10-Q 1 f10q093001.txt FORM 10Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 2001 or [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to Commission file number 1-12074 STONE ENERGY CORPORATION (Exact name of registrant as specified in its charter) Delaware 72-1235413 (State or other jurisdiction (I.R.S. employer of incorporation or organization) identification no.) 625 E. Kaliste Saloom Road 70508 Lafayette, Louisiana (Zip code) (Address of principal executive offices) Registrant's telephone number, including area code: (337) 237-0410 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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ As of November 9, 2001, there were 26,189,270 shares of the Registrant's Common Stock, par value $.01 per share, outstanding. TABLE OF CONTENTS Page PART I Item 1. Financial Statements: Condensed Consolidated Balance Sheet as of September 30, 2001 and December 31, 2000.................. 1 Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2001 and 2000. 2 Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2001 and 2000........... 3 Notes to Condensed Consolidated Financial Statements.............. 4 Auditors' Review Report........................................... 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............................. 9 PART II Item 6. Exhibits and Reports on Form 8-K.................................. 13 STONE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (In thousands) September 30, December 31, ASSETS 2001 2000 ------------------ ---------------- (Unaudited) Current assets: Cash and cash equivalents.................................... $20,077 $78,557 Marketable securities, at market............................. - 300 Accounts receivable.......................................... 53,306 95,722 Put contracts................................................ 27,047 1,847 Other current assets......................................... 3,051 2,916 ------------------ ---------------- Total current assets....................................... 103,481 179,342 Oil and gas properties, net: Proved....................................................... 593,268 691,883 Unevaluated.................................................. 67,600 55,691 Building and land, net........................................... 5,377 4,914 Fixed assets, net................................................ 5,058 4,441 Put contracts.................................................... 5,541 3,152 Other assets, net................................................ 2,943 4,681 ------------------ ---------------- Total assets............................................... $783,268 $944,104 ================== ================ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.............................................. $104,657 $116,281 Fair value of swap contracts.................................. 1,664 - Other current liabilities..................................... 2,528 9,996 ------------------ ---------------- Total current liabilities.................................. 108,849 126,277 Long-term debt................................................... 100,000 148,000 Production payments.............................................. 5,917 10,906 Deferred tax liability........................................... 34,417 68,926 Fair value of swap contracts..................................... 4,489 - Other long-term liabilities...................................... 1,284 2,418 ------------------ ---------------- Total liabilities.......................................... 254,956 356,527 ------------------ ---------------- Common stock..................................................... 262 260 Additional paid in capital....................................... 447,027 440,729 Retained earnings................................................ 69,847 146,588 Other comprehensive income....................................... 11,176 - ------------------ ---------------- Total stockholders' equity................................. 528,312 587,577 ------------------ ---------------- Total liabilities and stockholders' equity................. $783,268 $944,104 ================== ================
STONE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (In thousands, except per share amounts) (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, -------------------------------- ------------------------------- 2001 2000 2001 2000 --------------- ------------ ------------- ------------ Revenues Oil and gas production........................ $82,366 $108,536 $331,371 $261,846 Other income.................................. 716 1,011 2,441 2,872 --------------- ------------ ------------- ------------ Total revenues......................... 83,082 109,547 333,812 264,718 --------------- ------------ ------------- ------------ Expenses Normal lease operating expenses............... 12,543 10,754 35,491 29,644 Major maintenance expenses.................... 1,765 2,831 4,371 5,046 Production taxes.............................. 1,736 2,047 5,255 5,668 Depreciation, depletion and amortization...... 47,537 30,589 126,061 83,454 Write-down of oil and gas properties.......... 237,741 - 237,741 - Interest...................................... 771 2,164 2,589 6,989 Salaries, general and administrative.......... 3,194 3,146 9,114 9,057 Incentive compensation plan................... - 504 523 1,092 Hedge premium expense......................... 889 - 2,223 - Merger expenses............................... 88 - 25,719 - --------------- ------------ ------------- ------------ Total expenses......................... 306,264 52,035 449,087 140,950 --------------- ------------ ------------- ------------ Net income (loss) before income taxes........... (223,182) 57,512 (115,275) 123,768 --------------- ------------ ------------- ------------ Income tax provision (benefit): Current....................................... - 205 500 272 Deferred...................................... (78,114) 19,925 (39,034) 43,047 --------------- ------------ ------------- ------------ (78,114) 20,130 (38,534) 43,319 --------------- ------------ ------------- ------------ Net income (loss)............................... ($145,068) $37,382 ($76,741) $80,449 =============== ============ ============= ============ Earnings per common share: Basic earnings (loss) per share ............. ($5.54) $1.45 ($2.94) $3.12 =============== ============ ============= ============ Diluted earnings (loss) per share............ ($5.54) $1.42 ($2.94) $3.06 =============== ============ ============= ============ Average shares outstanding................... 26,184 25,839 26,084 25,772 =============== ============ ============= ============ Average shares outstanding assuming dilution.................................. 26,184 26,388 26,084 26,277 =============== ============ ============= ============
STONE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands) (Unaudited) Nine Months Ended September 30, -------------------------------------- 2001 2000 ---------------- ---------------- Cash flows from operating activities: Net income (loss)............................................. ($76,741) $80,449 Adjustments to reconcile net income (loss) to net cash provided by operating activities: DD&A.................................................... 126,061 83,454 Write-down of oil and gas properties.................... 237,741 - Provision (benefit) for deferred income taxes........... (39,034) 43,047 Non-cash effect of production payments.................. (4,691) (4,279) Amortization of hedge premiums.......................... 2,223 - Other non-cash expenses................................. 912 922 ---------------- ---------------- 246,471 203,593 Decrease in marketable securities..................... 300 34,606 (Increase) decrease in accounts receivable............ 42,416 (29,088) (Increase) decrease in other current assets........... (526) 1,021 Increase (decrease) in other accrued liabilities...... (10,152) 10,755 Investment in put contracts........................... (6,466) - Other................................................. (1,251) 214 ---------------- ---------------- Net cash provided by operating activities....................... 270,792 221,101 ---------------- ---------------- Cash flows from investing activities: Investment in oil and gas properties....................... (286,518) (187,284) Building additions and renovations......................... (562) (1,007) Sale of unevaluated properties............................. 1,366 3,790 Increase in other assets .................................. (159) (1,571) ---------------- ---------------- Net cash used in investing activities........................... (285,873) (186,072) ---------------- ---------------- Cash flows from financing activities: Proceeds from borrowings..................................... 5,000 59,000 Repayment of debt............................................ (53,000) (45,000) Deferred financing costs..................................... - (200) Purchase of treasury stock................................... (200) (649) Proceeds from the exercise of stock options.................. 4,801 3,067 ---------------- ---------------- Net cash provided by (used in) financing activities............. (43,399) 16,218 ---------------- ---------------- Net increase (decrease) in cash and cash equivalents............ (58,480) 51,247 Cash and cash equivalents, beginning of period.................. 78,557 17,651 ---------------- ---------------- Cash and cash equivalents, end of period........................ $20,077 $68,898 ================ ================ Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (net of amount capitalized)...................... $4,715 $8,640 Income taxes.............................................. 500 272
STONE ENERGY CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - INTERIM FINANCIAL STATEMENTS The condensed consolidated financial statements of Stone Energy Corporation at September 30, 2001 and for the three- and nine-month periods then ended are unaudited and reflect all adjustments (consisting only of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim period. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management's discussion and analysis of financial condition and results of operations, contained in our Current Report on Form 8-K filed on September 20, 2001. The results of operations for the three- and nine-month periods ended September 30, 2001 are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation. In accordance with the pooling of interests method of accounting for a merger transaction, all results were combined to give effect to the merger of Stone and Basin Exploration, Inc. Prior to the merger, Basin accounted for depreciation, depletion and amortization (DD&A) of oil and gas properties using the units of production method. In connection with the restatement of our financial statements on a pooling-of-interests basis, Basin's historical provision for DD&A was restated to conform to the future gross revenue method used by Stone. This restatement included related adjustments to Basin's historical reduction in carrying value of oil and gas properties recorded at the end of 1998 and their historical provision for income taxes. All periods presented reflect the effects of these adjustments. In addition, we reclassified certain amounts in Basin's historical financial statements to conform to Stone's presentation. NOTE 2 - EARNINGS PER SHARE In periods of net losses, basic and dilutive net income per share of common stock are calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the period. In addition, the weighted-average number of options granted to outside directors and employees that are traditionally considered dilutive are added to anti-dilutive shares for those periods. Since we reported net losses for the three- and nine-month periods ended September 30, 2001, there were no dilutive shares for those periods and antidilutive shares totaled approximately 1,053,000 and 962,000 shares, respectively. Dilutive shares for the third quarter and first nine months of 2000 totaled approximately 549,000 and 505,000 shares, respectively. Antidilutive shares for the these periods only included options whose exercise price exceeded the average price of our stock and totaled approximately 391,000 and 286,000 shares, respectively. NOTE 3 - CEILING TEST WRITE-DOWN The Securities and Exchange Commission requires companies to calculate a comparison of net capitalized costs of proved oil and gas properties to the discounted present value of future cash flows from the related reserves. The calculation is made using commodity prices held flat for the life of the reserves. If capitalized costs exceed discounted cash flows, the assets are required to be written down to the value of the discounted cash flows. We have historically used commodity prices on the last day of the quarter for reserve valuation purposes including the calculation of the ceiling test. As a result of the low natural gas price on September 30, 2001, we recorded a $237.7 million non-cash write-down of our oil and gas properties during the third quarter of 2001. Throughout September 2001, natural gas prices declined and closed on September 30, 2001 at $1.83 per MMBtu. The price volatility of today's natural gas market makes it difficult to determine the appropriate pricing for valuation as illustrated by the price change between September 30, 2001 and October 31, 2001. The September 30, 2001 natural gas price, which was used in calculating the ceiling test write-down that we recorded in third quarter of 2001, is significantly different from the closing price of natural gas on October 31, 2001 of $3.29 per MMBtu. If our discounted cash flows were valued using October 31, 2001 prices, no ceiling test write-down would have occurred. While use of the lower quarter-end natural gas price did result in an oil and gas property write-down, it did not result in the loss of any proved reserves. NOTE 4 - HEDGING ACTIVITIES We enter into hedging transactions to secure a price for a portion of future production that is acceptable at the time at which the transaction is entered into. The primary objective of these activities is to reduce our exposure to the possibility of declining oil and gas prices during the term of the hedge. We do not enter into hedging transactions for trading purposes. We currently utilize two forms of hedging contracts: fixed price swaps and puts. Fixed price swaps typically provide for monthly payments by us if NYMEX prices rise above the fixed swap price or to us if prices fall below the fixed swap price. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contracts represents our maximum cash exposure. We are not obligated to make any further payments under the put contracts regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above that floor. Since over 90% of our production has historically been derived from the Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely match changes in the market price we receive for our production. Oil contracts typically settle using the average of the daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices of near month NYMEX futures contracts for three days prior to the settlement date. The following table shows our hedging position as of October 1, 2001. Puts ---------------------------------------------------------- Gas Oil --------------------------- --------------------------- Volume Volume (BBtus) Floor (Bbls) Floor ----------- ----------- ------------ ----------- 2001............. 7,360 $3.50 322,000 $25.00 2002............. 21,900 3.50 1,277,500 24.00 Fixed Price Gas Swaps ------------------------------------------ Volume (BBtus) Price ------------------- ------------------ 2001............. 1,840 $2.33 2002............. 3,650 2.15 2003............. 3,650 2.15 During the third quarters of 2001 and 2000, we realized net increases (decreases) in oil and gas revenues related to hedging transactions of $2.6 million and ($14.1) million, respectively. Nine-month 2001 and 2000 oil and gas revenues included net decreases of ($10.5) million and ($26.3) million, respectively. During the third quarter and first nine months of 2001, we recognized $0.9 million and $2.2 million of hedge premium expenses, which represents amortization of the historical cost associated with oil and gas put contracts that settled during the respective periods of 2001. At September 30, 2001, the unsettled put contracts were recorded as assets totaling $32.6 million and the unsettled gas swaps were recorded as liabilities totaling $6.2 million. All changes in fair values of the puts and swaps were recorded net of taxes in equity through other comprehensive income (See Note 7). NOTE 5 - LONG-TERM DEBT At September 30, 2001, the borrowing base under our current credit facility was $200 million with outstanding letters of credit totaling $7.3 million and no outstanding borrowings. We are currently negotiating a new bank credit facility that will, among other things, increase our credit facility from $200 million to $400 million. We expect to finance a portion of the Conoco property acquisition (See Note 9) with borrowings under this credit facility. NOTE 6 - PRODUCTION PAYMENTS In 1999, we acquired a 51% working interest in the Lafitte Field by executing an agreement that included a dollar-denominated production payment to be satisfied through the sale of production from the purchased property. Based on the quarterly revaluation of this transaction, at September 30, 2001, the production payment associated with this purchase totaled $1.4 million. In July 1999, we acquired an additional working interest in East Cameron Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a volumetric production payment. This agreement requires that 7.3 MMcf of gas per day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have been distributed. We amortize the volumetric production payment as specified deliveries of gas are made to the seller and recognize non-cash revenue in the form of gas production revenues. At September 30, 2001, the volumetric production payment was $4.5 million, and we recognized $1.5 million and $4.5 million as gas revenues during each of the three- and nine-month 2001 and 2000 periods, respectively. NOTE 7 - COMPREHENSIVE INCOME Prior to the adoption of SFAS No. 133, the only component of comprehensive income on our balance sheet was net income. Effective January 1, 2001, we adopted SFAS No. 133 which created other components of comprehensive income as presented in the table below. Three Months Ended Nine Months Ended September 30, September 30, ------------------------------ ------------------------------ 2001 2000 2001 2000 ------------- ------------- ------------ ------------- (in thousands) Net income (loss).......................................... ($145,068) $37,382 ($76,741) $80,449 Other comprehensive income (loss), net of tax effect: Cumulative effect of accounting change for derivatives..................................... - - (26,114) - Net change in fair value of derivatives............... 12,913 - 37,290 - ------------- ------------- ------------- ------------- Total other comprehensive income.................... 12,913 - 11,176 - ------------- ------------- ------------- ------------- Comprehensive income (loss)................................ ($132,155) $37,382 ($65,565) $80,449 ============= ============= ============= =============
NOTE 8 - NEW ACCOUNTING STANDARD In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," effective for fiscal years beginning after June 15, 2002. This statement will require us to record the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we will be required to recognize cumulative transition amounts for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. We have not yet determined the transition amounts. NOTE 9 - ACQUISITION OF CONOCO PROPERTIES During October 2001, we entered into asset and stock purchase agreements to acquire up to $300 million of oil and gas properties located in the Gulf of Mexico from Conoco, Inc. A substantial portion of the offered price is attributable to properties that are subject to elections by third party working interest owners to exercise their preferential rights. We plan to finance the acquisition through a combination of borrowings under our credit facility and other long-term debt instruments. We expect to close the transaction by December 31, 2001. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE STOCKHOLDERS OF STONE ENERGY CORPORATION: We have reviewed the accompanying condensed consolidated balance sheet of Stone Energy Corporation (a Delaware corporation) as of September 30, 2001, and the related condensed consolidated statements of operations for the three-month and nine-month periods ended September 30, 2001 and 2000, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our reviews 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 auditing standards generally accepted in the United States, 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 reviews, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the balance sheet of Stone Energy Corporation as of December 31, 2000, included in the Company's Form 8-K dated September 20, 2001, (not presented herein), and, in our report therein dated February 23, 2001, we expressed an unqualified opinion on that statement. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived. ARTHUR ANDERSEN LLP New Orleans, Louisiana October 30, 2001 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Throughout this document we make statements that are classified as "forward-looking". Please refer to the "Forward-Looking Statements" section on page 12 of this document for an explanation of these types of assertions. We use the terms "Stone", "Stone Energy", "Company", "we", "us" and "our" to refer to Stone Energy Corporation. Results for all periods reflect the combination of Stone and Basin. OVERVIEW Stone Energy Corporation is an independent oil and gas company engaged in the acquisition, exploration, development and operation of oil and gas properties in the Gulf Coast Basin and Rocky Mountains. Our business strategy is to increase production, cash flow and reserves through the acquisition and development of mature properties. Currently, our property base consists of 80 productive properties, 48 in the Gulf Coast Basin and 32 in the Rocky Mountains, and 40 Gulf Coast Basin primary term leases. We serve as operator on 52 of our producing properties, which enables us to better control the timing and cost of rejuvenation activities. We believe that there will continue to be opportunities to acquire properties in the Gulf Coast Basin due to the increased focus by major and large independent companies on projects away from the onshore and shallow water shelf regions of the Gulf of Mexico. BASIS OF PRESENTATION In accordance with the pooling of interests method of accounting for a merger transaction, all results were combined to give effect to the merger of Stone and Basin Exploration, Inc. Prior to the merger, Basin accounted for depreciation, depletion and amortization (DD&A) of oil and gas properties using the units of production method. In connection with the restatement of our financial statements on a pooling-of-interests basis, Basin's historical provision for DD&A was restated to conform to the future gross revenue method used by Stone. This restatement included related adjustments to Basin's historical reduction in carrying value of oil and gas properties recorded at the end of 1998 and their historical provision for income taxes. All periods presented reflect the effects of these adjustments. In addition, we reclassified certain amounts in Basin's historical financial statements to conform to Stone's presentation. RESULTS OF OPERATIONS The following table sets forth certain operating information with respect to our oil and gas operations. Three Months Ended Nine Months Ended September 30, September 30, ---------------------------- --------------------------- 2001 2000 2001 2000 ------------ ----------- ----------- ----------- PRODUCTION: Oil (MBbls)............................................... 1,027 1,125 3,075 3,273 Gas (MMcf): Produced excluding volumetric production payment........ 17,066 19,164 50,725 51,691 Volumetric production payment........................... 672 667 1,993 2,000 ------------ ----------- ----------- ----------- Total gas volumes produced............................. 17,738 19,831 52,718 53,691 Oil and gas (MMcfe): Produced excluding volumetric production payment........ 23,228 25,914 69,175 71,329 Volumetric production payment........................... 672 667 1,993 2,000 ------------ ----------- ----------- ----------- Total oil and gas volumes produced..................... 23,900 26,581 71,168 73,329 SALES DATA (IN THOUSANDS) (a): Oil....................................................... $27,108 $31,838 $84,282 $84,718 Gas: Gas sales excluding volumetric production payment...... 53,764 75,204 242,607 172,646 Volumetric production payment.......................... 1,494 1,494 4,482 4,482 ------------ ----------- ----------- ----------- Total gas sales........................................ 55,258 76,698 247,089 177,128 AVERAGE SALES PRICES (a): Oil (per Bbl)............................................. $26.40 $28.30 $27.41 $25.88 Gas (per Mcf): Price excluding volumetric production payment.......... 3.15 3.92 4.78 3.34 Volumetric production payment.......................... 2.24 2.24 2.24 2.24 Net average price...................................... 3.12 3.87 4.69 3.30 Oil and gas (per Mcfe): Price excluding volumetric production payment.......... 3.48 4.13 4.73 3.61 Volumetric production payment.......................... 2.24 2.24 2.24 2.24 Net average price ..................................... 3.45 4.08 4.66 3.57 EXPENSES (per Mcfe): Normal lease operating expenses (b)....................... $0.52 $0.40 $0.50 $0.40 Salaries, general and administrative...................... 0.13 0.12 0.13 0.12 DD&A on oil and gas properties............................ 1.97 1.14 1.75 1.12
(a) Includes the effects of hedging (b) Excludes major maintenance expenses NET INCOME. For the third quarter of 2001, we reported a net loss totaling $145.1 million, or $5.54 per share, compared to net income reported for the third quarter of 2000 of $37.4 million, or $1.42 per share. Net income (loss) for the first nine months of 2001 and 2000 totaled ($76.7) million and $80.4 million, or ($2.94) and $3.06 per share, respectively. Included in third quarter and nine-month 2001 results was a non-cash write-down of oil and gas properties totaling $237.7 million or $154.5 million after taxes. In addition, during the third quarter of 2001, non-recurring merger expenses totaled $0.1 million, bringing total 2001 merger expenses from the Basin transaction to $25.7 million, or $18.5 million after taxes. Excluding merger expenses and the non-cash write-down, net income for the three- and nine-months ended September 30, 2001 totaled $9.5 million, or $0.36 per share, and $96.3 million, or $3.64 per share, respectively. The Securities and Exchange Commission requires companies to calculate a comparison of net capitalized costs of proved oil and gas properties to the discounted present value of future cash flows from the related reserves. The calculation is made using commodity prices held flat for the life of the reserves. If capitalized costs exceed discounted cash flows, the assets are required to be written down to the value of the discounted cash flows. We have historically used commodity prices on the last day of the quarter for reserve valuation purposes including the calculation of the ceiling test. Throughout September 2001, natural gas prices declined and closed on September 30, 2001 at $1.83 per MMBtu. The price volatility of today's natural gas market makes it difficult to determine the appropriate pricing for valuation as illustrated by the price change between September 30, 2001 and October 31, 2001. The September 30, 2001 natural gas price, which was used in calculating the ceiling test write-down that we recorded in third quarter of 2001, is significantly different from the closing price of natural gas on October 31, 2001 of $3.29 per MMBtu. If our discounted cash flows were valued using October 31, 2001 prices, no ceiling test write-down would have occurred. While use of the lower quarter-end natural gas price did result in an oil and gas property write-down, it did not result in the loss of any proved reserves. OIL AND GAS REVENUES. As a result of lower realized prices and reduced production volumes, oil and gas revenues for the third quarter of 2001 declined to $82.4 million, compared to $108.5 million for the third quarter of 2000. Year-to-date oil and gas revenues increased to $331.4 million compared to $261.8 million during the comparable 2000 period. PRICES. Prices realized during the third quarter of 2001 averaged $26.40 per barrel of oil and $3.12 per Mcf of gas. This represents a 15% decrease, on a thousand cubic feet of gas equivalent (Mcfe) basis, from third quarter 2000 average realized prices of $28.30 per barrel of oil and $3.87 per Mcf of gas. Average realized prices during the first nine months of 2001 were $27.41 per barrel of oil and $4.69 per Mcf of gas compared to $25.88 per barrel of oil and $3.30 per Mcf of gas realized during the first nine months of 2000. All unit pricing amounts include the effects of hedging. PRODUCTION. Natural gas production during the third quarter of 2001 decreased to approximately 17.7 billion cubic feet compared to third quarter 2000 gas production of 19.8 billion cubic feet, while oil production during the third quarter of 2001 totaled approximately 1 million barrels compared to 1.1 million barrels of oil produced during the third quarter of 2000. On a gas equivalent basis, production volumes for the third quarter of 2001 declined to 23.9 Bcfe compared to third quarter 2000 production of 26.6 Bcfe. Year-to-date 2001 production totaled 3.1 million barrels of oil and 52.7 billion cubic feet of gas while year-to-date 2000 production totaled 3.3 million barrels of oil and 53.7 billion cubic feet of gas. During the third quarter of 2000, we recorded the highest oil and gas production volumes in our history. On an Mcfe basis, production volumes for the third quarter of 2001 declined 10% from third quarter 2000 volumes. The decline in our 2001 production rate has been the result of normal production declines. Typically, we are able to offset these declines by bringing new wells on production soon after drilling operations have been completed. During 2001 however, we have drilled multiple successful wells that we were unable to immediately place on production due to the need for substantial production facilities. We expect to have the facilities in place and the wells on full production by January 2002, at which point we expect a 16% increase in our production over our estimated average rate for 2001 of 255 MMcfe per day. EXPENSES. Normal operating costs during the third quarter of 2001 totaled $12.5 million, compared to $10.8 million for the comparable quarter in 2000. The increase in operating costs was due primarily to industry-wide increases in the costs of oil field products and services. Depreciation, depletion and amortization (DD&A) expense on oil and gas properties for the third quarter of 2001 totaled $47.1 million or $1.97 per Mcfe, compared to $30.2 million or $1.14 per Mcfe for the third quarter of 2000. Third quarter 2001 DD&A expense was negatively impacted by significantly lower quarter-end natural gas prices. Year-to-date 2001 DD&A expense on oil and gas properties totaled $124.8 million, or $1.75 per Mcfe, compared to $82.2 million, or $1.12 per Mcfe, for the comparable period in 2000. General and administrative expenses for the third quarter of 2001 totaled $3.2 million, or $0.13 per Mcfe, compared to $3.1 million, or $0.12 per Mcfe, for the third quarter of 2000. As a result of the repayment of all bank debt in February 2001 and the increase in capitalized interest on unevaluated properties, interest expense for the third quarter of 2001 decreased to $0.8 million from $2.2 million for the comparable 2000 period. Our estimated effective tax rate is 35%. However, we estimated that approximately $5.2 million of merger-related expenses were not tax deductible. The exclusion of these expenses had a 2% impact on the effective tax rate for the first nine months of 2001. HEDGING ACTIVITIES During the third quarter of 2001, hedging transactions increased the average price we received for gas by $0.15 per Mcf compared to net decreases of $3.34 per barrel and $0.54 per Mcf for the third quarter of 2000. Hedging transactions for the first nine months of 2001 reduced the average price we received for gas by $0.21 per Mcf compared to net decreases of $3.64 per barrel and $0.28 per Mcf for the comparable 2000 period. During the third quarter and first nine months of 2001, we recognized $0.9 million and $2.2 million of hedge premium expenses, which represents amortization of the historical cost associated with oil and gas put contracts that settled during the respective periods of 2001. At September 30, 2001, the unsettled put contracts were recorded as assets totaling $32.6 million and the unsettled gas swaps were recorded as liabilities totaling $6.2 million. All changes in fair values of the puts and swaps were recorded in equity through other comprehensive income. LIQUIDITY AND CAPITAL RESOURCES CASH FLOW. Net cash flow from operations before working capital changes for the third quarter and first nine months of 2001 was $61.5 million, or $2.35 per share, and $246.5 million, or $9.45 per share, compared to $86.8 million and $203.6 million, or $3.29 and $7.75 per share, reported for the respective periods of 2000. Excluding the effect of non-recurring merger expenses, net cash flow from operations for the third quarter of 2001 was $61.5 million and for the first nine months of 2001 was $265 million. CAPITAL EXPENDITURES. Capital expenditures excluding acquisition costs during the third quarter of 2001 totaled $82.7 million, including $2.2 million of capitalized salaries, general and administrative expenses and $1.6 million of capitalized interest. Capital expenditures excluding acquisition costs for the first nine months of 2001 totaled $264.3 million, including $7.8 million of capitalized salaries, general and administrative expenses and $4.8 million of capitalized interest. Oil and gas property acquisition costs totaled $1 million and $12.8 million during the three- and nine-month periods ended September 30, 2001. These investments were financed by cash flow from operations and working capital. BUDGETED CAPITAL EXPENDITURES. Our 2001 capital expenditures budget, excluding acquisitions, capitalized salaries, general and administrative costs and interest, is currently $290 million. As of November 1, 2001, we spudded 66 of the 70 gross wells planned for 2001. Of the 70 wells, 50 are in the onshore and shallow water offshore regions of the Gulf Coast Basin and 20 are in the Rocky Mountains. Based upon our outlook of oil and gas prices and production rates, we believe that our cash on hand and cash flow from operations will be sufficient to fund the remainder of our 2001 capital expenditures budget. Currently, we estimate that our daily production rate will average 255 MMcfe for 2001. If oil and gas prices or production rates fall below our current expectations, we believe that the available borrowings under our bank credit facility will be sufficient to fund the capital expenditures in excess of operating cash flow. Although we do not budget acquisitions, we continue to evaluate properties and transaction alternatives to add to our existing property base. On October 10, 2001, we announced that we had entered into asset and stock purchase agreements to acquire up to $300 million of oil and gas properties located in the Gulf of Mexico from Conoco, Inc. A substantial portion of the offered price is attributable to properties that are subject to elections by third party working interest owners to exercise their preferential rights. We expect to close the transaction by December 31, 2001. We expect to finance the Conoco property acquisition through a combination of borrowings under our credit facility and other long-term debt instruments. Our borrowing base is currently $200 million with outstanding letters of credit totaling $7.3 million and no outstanding borrowings. We are currently negotiating a new bank credit facility that will, among other things, increase our credit facility from $200 million to $400 million. FORWARD-LOOKING STATEMENTS. This Form 10-Q and the information incorporated by reference contain statements that constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. The words "expect", "project", "estimate", "believe", "anticipate", "intend", "budget", "plan", "forecast", "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Stone Energy Corporation are expressly qualified in their entirety by this cautionary statement. PART II ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits *15.1 - Letter from Arthur Andersen LLP dated November 9, 2001, regarding unaudited interim financial information. * Filed herewith (b) We filed the following reports on Form 8-K during the three months ended September 30, 2001: Date of Event Reported Item Reported ---------------------- ------------- September 20, 2001 Items 5, 7 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. STONE ENERGY CORPORATION Date: November 9, 2001 By: /s/James H. Prince ------------------------------ James H. Prince Vice President, Chief Financial Officer and Treasurer (On behalf of Registrant and as Principal Financial Officer)