. 20549 Re: Cabot Oil & Gas Corporation Registration Statements on Form S-8 Commissioners: We are aware that our report dated August 6, 1999 on our review of the condensed consolidated interim financial statements of Cabot Oil & Gas Corporation (the "Company") as of June 30, 1999, and for the three-month and six-month periods then ended, and included in the Company's quarterly report on Form 10-Q is incorporated by reference in the Company's registration statements on Form S-8 filed with the Securities and Exchange Commission on June 23, 1990, November 1, 1993 and May 20, 1994, and Form S-3 filed with the Securities and Exchange Commission on July 27, 1999. Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of the registration statement prepared or certified by us within the meanings of Section 7 and 11 of the Act. PricewaterhouseCoopers LLP Houston, Texas August 6, 1999 20