10-Q 1 ee3q2003.txt SWIFT ENERGY COMPANY 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 September 30, 2003 Commission File Number 1-8754 SWIFT ENERGY COMPANY (Exact Name of Registrant as Specified in its Charter) TEXAS 74-2073055 (State of Incorporation) (I.R.S. Employer Identification No.) 16825 Northchase Drive, Suite 400 Houston, Texas 77060 (281) 874-2700 (Address and telephone number of principal executive offices) 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 and 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 Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date. Common Stock 27,444,262 Shares ($.01 Par Value) (Outstanding at October 31, 2003) (Class of Stock) SWIFT ENERGY COMPANY FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003 INDEX
PART I. FINANCIAL INFORMATION PAGE Item 1. Consolidated Financial Statements Consolidated Balance Sheets - September 30, 2003 and December 31, 2002 3 Consolidated Statements of Income - For the Three-month and Nine-month periods ended September 30, 2003 and 2002 5 Consolidated Statements of Stockholders' Equity - September 30, 2003 and December 31, 2002 6 Consolidated Statements of Cash Flows - For the Nine-month periods ended September 30, 2003 and 2002 7 Notes to Consolidated Financial Statements 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 19 Item 3. Quantitative and Qualitative Disclosures About Market Risk 30 Item 4. Controls and Procedures 31 PART II. OTHER INFORMATION Item 1. Legal Proceedings 32 Item 2. Changes in Securities and Use of Proceeds None Item 3. Defaults Upon Senior Securities None Item 4. Submission of Matters to a Vote of Security Holders None Item 5. Other None Item 6. Exhibit Index and Reports on Form 8-K 32 SIGNATURES 33
2 SWIFT ENERGY COMPANY CONSOLIDATED BALANCE SHEETS
September 30, 2003 December 31, 2002 ------------------------ ------------------------- (Unaudited) ASSETS Current Assets: Cash and cash equivalents $ 2,678,315 $ 3,816,107 Accounts receivable - Oil and gas sales 23,335,323 17,360,716 Associated limited partnerships and joint ventures 143,190 191,964 Joint interest owners 1,400,790 3,364,846 Other current assets 4,695,602 5,034,566 ------------------------ ------------------------- Total Current Assets 32,253,220 29,768,199 ------------------------ ------------------------- Property and Equipment: Oil and gas, using full-cost accounting Proved properties being amortized 1,264,918,011 1,150,633,802 Unproved properties not being amortized 65,642,790 69,603,481 ------------------------ -------------------------- 1,330,560,801 1,220,237,283 Furniture, fixtures, and other equipment 10,204,883 9,595,944 ------------------------ ------------------------- 1,340,765,684 1,229,833,227 Less-Accumulated depreciation, depletion, and amortization (551,095,515) (504,323,773) ------------------------ ------------------------- 789,670,169 725,509,454 ------------------------ ------------------------- Other Assets: Deferred income taxes 433,591 2,680,585 Deferred charges 8,279,976 9,047,621 ------------------------ ------------------------- 8,713,567 11,728,206 ------------------------ ------------------------- $ 830,636,956 $ 767,005,859 ======================== =========================
See accompanying notes to consolidated financial statements. 3 SWIFT ENERGY COMPANY CONSOLIDATED BALANCE SHEETS
September 30, 2003 December 31, 2002 ------------------------ ------------------------ (Unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 51,681,138 $ 43,028,708 Payable to associated limited partnerships 514,309 91,126 Undistributed oil and gas revenues 5,527,236 3,764,350 ------------------------ ------------------------ Total Current Liabilities 57,722,683 46,884,184 ------------------------ ------------------------ Long-Term Debt 336,233,381 324,271,973 Deferred Income Taxes 39,248,246 30,776,518 Asset Retirement Obligation 9,834,695 --- Commitments and Contingencies Stockholders' Equity: Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding --- --- Common stock, $.01 par value, 85,000,000 shares authorized, 27,968,640 and 27,811,632 shares issued, and 27,441,622 and 27,201,509 shares outstanding, respectively 279,686 278,116 Additional paid-in capital 334,418,690 333,543,471 Treasury stock held, at cost, 527,018 and 610,123 shares, respectively (7,558,093) (8,749,922) Retained earnings 60,571,708 40,179,572 Other comprehensive loss, net of taxes (114,040) (178,053) ------------------------ ------------------------ 387,597,951 365,073,184 ------------------------ ------------------------ $ 830,636,956 $ 767,005,859 ======================== ========================
See accompanying notes to consolidated financial statements. 4 SWIFT ENERGY COMPANY Consolidated Statements of Income (UNAUDITED)
Three months ended Nine months ended ------------------------------ --------------------------------- 09/30/03 09/30/02 09/30/03 09/30/02 -------------- ------------- ---------------- -------------- Revenues: Oil and gas sales $ 52,087,321 $ 36,592,329 $ 157,846,870 $ 101,536,512 Fees from limited partnerships and joint ventures 5,577 5,830 20,512 59,953 Interest income 26,279 158,664 136,747 190,957 Gain on asset disposition --- --- --- 7,332,668 Price-risk management and other, net (566,655) (186,014) (2,234,085) 375,065 -------------- ------------- ---------------- -------------- 51,552,522 36,570,809 155,770,044 109,495,155 -------------- ------------- ---------------- -------------- Costs and Expenses: General and administrative, net 3,670,416 2,497,413 10,564,959 7,368,989 Depreciation, depletion and amortization 16,042,377 13,487,437 46,630,689 41,789,711 Accretion of asset retirement obligation 206,475 --- 623,761 --- Oil and gas production 13,730,467 11,004,641 39,392,531 30,602,493 Interest expense, net 6,749,419 6,647,968 20,107,188 16,607,651 -------------- ------------- ---------------- -------------- 40,399,154 33,637,459 117,319,128 96,368,844 -------------- ------------- ---------------- -------------- Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle 11,153,368 2,933,350 38,450,916 13,126,311 Provision for Income Taxes 4,090,743 986,344 13,681,928 4,575,403 -------------- ------------- ---------------- -------------- Income Before Cumulative Effect of Change in Accounting Principle 7,062,625 1,947,006 24,768,988 8,550,908 Cumulative Effect of Change in Accounting Principle (net of taxes) --- --- 4,376,852 --- -------------- ------------- ---------------- -------------- Net Income $ 7,062,625 $ 1,947,006 $ 20,392,136 $ 8,550,908 ============== ============= ================ ============== Per share amounts - Basic: Income Before Cumulative Effect of Change in Accounting Principle $ 0.26 $ 0.07 $ 0.91 $ 0.33 Cumulative Effect of Change in Accounting Principle --- --- (0.16) --- -------------- ------------- ---------------- -------------- Net Income $ 0.26 $ 0.07 $ 0.75 $ 0.33 ============== ============= ================ ============== Diluted: Income Before Cumulative Effect of Change in Accounting Principle $ 0.26 $ 0.07 $ 0.90 $ 0.32 Cumulative Effect of Change in Accounting Principle --- --- (0.16) --- -------------- ------------- ---------------- -------------- Net Income $ 0.26 $ 0.07 $ 0.74 $ 0.32 ============== ============= ================ ============== Weighted Average Shares Outstanding 27,424,195 26,889,186 27,326,169 26,112,382 ============== ============= ================ ==============
See accompanying notes to consolidated financial statements. 5 SWIFT ENERGY COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Accumulated Additional Other Common Paid-in Treasury Retained Comprehensive Stock (1) Capital Stock Earnings Loss Total ---------- -------------- ------------- -------------- --------------- -------------- Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ - $ 312,652,720 Stock issued for benefit plans (38,149 shares) 292 617,960 127,795 - - 746,047 Stock options exercised (112,995 shares) 1,130 1,206,413 - - - 1,207,543 Public stock offering (1,725,000 shares) 17,250 30,465,809 - - - 30,483,059 Employee stock purchase plan (9,801 shares) 98 122,343 - - - 122,441 Stock issued in acquisitions (520,000 shares) 3,000 4,958,126 3,155,074 - - 8,116,200 Comprehensive income: Net income - - - 11,923,227 - 11,923,227 Change in fair value of cash flow hedges, net of income tax - - - - (178,053) (178,053) -------------- Total comprehensive income - - - - - 11,745,174 ---------- -------------- ------------- -------------- --------------- -------------- Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ 40,179,572 $ (178,053) $ 365,073,184 ========== ============== ============= ============== =============== ============== Stock issued for benefit plans (83,201 shares) (2) 1 (408,178) 1,191,829 - - 783,652 Stock options exercised (100,338 shares) (2) 1,003 869,450 - - - 870,453 Employee stock purchase plan (56,574 shares) (2) 566 413,947 - - - 414,513 Comprehensive income: Net income (2) - - - 20,392,136 - 20,392,136 Change in fair value of cash flow hedges, net of income tax (2) - - - - 64,013 64,013 -------------- Total comprehensive income (2) - - - - - 20,456,149 ---------- -------------- ------------- -------------- --------------- -------------- Balance, September 30, 2003 (2) $ 279,686 $ 334,418,690 $ (7,558,093) $ 60,571,708 $ (114,040) $ 387,597,951 ========== ============== ============= ============== =============== ==============
(1)$.01 par value (2) Unaudited See accompanying notes to consolidated financial statements. 6 SWIFT ENERGY COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Period Ended September 30, ----------------------------------------------- 2003 2002 --------------------- -------------------- Cash Flows From Operating Activities: Net income $ 20,392,136 $ 8,550,908 Adjustments to reconcile net income to net cash provided by operating activities - Cumulative effect of change in accounting principle 4,376,852 --- Depreciation, depletion, and amortization 46,630,689 41,789,711 Accretion of asset retirement obligation 623,761 --- Deferred income taxes 13,375,807 4,554,165 Gain on asset disposition --- (7,332,668) Other 658,524 728,917 Change in assets and liabilities - (Increase) decrease in accounts receivable, excluding income taxes receivable (3,895,748) 1,263,553 Increase in accounts payable and accrued liabilities 1,860,038 5,539,810 Decrease in income taxes receivable --- 600,000 --------------------- -------------------- Net Cash Provided by Operating Activities 84,022,059 55,694,396 --------------------- -------------------- Cash Flows From Investing Activities: Additions to property and equipment (101,510,935) (132,521,779) Proceeds from the sale of property and equipment 3,839,714 11,525,547 Net cash distributed as operator of oil and gas properties (989,176) (4,247,012) Net cash received (distributed) as operator of partnerships and joint ventures 471,957 (26,527,633) Other (89,635) 68,388 --------------------- -------------------- Net Cash Used in Investing Activities (98,278,075) (151,702,489) --------------------- -------------------- Cash Flows From Financing Activities: Proceeds from long-term debt --- 200,000,000 Net proceeds from (payments of) bank borrowings 11,900,000 (129,500,000) Net proceeds from issuances of common stock 1,218,224 31,330,384 Payments of debt issuance costs --- (6,257,428) --------------------- -------------------- Net Cash Provided by Financing Activities 13,118,224 95,572,956 --------------------- -------------------- Net Decrease in Cash and Cash Equivalents (1,137,792) (435,137) Cash and Cash Equivalents at Beginning of Period 3,816,107 2,149,086 --------------------- -------------------- Cash and Cash Equivalents at End of Period $ 2,678,315 $ 1,713,949 ===================== ==================== Supplemental disclosures of cash flows information: Cash paid during period for interest, net of amounts capitalized $ 17,825,296 $ 10,511,529 Cash paid during period for income taxes $ 306,121 $ 2,500 Non-cash investing activity: Issuance of common stock in acquisitions $ --- $ 8,116,200
See accompanying notes to consolidated financial statements. 7 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 (1) GENERAL INFORMATION The consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the balance sheet at December 31, 2002, which has been prepared from the audited financial statements at that date. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of our management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in the latest Form 10-K and Annual Report. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Oil and Gas Properties We follow the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and gas reserves are capitalized. Under the full-cost method of accounting, such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred. Our interests in oil and gas properties and partnerships are proportionately consolidated. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization of oil and gas properties by the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties (net of salvage value)-including future development costs, gas processing facilities and capitalized asset retirement obligations, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country-by-country basis. Furniture, fixtures, and other equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized. 8 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 The cost of unproved properties not being amortized is assessed quarterly, on a country-by-country basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense. Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities and capitalized asset retirement obligations, net of related salvage values and deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using hedge adjusted period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Test"). This calculation is done on a country-by-country basis for those countries with proved reserves. The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional non-cash write-downs of oil and gas properties could occur in the future. Accounts Receivable Included in the total "Accounts receivable" balance, which totaled $24.9 million at September 30, 2003 on the accompanying balance sheet, was approximately $2.3 million of receivables related to disputed volumes produced from 2001 and 2002. Due to this dispute, we have not recorded a receivable to date with regard to 2003 volumes. We assess the collectibility of trade and other receivables. Based on our judgment, we would accrue a reserve when we believe a receivable may not be collected. At September 30, 2003 and December 31, 2002, we had an allowance for doubtful accounts of $771,354 and $291,136, respectively. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. 9 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 Earnings Per Share Basic earnings per share ("Basic EPS") have been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share ("Diluted EPS") for all periods also assume, as of the beginning of the period, exercise of stock options using the treasury stock method. The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS (before cumulative effect of change in accounting principle) for the three-month and nine-month periods ended September 30, 2003 and 2002:
Three Months Ended September 30, -------------------------------------------------------------------------------- 2003 2002 -------------------------------------- --------------------------------------- Net Per Share Net Per Share Income Shares Amount Income Shares Amount ------------- ----------- ---------- ------------- ----------- ---------- Basic EPS: Net Income Before Cumulative Effect of Change in Accounting Principle and Share Amounts $ 7,062,625 27,424,195 $ .26 $ 1,947,006 26,889,186 $ .07 Stock Options --- 259,246 --- 242,283 ------------- ----------- ------------- ----------- Diluted EPS: Net Income Before Cumulative Effect of Change in Accounting Principle and Assumed Share Conversions $ 7,062,625 27,683,441 $ .26 $ 1,947,006 27,131,469 $ .07 ------------- ----------- -------------- ----------- Nine Months Ended September 30, -------------------------------------------------------------------------------- 2003 2002 -------------------------------------- --------------------------------------- Net Per Share Net Per Share Income Shares Amount Income Shares Amount ------------- ----------- ---------- ------------- ----------- ----------- Basic EPS: Net Income Before Cumulative Effect of Change in Accounting Principle and Share Amounts $ 24,768,988 27,326,169 $ .91 $ 8,550,908 $26,112,382 $ .33 Stock Options --- 147,158 --- 368,786 -------------- ----------- ------------ ------------ Diluted EPS: Net Income Before Cumulative Effect of Change in Accounting Principle and Assumed Share Conversions $ 24,768,988 27,473,327 $ .90 $ 8,550,908 $26,481,168 $ .32 ------------- ----------- ------------ -----------
Options to purchase approximately 2.9 million shares of common stock, at an average exercise price of $16.61 were outstanding at September 30, 2003. Approximately 1.3 million and 1.6 million options to purchase shares were not included in the computation of Diluted EPS, for the three months and nine months ended September 30, 2003, because the options were antidilutive in that the option price was greater than the average closing market price of the common shares during those periods. 10 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 Other Comprehensive Loss We follow the provisions of SFAS No. 130 "Reporting Comprehensive Income," which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At September 30, 2003, we recorded $178,188, net of taxes of $64,148, of derivative losses in "Other comprehensive loss" on the accompanying balance sheet. The components of accumulated other comprehensive loss and related tax effects for the nine months ended September 30, 2003 were as follows:
Gross Value Tax Effect Net of Tax Value ---------------- --------------- ---------------- Balance at December 31, 2002 $ 278,208 $ 100,155 $ 178,053 Change in fair value of cash flow hedges 1,891,210 680,836 1,210,374 Effect of cash flow hedges settled during the period (1,991,230) (716,843) (1,274,387) ---------------- --------------- ---------------- Balance at September 30, 2003 $ 178,188 $ 64,148 $ 114,040 ================ =============== ================
Total comprehensive income was $7.3 million and $1.8 million for the third quarters of 2003 and 2002. For the nine-month periods ended September 30, 2003 and 2002, total comprehensive income was $20.5 million and $8.4 million, respectively. Stock Based Compensation We account for three stock-based compensation plans under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant. Had compensation expense for these plans been determined based on the fair value of the options using the Black-Scholes option pricing model, and consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," our net income and earnings per share would have been adjusted to the following pro forma amounts:
Three Months Ended September 30, ----------------------------------------------- 2003 2002 --------------------- ------------------- Net Income: As Reported $7,062,625 $1,947,006 Stock-based employee compensation expense determined under fair value method for all awards, net of tax (1,024,734) (1,110,573) --------------------- ------------------- Pro Forma $6,037,891 $836,433 Basic EPS: As Reported $.26 $.07 Pro Forma $.22 $.03 Diluted EPS: As Reported $.26 $.07 Pro Forma $.22 $.03
11 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Nine Months Ended September 30, ------------------------------------------------- 2003 2002 ---------------------- ------------------- Net Income: As Reported $20,392,136 $8,550,908 Stock-based employee compensation expense determined under fair value method fo all awards, net of tax (3,048,052) (3,321,059) ---------------------- ------------------- Pro Forma $17,344,084 $5,229,849 Basic EPS: As Reported $.75 $.33 Pro Forma $.63 $.20 Diluted EPS: As Reported $.74 $.32 Pro Forma $.63 $.20
Pro forma compensation cost reflected above may not be representative of the cost to be expected in future periods. Price-Risk Management Activities We follow SFAS No. 133, which requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or a liability measured at its fair value. Special hedge accounting for qualifying hedges would allow the gains and losses on derivatives to offset related results on the hedged item in the consolidated statements of income and would require that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of protection price floors and collars. During the third quarters of 2003 and 2002, we recognized net losses of $598,766 and $181,595, respectively, relating to our derivative activities. During the first nine months of 2003 and 2002 we recognized net losses of $2,399,435 and $201,474, respectively, relating to our derivative activities. Approximately $5,789 and $162,727 of the losses recognized in the 2003 and 2002 periods, respectively, were unrealized, as the contracts were still open. This activity is recorded in "Price-risk management and other, net" on the accompanying statements of income. At September 30, 2003, we had recorded $178,188 of derivative losses, net of tax effects of $64,148, in "Other comprehensive loss" on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in "Price-risk management and other, net" for the first nine months of 2003 was not material. We expect to reclassify all amounts currently held in "Other comprehensive loss" into the statement of income within the next six months when the forecasted sale of hedged production occurs. As of September 30, 2003, we had in place price floors in effect through the December 2003 contract month for natural gas and through November 2003 for crude oil. The natural gas price floors cover notional volumes of 1,050,000 MMBtu with a weighted average floor price of $4.75 per MMBtu. The crude oil price floors cover notional volumes of 180,000 barrels of oil, with a weighted average floor price of $27.58 per barrel. When we entered into the preceding transactions, with the exception of several November natural gas floors, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of our oil and natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are initially recorded in 12 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 Other Comprehensive Income (Loss). When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are transferred from "Other comprehensive income (loss) and recorded in "Price-risk management and other, net" on the consolidated statement of income. Several of our November contract month natural gas floors became ineffective, as accounted for under special hedge accounting treatment, during the second quarter of 2003. These natural gas floors have been marked to market each period with any gain or loss recorded in "Price-risk management and other, net" on the consolidated statement of income. The fair value of our derivatives are computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. At September 30, 2003, the fair values of the derivative instruments were as follows: gas price floors represented an asset of $322,080 and crude oil price floors represented an asset of $95,899. These instruments are recognized on the balance sheet in "Other current assets." Asset Retirement Obligation In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143 effective January 1, 2003, we recorded an asset retirement obligation of $8.9 million, an addition to oil and gas properties of $2.0 million and a non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which is recorded as a Cumulative Effect of Change in Accounting Principle. The following provides a roll-forward of our asset retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2003 $ 8,934,320 Accretion expense for the nine months ended September 30, 2003 623,761 Additions due to new wells and facilities construction 546,350 Reductions due to sold and abandoned wells (332,327) Increase due to currency exchange rate fluctuations 62,591 ---------------- Asset Retirement Obligation as of September 30, 2003 $ 9,834,695 ----------------
The pro forma effect on the first quarter of 2002, assuming adoption of SFAS No. 143 effective January 1, 2002, would have included a non-cash charge of $3.7 million (net of $2.1 million of deferred taxes), which would have been recorded as a Cumulative Effect of Change in Accounting Principle. The following table displays our pro forma results for the three and nine months ended September 30, 2002, had we adopted SFAS No. 143 effective January 1, 2002. 13 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ------------------- --------------------- Net Income: Actual - as reported $ 1,947,006 $ 8,550,908 Pro Forma $ 1,841,047 $ 4,520,396 Basic EPS: Actual - as reported $ .07 $ .33 Pro Forma $ .07 $ .17 Diluted EPS: Actual - as reported $ .07 $ .32 Pro Forma $ .07 $ .17 New Accounting Principles In January 2003, the FASB issued Interpretation No. 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (the "Interpretation"). The Interpretation will significantly change whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model - the variable interest model - which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. These provisions apply immediately to variable interests in VI's created after January 15, 2003 and are effective for periods ending after December 15, 2003 for VIE's in which the Company holds a variable interest that it acquired prior to February 1, 2003. The Company is still evaluating the impact of this new interpretation. In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement sets standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity. This statement is effective for periods ending after December 15, 2003. The Company is still evaluating the impact of this new interpretation. The Securities and Exchange Commission ("SEC") commented that acquired oil and gas drilling rights should be classified as an intangible asset pursuant to FASB No. 142 "Goodwill and Other Intangible Assets." The SEC has not required companies to apply this classification and we classify the costs of oil and gas drilling rights as property and equipment. The Emerging Issues Task Force, a subset of FASB, will address this issue at a later date. If the SEC's comment on this issue is adopted in the future, we may be required to reclassify these costs from property and equipment to intangible assets on our balance sheet. 14 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 (3) LONG-TERM DEBT Our long-term debt as of September 30, 2003 and December 31, 2002, is as follows: September 30, December 31, 2003 2002 ------------------ ------------------- Bank Borrowings $ 11,900,000 $ --- Senior Notes due 2009 124,333,381 124,271,973 Senior Notes due 2012 200,000,000 200,000,000 ------------------ ------------------- Long-Term Debt $ 336,233,381 $ 324,271,973 ------------------ ------------------- The unamortized discount on the Senior Notes due 2009 was $666,619 and $728,027 at September 30, 2003 and December 31, 2002, respectively. Bank Borrowings Under our $300.0 million credit facility with a syndicate of ten banks, at September 30, 2003 we had $11.9 million in outstanding borrowings and no outstanding borrowings at year-end 2002. At September 30, 2003, the credit facility consisted of a $300.0 million secured revolving line of credit with a $150.0 million commitment amount. The interest rate is either (a) the lead bank's prime rate (4% at September 30, 2003) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. Of the $11.9 million borrowed at September 30, 2003, $5.0 million was borrowed at the LIBOR rate plus applicable margin, which was 2.37%. Our credit facility extends until October 1, 2005. The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $5.0 million in any fiscal year), a remaining aggregate limitation on purchases of Company stock of $15.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt or repurchasing our existing Senior Notes. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and gas properties. We have also pledged 65% of the stock in our two active New Zealand subsidiaries as collateral for this credit facility. The borrowing base is re-determined at least every six months and was recently reconfirmed by our bank group and increased to $250.0 million effective November 1, 2003, an increase of $55.0 million from the previous level of $195.0 million. We previously requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The next borrowing base review is scheduled for May 2004. 15 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 Senior Notes Due 2009 At September 30, 2003, our Senior Notes due 2009 consisted of $125.0 million of 10.25% Senior Subordinated Notes due 2009. These Senior Notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on these Senior Notes is payable semiannually on February 1 and August 1. On or after August 1, 2004, these notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. Upon certain changes in control of Swift, each holder of these notes will have the right to require Swift to repurchase the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these Senior Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing the these notes. Senior Notes Due 2012 At September 30, 2003, our Senior Notes due 2012 consisted of $200.0 million of 9.375% Senior Subordinated Notes due 2012. These Senior Notes were issued at 100% of the principal amount on April 11, 2002, and will mature on May 1, 2012. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on these Senior Notes is payable semiannually on May 1 and November 1. On or after May 1, 2007, these notes are redeemable for cash at the option of Swift, with certain restrictions, at 104.688% of principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of the Senior Notes with the proceeds of qualified offerings of our equity at 109.375% of the principal amount of these notes, together with accrued and unpaid interest. Upon certain changes in control of Swift, each holder of Senior Notes will have the right to require Swift to repurchase the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of our these Senior Notes include, among other restrictions, a limit on repurchases by Swift of its common stock. We are currently in compliance with the provisions of the indenture governing these notes. (4) STOCKHOLDERS' EQUITY In March 2002, we issued 220,000 shares of our common stock, along with cash consideration as an effective date adjustment, to acquire all of the New Zealand assets of Antrim Oil and Gas Limited ("Antrim"). At the time, these 220,000 shares, with a fair market value of $4.2 million, were issued out of treasury shares, and resulted in an increase to paid-in capital of $1.0 million and a decrease in the value of our treasury shares of $3.2 million. In April 2002, we issued 1,725,000 shares of common stock in a public offering, at a price of $18.25 per share. Gross proceeds from this offering were $31,481,250, with issuance costs of $998,191. In September 2002, we issued 300,000 shares of our common stock with a fair market value of $3.9 million, along with $2.7 million in cash, to acquire the interests owned by Bligh Oil and Minerals N.L. ("Bligh") in the Swift operated Rimu/Kauri and TAWN permits, mining licenses and facilities in New Zealand. (5) FOREIGN ACTIVITIES As of September 30, 2003, our gross capitalized oil and gas property costs in New Zealand totaled approximately $200.1 million. Approximately $166.0 million has been included in the proved properties portion of our oil and gas properties, while $34.1 million is included as unproved properties. Our functional currency in New Zealand is the U.S. dollar. 16 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 (6) SEGMENT INFORMATION Below is a summary of financial information by country:
Three Months Ended September 30, ---------------------------------------------------------------------------------------------- 2003 2002 -------------------------------------------- --------------------------------------------- New New Domestic Zealand Total Domestic Zealand Total ------------- -------------- ------------- ------------- ------------- ------------- Oil and gas sales $ 39,974,435 $ 12,112,886 $ 52,087,321 $ 28,454,804 $ 8,137,525 $ 36,592,329 Costs and Expenses: Depreciation, depletion and amortization 11,645,480 4,396,897 16,042,377 10,196,179 3,291,258 13,487,437 Accretion of asset retirement obligation 151,188 55,287 206,475 --- --- --- Oil and gas production 10,260,211 3,470,256 13,730,467 8,444,530 2,560,111 11,004,641 ------------- -------------- ------------- ------------- ------------- ------------ Income from oil and gas operations $ 17,917,556 $ 4,190,446 $ 22,108,002 $ 9,814,095 $ 2,286,156 $ 12,100,251 Other revenues (1) (534,799) (21,520) General and administrative, net 3,670,416 2,497,413 Interest expense, net 6,749,419 6,647,968 Income before income taxes and Cumulative Effect of Change in Accounting Principle $ 11,153,368 $ 2,933,350 ============= ============= Nine Months Ended September 30, --------------------------------------------------------------------------------------------- 2003 2002 -------------------------------------------- -------------------------------------------- New New Domestic Zealand Total Domestic Zealand Total ------------- -------------- ------------- ------------- ------------- ------------- Oil and gas sales $ 123,693,311 $ 34,153,559 $ 157,846,870 $ 82,202,092 $ 19,334,420 $ 101,536,512 Costs and Expenses: Depreciation, depletion and amortization 32,508,198 14,122,491 46,630,689 34,210,133 7,579,578 41,789,711 Accretion of asset retirement obligation 448,711 175,050 623,761 --- --- --- Oil and gas production 29,532,116 9,860,415 39,392,531 25,141,686 5,460,807 30,602,493 ------------- -------------- ------------- ------------- ------------- ------------- Income from oil and gas operations $ 61,204,286 $ 9,995,603 $ 71,199,889 $ 22,850,273 $ 6,294,035 $ 29,144,308 Other revenues (1) (2,076,826) 7,958,643 General and administrative, net 10,564,959 7,368,989 Interest expense, net 20,107,188 16,607,651 Income before income taxes and Cumulative Effect of Change in Accounting Principle $ 38,450,916 $ 13,126,311 ============= ============= Property, Plant and Equipment, net $ 616,251,046 $ 173,419,123 $ 789,670,169 $ 551,583,952 $ 158,976,243 $ 710,560,195 ============= ============== ============= ============= ============= =============
(1) Other revenues consist of Fees from limited partnerships and joint ventures, Interest income, Gain on asset disposition and Price-risk management and other, net on the accompanying consolidated statements of income. 17 SWIFT ENERGY COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002 (7) ACQUISITIONS AND DISPOSITIONS New Zealand. Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in January 2002 for approximately $51.4 million in cash. We allocated $36.1 million of the acquisition price to "Proved properties," $10.0 million to "Unproved properties," $4.9 million to "Deferred income taxes" and $0.4 million to "Other current assets" on our Consolidated Balance Sheet. Southern NZ was an affiliate of Shell New Zealand and owns interests in four onshore producing oil and gas fields, hydrocarbon processing facilities, and pipelines connecting the fields and facilities to export terminals and markets. This acquisition was accounted for by the purchase method of accounting. In March 2002, we purchased through our subsidiary, SENZ, all of the New Zealand assets owned by Antrim for 220,000 shares of Swift Energy Company common stock valued at $4.2 million with an effective date adjustment of approximately $0.5 million for total consideration of $4.7 million. In September 2002, we purchased through our subsidiary, SENZ, Bligh's 5% working interest in permit 38719 and 5% interest in the Rimu petroleum mining permit 38151, along with its 3.24% working interest in the four TAWN petroleum mining licenses, for 300,000 shares of Swift Energy Company common stock valued at $3.9 million, along with $2.7 million in cash for total consideration of $6.6 million. Russia. In 1993, we entered into a Participation Agreement with Senega, a Russian Federation joint stock company, to assist in the development and production of reserves from two fields in western Siberia and received a 5% net profits interest. We also purchased a 1% net profits interest. Our investment in Russia was fully impaired in the third quarter of 1998. In March 2002, we received $7.5 million for our investment in Russia. Although the proceeds from sales of oil and gas properties are generally treated as a reduction of oil and gas property costs, because we had previously charged to expense all $10.8 million of cumulative costs relating to our Russian activities, this cash payment, net of transaction expenses, resulted in recognition of a $7.3 million non-recurring gain on asset disposition in the first quarter of 2002. 18 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL Over the last several years, we have emphasized adding reserves through drilling activity, while adding reserves through strategic purchases of producing properties when oil and gas prices were at lower levels and other market conditions were appropriate. We used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production during such period. CONTRACTUAL COMMITMENTS AND OBLIGATIONS Our contractual commitments for the remainder of 2003 and the next four years and thereafter as of September 30, 2003 are as follows:
2003 2004 2005 2006 2007 Thereafter Total ---- ---- ---- ---- ---- ---------- ----- Non-cancelable operating lease commitments $ 547,591 $ 2,191,495 $ 523,755 $ 190,676 $ 190,676 $ 186,834 $ 3,831,027 Capital commitments due to pipeline operators 400,426 -- -- -- -- -- 400,426 Asset Retirement Obligation (1) 1,068,558 651,679 -- 3,441,209 300,079 4,373,170 9,834,695 Drilling Rig Commitments 2,535,000 -- -- -- -- -- 2,535,000 Senior Notes due 2009 (2) -- -- -- -- -- 125,000,000 125,000,000 Senior Notes due 2012 (2) -- -- -- -- -- 200,000,000 200,000,000 Credit Facility which expires in October 2005 (3) -- -- 11,900,000 -- -- -- 11,900,000 ----------- ------------ ------------- ----------- ---------- ------------- ------------- $ 4,551,575 $ 2,843,174 $ 12,423,755 $ 3,631,885 $ 490,755 $ 329,560,004 $ 353,501,148 =========== ============ ============= =========== ========== ============= =============
(1)Amounts shown by year are the net present value, discounted to September 30, 2003. (2)These amounts do not include the interest obligation, which is paid semiannually. (3)These amounts exclude a $0.8 million standby letter of credit outstanding under this facility. COMMODITY PRICE TRENDS AND UNCERTAINTIES Oiland natural gas prices historically have been volatile and are expected to continue to be volatile in the future. Worldwide supply disruptions, such as the reduction in crude oil production from Venezuela, together with perceived risks associated with the war between the United States and Iraq, along with other factors, have caused the price of oil to increase significantly in the first nine months of 2003 when compared to historical prices. Other factors such as actions taken by OPEC, worldwide economic conditions, and weather conditions can cause wide fluctuations in the price of oil. Natural gas prices increased significantly in the first quarter of 2003 when compared to historical prices, and have since declined somewhat. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, and the availability and accessibility of natural gas deposits in North America can cause wide fluctuations in the price of natural gas. All of such factors are beyond our control. 19 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED LIQUIDITY AND CAPITAL RESOURCES During the first nine months of 2003, we largely relied upon our net cash provided by operating activities of $84.0 million and proceeds from bank borrowings of $11.9 million to fund capital expenditures of $101.5 million. During the first nine months of 2002, we principally relied upon our net cash provided by operating activities of $55.7 million, net proceeds from the public issuance of long-term debt of $195.0 million and net proceeds of our public stock offering of $30.5 million, less the repayment of bank borrowings of $129.5 million, to fund capital expenditures of $132.5 million. Net Cash Provided by Operating Activities. For the first nine months of 2003, net cash provided by our operating activities was $84.0 million, representing a 51% increase as compared to $55.7 million generated during the first nine months of 2002. The $28.3 million increase was primarily due to an increase of $56.3 million in oil and gas sales for the first nine months of 2003, attributable to higher commodity prices and production, offset in part by production cost increases due to significant Lake Washington facility enhancements and workovers, along with scheduled plant shutdowns for maintenance in New Zealand and an increase in interest expense attributed to the replacement of our bank borrowings in April 2002 with the Senior Notes due 2012 that carry a higher interest rate and a longer term. Accounts Receivable. In early 2003, a dispute arose with a third party regarding the level of volumes we produced and delivered through a gathering system covered by a production handling agreement. Outside audits were conducted related to these volumes produced and delivered to such third party during 2001, 2002 and a portion of 2003. As a result of these audits, we have made claim for payment of additional volumes produced during those periods. Included in the accompanying consolidated balance sheet is approximately $2.3 million of receivables related to these disputed volumes produced in 2001 and 2002. Due to this dispute, we have not recorded a receivable to date with regard to 2003 volumes. We believe that we will prevail in this dispute and currently anticipate mediation, arbitration or legal action to resolve this claim. Existing Credit Facility. We had $11.9 million in outstanding borrowings under our credit facility at September 30, 2003, and no outstanding borrowings at December 31, 2002. At September 30, 2003, our credit facility consisted of a $300.0 million revolving line of credit with a $150.0 million commitment amount. The borrowing base is re-determined at least every six months and was recently reconfirmed by our bank group and increased to $250.0 million, effective November 1, 2003, an increase of $55.0 million from the previous level of $195.0 million. We previously requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion. Our revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. We are in compliance with the provisions of this agreement. Debt Maturities. Our credit facility extends until October 1, 2005. Our $125.0 million Senior Notes mature August 1, 2009 and our $200.0 million Senior Notes mature May 1, 2012. Working Capital. Our working capital decreased from a deficit of $17.1 million at December 31, 2002, to a deficit of $25.5 million at September 30, 2003. The decrease was primarily due to an increase in accrued liabilities due to our drilling activities in the first nine months of 2003. Capital Expenditures. During the first nine months of 2003, we used $101.5 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included: Domestic activities of $77.3 million as follows: o $53.6 million for drilling costs, both development and exploratory; 20 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED o $14.2 million for the construction of production and surface facilities, mainly in our Lake Washington area. o $7.6 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects; o $1.5 million of producing property acquisitions; and o $0.4 million primarily for computer equipment, software, furniture, and fixtures. New Zealand activities of $24.2 million as follows: o $14.7 million for drilling costs, both development and exploratory; o $4.8 million on prospect costs, principally seismic and geological costs; o $4.2 million for the construction of production facilities and pipelines; o $0.3 million for property acquisitions; and o $0.2 million for fixed assets. We have spent considerable time and capital in 2003 on significant facility capacity upgrades in the Lake Washington field to increase facility capacity to more than 20,000 barrels per day ('b/d') for crude oil up from 9,000 b/d capacity in the first quarter 2003. Facility upgrades, most of which have been recently completed, and the commissioning of these upgrades, have led to numerous planned production shut-in periods during the third and fourth quarters of 2003. We have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility. We drilled or participated in drilling 48 domestic development wells and seven domestic exploratory wells in the first nine months of 2003, 42 of the development wells and five exploratory wells were in the Lake Washington area. Five domestic exploratory wells and 40 of the domestic development wells were completed. In New Zealand, the Kauri-E1, Kauri-E2 and Kauri-F1 were completed, while the Kauri-A4 began producing into the Rimu Production Station (RPS). The re-entry of the Tuihu exploration well was plugged and abandoned in October 2003. For the remaining three months of 2003, we expect to make capital expenditures of approximately $48 to $55 million (depending on the level and costs of actual drilling activities and on commodity prices). We anticipate that our fourth quarter 2003's internally generated cash flows together with our available bank borrowings, will be sufficient to finance our remaining 2003 capital expenditures. We currently estimate total capital expenditures for 2003 to be approximately $150 to $157 million. Capital expenditures for 2002 were $155.2 million. During the last three months of 2003, we anticipate drilling or participating in the drilling of up to an additional 23 domestic wells, with an emphasis in the Lake Washington area while undertaking activity in our Brookeland, Masters Creek and South Texas areas again. Our capital projects also include facility upgrades and planning for our 3-D seismic work in Lake Washington. In addition, we plan on drilling an additional well in New Zealand. Our 2003 capital expenditures continue to be focused on developing and producing long-lived oil reserves in Lake Washington and in the Rimu/Kauri area in New Zealand. With this focus, we expect our 2003 total 21 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED production to increase by 7% to 9% over 2002 levels primarily from the Lake Washington and TAWN areas, while we expect production in our other core areas to decrease as limited new drilling is currently budgeted to offset the natural production decline of these properties. This drilling focus should help add long-lived oil reserves and should help develop an overall lesser production decline curve, which would extend our average reserve life and emphasize the balancing of our reserves between oil and gas. We currently anticipate that our capital expenditures for 2004 will range between $150 and $170 million. Depending on a number of factors, such as commodity pricing, production levels, and the level and success of planned non-core property dispositions, our internally generated cash flows are expected to fund a majority of these expenditures. Although current plans do not call for extensive use of our bank credit facility in 2004, we believe that our recently increased bank borrowing base will continue to stay at or near its current level, as our proved reserve base continues to grow. If oil and gas prices were to drop precipitously on a sustained basis, it would negatively affect our liquidity and cash flows, including our ability to stay in compliance with certain financial covenants under our credit facility. We would reduce the level of our capital expenditures in response to any such precipitous drop in prices, as we would deem necessary. RESULTS OF OPERATIONS - Three Months Ended September 30, 2003 and 2002 Revenues. Our revenues in the third quarter of 2003 increased by 41% to $51.6 million compared to revenues of $36.6 million in the same period in 2002, primarily due to increases in oil and gas prices and our increased production. Oil and gas sales revenues of $52.1 million in the third quarter of 2003 increased by 42%, or $15.5 million, from the level of those revenues for the comparable 2002 period. Our net sales volumes of 13.6 Bcfe in the third quarter of 2003 increased by 12%, or 1.4 Bcfe, over net sales volumes in the comparable 2002 period. Average prices received for oil increased to $29.24 per Bbl in the third quarter of 2003 from $26.17 per Bbl in the comparable 2002 period. Average gas prices received increased to $3.17 per Mcf in the third quarter of 2003 from $2.32 per Mcf in the 2002 period. Average natural gas liquids (Ngl) prices increased to $16.81 per Bbl in the third quarter of 2003 from $13.58 per Bbl in the comparable 2002 period. The increase in production during the 2003 period was predominantly from our Lake Washington and New Zealand areas. In the third quarter of 2003, our $15.5 million increase in oil and gas sales resulted from: o Price variances that had a $9.8 million favorable impact on sales, of which $5.7 million was attributable to the 37% increase in average gas prices received and $4.1 million was attributable to the 15% increase in the average combined oil and Ngl prices received; and o Volume variances that had a $5.7 million favorable impact on sales, with $5.9 million of the increase coming from the 256,000 Bbl increase in oil and Ngl sales volumes, offset by a $0.2 million decrease coming from the 0.1 Bcf decrease in gas sales volumes. 22 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our domestic core areas and New Zealand:
Three Months Ended September 30, -------------------------------- Area Revenues (In Millions) Net Sales Volumes (Bcfe) ---- --------------------------------------- ---------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- AWP Olmos $ 10.5 $ 7.9 2.3 2.8 Brookeland 3.9 3.2 1.0 0.8 Lake Washington 16.6 5.2 3.5 1.2 Masters Creek 5.6 8.1 1.3 2.1 Other 3.4 4.1 0.6 1.2 --------------------- --------------- --------------- ---------------- Total Domestic $ 40.0 $28.5 8.7 8.1 --------------------- --------------- --------------- ---------------- Rimu/Kauri 3.5 1.4 1.0 0.7 TAWN 8.6 6.7 3.9 3.4 --------------------- --------------- --------------- ---------------- Total New Zealand $ 12.1 $ 8.1 4.9 4.1 --------------------- --------------- --------------- ---------------- Total $ 52.1 $36.6 13.6 12.2 ===================== =============== =============== ================
Our drilling efforts in the third quarter of 2003 have focused on Lake Washington, South Texas and New Zealand. The following table provides additional information regarding our oil and gas sales:
Net Sales Volume Average Sales Price ---------------- ------------------- Oil Ngl Gas Combined Oil Ngl Gas (MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf) 2002 ---- Three Months Ended September 30: Domestic 517 169 4.0 8.1 $26.95 $14.42 $3.06 New Zealand 166 56 2.8 4.1 $23.76 $11.03 $1.28 ------- ------- -------- --------- Total 683 225 6.8 12.2 $26.17 $13.58 $2.32 ======= ======= ======== ========= 2003 ---- Three Months Ended September 30: Domestic 757 179 3.2 8.7 $29.33 $17.96 $4.63 New Zealand 160 68 3.5 4.9 $28.83 $13.76 $1.87 ------- ------- -------- --------- Total 917 247 6.7 13.6 $29.24 $16.81 $3.17 ======= ======= ======== =========
During the third quarter of 2003, we recognized net losses of $0.6 million relating to our hedging activities, as compared to net losses of $0.2 million in the 2002 period. This activity is recorded in "Price-risk management and other, net" on the accompanying consolidated statement of income. Revenues from our oil and gas sales comprised substantially all of net revenues for the third quarters of 2003 and 2002. Natural gas production made up 49% of our production volumes in the third quarter of 2003 and 55% in the 2002 period. Costs and Expenses. Our expenses in the third quarter of 2003 increased $6.8 million, or 20%, compared to the 2002 period expenses. The majority of this increase was due to our increased depletion expense and oil 23 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED and gas production costs, both domestically and in New Zealand. Our net general and administrative expense in the third quarter of 2003, increased $1.2 million, or 47%, from the level of such expenses in the comparable 2002 period. These increases reflect additional costs needed to run our increased activities in New Zealand, an increase in franchise tax expense, and increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe produced increased to $0.27 per Mcfe in the third quarter of 2003 from $0.20 per Mcfe in the comparable 2002 period. The portion of supervision fees netted from general and administrative expenses was $0.8 million for the both the third quarters of 2003 and 2002. Depreciation, depletion, and amortization of our assets, or DD&A, increased $2.6 million, or 19%, in the third quarter of 2003 from the 2002 period. Domestically, DD&A increased $1.4 million due to increased production in the 2003 period, offset somewhat by higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, our production increased in the 2003 period in both the Rimu/Kauri and TAWN areas, which increased DD&A in the third quarter 2003. Our DD&A rate per Mcfe of production was $1.18 in the third quarter of 2003 and $1.10 in the comparable 2002 period, reflecting these variations in per unit cost of reserves additions. We recorded $0.2 million of accretion on our asset retirement obligation in the third quarter of 2003 associated with the adoption of SFAS No. 143 implemented effective January 1, 2003. Our production costs increased $2.7 million in the third quarter of 2003, or 25%, and were $1.01 and $0.90 per Mcfe in the third quarter of 2003 and 2002, respectively. Due to the 18% increase in production during the third quarter of 2003, our New Zealand operations contributed $0.9 million of the cost increase in the period. Domestic severance taxes increased $1.3 million in the third quarter of 2003, due to higher commodity prices and production. The portion of supervision fees netted from production costs was $0.5 million for the third quarters of 2003 and 2002. Interest expense on our Senior Notes due 2009, including amortization of debt issuance costs, totaled $3.3 million in both the third quarter of 2003 and 2002. Interest expense on our Senior Notes due 2012, including amortization of debt issuance costs, totaled $4.8 million in the third quarter of 2003 and $4.7 million in the third quarter of 2002. Interest expense on our credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.3 million in the third quarter of 2003 and $0.4 million in the same period in 2002. The total interest cost in the third quarter of 2003 was $8.4 million, of which $1.7 million was capitalized. The total interest cost in the third quarter of 2002 was $8.4 million, of which $1.8 million was capitalized. We capitalize that portion of interest related to our unproved properties. Net Income. Our net income in the third quarter of 2003 of $7.1 million was 263% higher and Basic EPS of $0.26 were 256% higher than our third quarter of 2002 net income of $1.9 million and Basic EPS of $0.07. Our Diluted EPS in the third quarter of 2003 of $0.26 were also 256% higher than our third quarter of 2002 Diluted EPS of $0.07. These amounts increased in the 2003 period as oil and gas sales increased due to higher commodity prices and our increased production. RESULTS OF OPERATIONS - Nine Months Ended September 30, 2003 and 2002 Revenues. Our revenues in the first nine months of 2003 increased by 42% to $155.8 million compared to revenues of $109.5 million in the same period in 2002, primarily due to increases in oil and gas prices and, to a lesser extent, our increased production. Oil and gas sales revenues of $157.8 million in the first nine months of 2003 increased by 55%, or $56.3 million, from the level of those revenues for the comparable 2002 period. Our net sales volumes of 39.8 Bcfe in the first nine months of 2003 increased by 7%, or 2.6 Bcfe, over net sales volumes in the comparable 2002 period. Average prices received for oil increased to $29.80 per Bbl in the first nine months of 2003 from $26.50 per Bbl in the comparable 2002 24 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED period. Average gas prices received increased to $3.46 per Mcf in the first nine months of 2003 from $2.21 per Mcf in the 2002 period. Average natural gas liquids (Ngl) prices increased to $17.87 per Bbl in the first nine months of 2003 from $11.77 per Bbl in the comparable 2002 period. The increase in production during the 2003 period was from our Lake Washington and New Zealand areas. Our domestic Ngl volumes decreased in the first nine months of 2003, as it was more profitable to sell high Btu natural gas than to strip out ethane and other Ngls from the gas stream. In the first nine months of 2003, our $56.3 million increase in oil and gas sales resulted from: o Price variances that had a $49.2 million favorable impact on sales, of which $26.8 million was attributable to the 56% increase in average gas prices received and $22.4 million was attributable to the 37% increase in the average combined oil and Ngl prices received; and o Volume variances that had a $7.1 million favorable impact on sales, with $4.1 million of the increase coming from the 206,000 Bbl increase in oil and Ngl sales volumes, and $3.0 million of the increase coming from the 1.4 Bcf increase in gas sales volumes. The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our domestic core areas and New Zealand:
Nine Months Ended September 30, ------------------------------- Area Revenues (In Millions) Net Sales Volumes (Bcfe) ---- -------------------------------------- ----------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- AWP Olmos $34.6 $ 24.1 6.4 8.4 Brookeland 12.3 9.2 2.9 3.1 Lake Washington 40.4 12.1 8.3 3.1 Masters Creek 21.3 25.5 4.6 8.0 Other 15.0 11.3 2.8 4.0 -------------------- -------------- ---------------- ---------------- Total Domestic $ 123.6 $ 82.2 25.0 26.6 -------------------- -------------- ---------------- ---------------- Rimu/Kauri 6.8 2.5 2.0 1.0 TAWN 27.4 16.8 12.8 9.6 -------------------- -------------- ---------------- ---------------- Total New Zealand $ 34.2 $ 19.3 14.8 10.6 -------------------- -------------- ---------------- ---------------- Total $ 157.8 $101.5 39.8 37.2 ==================== ============== ================ ================
Our drilling efforts in the first nine months of 2003 have focused on Lake Washington, AWP Olmos and New Zealand. During 2003, our TAWN natural gas production in New Zealand was materially higher than original expectations due to increased natural gas demand in New Zealand and facility modifications implemented by our New Zealand operations. As a result of this increased production, which we believe peaked during the third quarter of 2003, the depletion of our TAWN property during the first nine months of 2003 was at a higher rate than was seen during the comparable 2002 period, and we expect a higher rate of depletion to continue. We also expect to conduct future drilling operations to add new supply volumes and install compression to improve deliverability and recovery of natural gas in the TAWN area. 25 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED The following table provides additional information regarding our oil and gas sales:
Net Sales Volume Average Sales Price ---------------- ------------------- Oil Ngl Gas Combined Oil Ngl Gas (MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf) 2002 ---- Nine Months Ended September 30: Domestic 1,257 1,110 12.4 26.6 $27.38 $11.91 $2.78 New Zealand 342 145 7.6 10.6 $23.28 $10.76 $1.29 ----------- ---------- ---------- ------------ Total 1,599 1,255 20.0 37.2 $26.50 $11.77 $2.21 =========== ========== ========== ============ 2003 ---- Nine Months Ended September 30: Domestic 2,010 419 10.4 25.0 $29.96 $20.18 $5.30 New Zealand 418 213 11.0 14.8 $29.03 $13.33 $1.74 ----------- ---------- ---------- ------------ Total 2,428 632 21.4 39.8 $29.80 $17.87 $3.46 =========== ========== ========== ============
In March 2002, we received $7.5 million for our interest in the Samburg project located in western Siberia, Russia as a result of the sale by a third party of its ownership in a Russia joint stock company that owned and operated the field. Although the proceeds from sales of oil and gas properties are generally treated as a reduction of oil and gas property costs, because we had previously charged to expense all $10.8 million of cumulative costs relating to our Russian activities, this cash payment, net of transaction expenses, resulted in recognition of a $7.3 million non-recurring gain on asset disposition in the first quarter of 2002. This activity was recorded in "Gain on asset disposition" in the accompanying consolidated statement of income. During the first nine months of 2003, we recognized net losses of $2.4 million relating to our hedging activities, as compared to net losses of $0.2 million in the same 2002 period. This activity is recorded in "Price-risk management and other, net" on the accompanying consolidated statement of income. Revenues from our oil and gas sales comprised substantially all of net revenues for the first nine months of 2003 and 93% of total revenues for the comparable 2002 period. Natural gas production made up 54% of our production volumes in the first nine months of both 2003 and 2002. Costs and Expenses. Our expenses in the first nine months of 2003 increased $21.0 million, or 22%, compared to the same 2002 period expenses. The majority of the increase was due to our increased oil and gas production costs, both domestically and in New Zealand, an increase in depletion expense, both domestically and in New Zealand, and an increase in interest expense due to replacement of our bank borrowings with our Senior Notes due 2012. Our net general and administrative expense in the first nine months of 2003 increased $3.2 million, or 43%, from the level of such expenses in the comparable 2002 period. These increases reflect additional costs needed for our increased activities in New Zealand, a reduction in reimbursement from partnerships we managed as almost all of these partnerships have liquidated, an increase in franchise tax expense, and increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe produced increased to $0.27 per Mcfe in the first nine months of 2003 from $0.20 per Mcfe in the same 2002 period. The portion of supervision fees netted from general and administrative expenses was $2.2 million for the first nine months of 2003 and $2.3 million for the same 2002 period. 26 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED Depreciation, depletion, and amortization of our assets, or DD&A, increased $4.8 million, or 12%, in the first nine months of 2003 from the same 2002 period. Domestically, DD&A decreased $1.7 million due to decreased production in the same 2003 period, and higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, our production increased in the first nine months of 2003 in both the Rimu/Kauri and TAWN areas, which increased DD&A in this period. Our DD&A rate per Mcfe of production was $1.17 in the first nine months of 2003 and $1.12 in the same 2002 period, reflecting these variations in per unit cost of reserves additions. We recorded $0.6 million of accretion on our asset retirement obligation in the first nine months of 2003 associated with the adoption of SFAS No. 143 implemented on January 1, 2003. Our production costs increased $8.8 million in the first nine months of 2003, or 29%, and were $0.99 and $0.82 per Mcfe in the first nine months of 2003 and 2002, respectively. Due to the 41% increase in production during the first nine months of 2003, our New Zealand operations contributed $4.4 million of the cost increase in the period. Domestic severance taxes increased $4.4 million in the first nine months of 2003, due to higher commodity prices. The portion of supervision fees netted from production costs was $1.5 million for the first nine months of both 2003 and 2002. Interest expense on our Senior Notes due 2009, including amortization of debt issuance costs, totaled $9.9 million in both the first nine months of 2003 and 2002. Interest expense on our Senior Notes due 2012, including amortization of debt issuance costs, totaled $14.3 million and $8.7 million in the first nine months of 2003 and 2002, respectively. Interest expense on our credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.1 million in the first nine months of 2003 and $3.3 million in the same period in 2002. The total interest cost in the first nine months of 2003 was $25.3 million, of which $5.2 million was capitalized. The total interest cost in the first nine months of 2002 was $21.9 million, of which $5.3 million was capitalized. We capitalize that portion of interest related to our unproved properties. The increase in interest expense in the first nine months of 2003 was attributed to the replacement of our bank borrowings in April 2002 with the Senior Notes due 2012 that carry a higher interest rate and a longer term. As discussed in Note 1 to the Consolidated Financial Statements, we implemented SFAS No. 143 effective January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which is recorded as a "Cumulative Effect of Change in Accounting Principle" in the consolidated statement of income. This statement requires that the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets be recorded in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the obligation is either settled for its recorded amount or a gain or loss is incurred upon settlement. This statement requires that a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values be recorded. Net Income. Our net income in the first nine months of 2003 of $20.4 million was 138% higher and Basic EPS of $0.75 were 131% higher than our first nine months of 2002 net income of $8.6 million and Basic EPS of $0.33. Our Diluted EPS in the first nine months of 2003 of $0.74 were also 131% higher than our first nine months of 2002 Diluted EPS of $0.32. These amounts increased in the same 2003 period as oil and gas sales increased due to higher commodity prices and our increased production. Related-Party Transactions We are currently the operator of a limited number of properties owned by the six remaining affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships were approximately $0.1 million in the first nine months of 2003 and $0.3 million in the 2002 27 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED period, and are recorded as reductions of general and administrative expense and oil and gas production expense. We also have been reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $0.4 million and $0.9 million in the first nine months of 2003 and 2002, respectively. These lower amounts reflect our continued transition away from partnerships. 28 SWIFT ENERGY COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED Forward Looking Statements The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as "plan," "future," "estimate," "expect," "budget," "predict," "anticipate," "projected," "should," "believe" or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and therefore, actual results may differ materially. Among the factors that could cause actual results to differ materially are: volatility in oil and gas prices; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed herein, and set forth from time to time in our other public reports, filings and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year. 29 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS Commodity Risk Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility are discussed in Management's Discussion and Analysis, and such volatility is expected to continue. Our price-risk program permits the utilization of derivative instruments (such as futures, forward and options contracts, and swaps) to mitigate price risk associated with fluctuations in oil and natural gas prices. Below is a description of the derivative instruments we have utilized to hedge our exposure to price risk. o Price Floors - At September 30, 2003, we had price floors in place effective through the contract month of December 2003 for natural gas and through November 2003 for crude oil. The natural gas price floors cover notional volumes of 1,050,000 MMBtu, with a weighted average floor price of $4.75 per MMBtu. The crude oil price floors cover notional volumes of 180,000 barrels of oil, with a weighted average floor price of $27.58 per barrel. Our hedges in place at September 30, 2003 should cover approximately 25% to 30% of our forecasted fourth quarter 2003 gas production and 15% to 20% of our forecasted fourth quarter 2003 oil production. o New Zealand Gas Contracts - A majority of our gas production in New Zealand is sold under long-term, fixed-price contracts denominated in New Zealand dollars. These contracts protect against price volatility, and our revenue from these contracts will vary only due to fluctuations in volumes delivered and foreign exchange rates. Customer Credit Risk We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and seek to minimize exposure to any one customer where other customers are readily available. Due to availability of other purchasers, we do not believe that the loss of any single oil or gas customer would have a material adverse effect on our results of operations. Foreign Currency Risk We are exposed to the risk of fluctuations in foreign currencies, most notably the New Zealand Kiwi. Fluctuations in rates between the New Zealand Kiwi and U.S. Dollar may impact our financial results from our New Zealand subsidiaries since we have receivables and liabilities denominated in New Zealand Kiwi. Interest Rate Risk Our Senior Notes have a fixed interest rate, so consequently we are not exposed to cash flow risk from market interest rate changes on our Senior Notes. However, there is a risk that market rates will decline and the required interest payments on our Senior Notes may exceed those payments based on the current market rate. At September 30, 2003, we had $11.9 million in borrowings under our credit facility, which is subject to floating rates and therefore susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank's base rate would constitute 40 basis points and would not have a material adverse effect on our 2003 cash flows based on this same level of borrowing. 30 CONTROLS AND PROCEDURES The Company's chief executive officer and chief financial officer have evaluated the Company's disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act") as of the end of the period covered by this report. Based on that evaluation, they have concluded that such disclosure controls and procedures are effective, in all material respects, in communicating to them on a timely basis material information relating to the Company required under the Exchange Act to be disclosed in this quarterly report. There were no significant changes in the Company's internal control over financial reporting that occurred during the Company's last fiscal quarter that have materially affected, or are reasonably likely to materially affect, such control. 31 SWIFT ENERGY COMPANY PART II. - OTHER INFORMATION Item 1. Legal Proceedings No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company's business. Item 2. Changes in Securities and Use of Proceeds - N/A Item 3. Defaults Upon Senior Securities - N/A Item 4. Submission of Matters to a Vote of Security Holders - N/A Item 5. Other Information - N/A Item 6. Exhibits & Reports on Form 8-K - (a) Documents filed as part of the report (3) Exhibits 10.19 Employment Agreement dated as of November 1, 2003 between Swift Energy Company and James P. Mitchell. 12 Swift Energy Company Ratio of Earnings to Fixed Charges. 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K filed during the quarter ended September 30, 2003, which are incorporated herein by reference: On August 6, 2003, the Company filed a Current Report on Form 8-K that reported under Item 7, "Financial Statements, Pro Forma Financial Information and Exhibits" and Item 12, "Results of Operations and Financial Conditions" relating to the press release announcement of second quarter 2003 earnings. 32 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SWIFT ENERGY COMPANY (Registrant) Date: November 14, 2003 By: (original signed by) ----------------- ---------------------------- Alton D. Heckaman, Jr. Senior Vice President, Chief Financial Officer Date: November 14, 2003 By: (original signed by) ----------------- ---------------------------- David W. Wesson Controller and Principal Accounting Officer 33 Exhibit 10.19 EMPLOYMENT AGREEMENT THIS EMPLOYMENT AGREEMENT ("Agreement") is dated this 1st day of November, 2003, by and between Swift Energy Company, a Texas corporation (the "Company"), and James P. Mitchell. W I T N E S S E T H: WHEREAS, Employee is employed as Senior Vice President-Commercial Transactions and Land of the Company; and WHEREAS, the Company and Employee wish to document certain terms of employment of Employee in such capacity; NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and Employee hereby agree as follows: 1. Employment and Term of Employment. Subject to the terms and conditions of this Agreement, the Company hereby agrees to employ Employee, and Employee hereby agrees to serve as Senior Vice President-Commercial Transactions and Land of the Company, or in such other position as is mutually acceptable to both Employee and the Company, for a period commencing on the date hereof through May 9, 2006, which period shall automatically be extended for an additional year on May 9 of each year beginning May 9, 2004 (such period, as so extended at any time, the "Contract Term") unless notice to the contrary is given not less than 60 days prior to any May 9 of each year beginning May 9, 2004 by either party to this Agreement. The period during which Employee actually works for and is employed by the Company is hereafter referred to as the "Term of Employment." 2. Scope of Employment. During the Term of Employment, (i) Employee will serve as Senior Vice President-Commercial Transactions and Land with the powers and responsibilities of such position set forth in the bylaws of the Company, or in such other position as is mutually acceptable to both Employee and the Company, and Employee will perform diligently to the best of his ability those duties set forth therein and in this Agreement in a manner that promotes the interests and goodwill of the Company, (ii) the Company shall not require Employee to relocate from Houston, Texas, and (iii) the Company may assign Employee to other duties. 3. Compensation. During the Term of Employment, the Company shall compensate Employee for his services hereunder in such amount as shall be determined by the Compensation Committee of the Board of Directors of the Company from time to time, but such compensation shall not be reduced at any time in contemplation of, related to, or as a result of, a Change in Control, as defined in Section 7. 4. Additional Compensation and Benefits. As additional compensation for Employee's services under this Agreement, during the Term of Employment the Company agrees to provide Employee with the following reimbursements and benefits: (a) The Company shall reimburse Employee for reasonable and necessary expenses incurred by Employee in furtherance of the Company's business, including a mileage allowance for all business-related travel on a per-mile basis at a rate equivalent to that allowed by the Internal Revenue Service, provided that such expenses are incurred in accordance with the Company's policies and upon presentation of documentation in accordance with expense reimbursement policies of the Company as they may exist from time to time, and submission to the Company of adequate documentation in accordance with federal income tax regulations. (b) Employee may participate in any non-cash benefits provided by the Company to its 34 employees as they may exist from time to time. Such benefits shall include leave or vacation time, medical and dental insurance, life insurance, accidental death and dismemberment insurance, retirement benefits and disability benefits, as such benefits may hereafter be provided by the Company in accordance with its policies in force from time to time. (c) In the event of Employee's death during the Term of Employment (i) for a twelve-month period after his death the Company shall make available at its expense medical and dental insurance covering Employee's spouse and his dependents ("Dependents") who would have been covered (if the Term of Employment had continued) by the Company's medical and dental insurance policies as then in effect or in effect from time to time and (ii) thereafter for the remainder of the Contract Term such medical and dental insurance shall be provided to Employe's spouse and Dependents, with Employee's spouse (or Dependents or estate, if applicable), to reimburse the Company for the cost for comparable family coverage under the Company's medical and dental insurance policies, unless otherwise prohibited by applicable law. 5. Confidentiality. (a) Employee recognizes that the Company's business involves the handling of confidential information of both the Company and the Company's affiliates, subsidiaries, joint venture partners and industry partners, and requires a confidential relationship between them and the Company and Employee. The Company's business requires the fullest practical protection and confidential treatment of unique and proprietary business and technical information, including but not limited to inventions, trade secrets, patents, proprietary and confidential data (including engineering, geophysical, geological and computer program data) and Employee's knowledge of the Company, its affiliates, subsidiaries, joint venture partners, industry partners, customers and contractors (collectively, hereinafter called "Confidential Information") which is conceived or obtained by Employee in the course of his employment. Accordingly, during and after termination of employment by the Company, Employee agrees: (i) to prevent the disclosure to any third party of all such Confidential Information; (ii) not to use for Employee's own benefit any of the Company's Confidential Information, and (iii) not to aid others in the use of such Confidential Information in competition with the Company or its affiliates and subsidiaries. These obligations shall exist during and after any termination of employment hereunder. Notwithstanding anything else contained herein, the term "Confidential Information" shall not be deemed to include any general knowledge, skills or experience acquired by Employee or any knowledge or information known to the public in general. (b) Employee agrees that every item of Confidential Information referred to in this Section 5 which relates to the Company's present business or which arises or is contemplated to arise out of use of the Company's time, facilities, personnel or funds prior to Employee's termination, is the property of the Company. (c) Employee further agrees that upon termination of his employment for any reason, he will surrender to the Company all reports, manuals, procedures, guidelines, documents, writing, illustrations, models and other such materials produced by him or coming into his possession by virtue of his employment with the Company during the period of his employment and agrees that all such materials are at all times the property of the Company. Employee shall be entitled to review, inspect and copy any of the Company information or material necessary for legal or other proceedings to which Employee is a party defendant by reason of the fact that he is or was an Employee of the Company. (d) Employee and the Company acknowledge their respective execution of an agreement 35 entitled "Inventions, Copyrights, and Confidentiality of Company or Customer Information Agreement" (the "Inventions Agreement") and hereby agree that should any provision of this Agreement conflict with any provision of the Inventions Agreement, the provisions of the Inventions Agreement shall control. 6. Covenant Not to Compete. (a) Subject to the provisions of (c) of this section, without the express prior written consent of the Corporate Governance Committee of the Company's Board of Directors, Employee will not serve as an employee, officer, director or consultant, or in any other similar capacity or make investments (other than open market investments in no more than five percent (5%) of the outstanding stock of any publicly traded company) in or on behalf of any person, firm, corporation, association or other entity whose activities directly compete with the activities of the Company existing or contemplated as of the date he last worked on the Company's behalf pursuant to this Agreement, in those portions or areas of oil and gas basins in which the Company is active or as to which it has begun study or analysis, where such employment may involve working for or with, or assisting, such competitor with activities that are the same as or similar to activities Employee performed on behalf of the Company; provided, however, the Company recognizes that any investment made by Employee in oil and gas properties owned by the Company which investments are made on the same terms (or terms more favorable to the Company) as those offered to unaffiliated third parties are specifically excluded from this section; and (b) Subject to the provisions of (c) of this section, without the express prior written consent of the Company, he will not solicit, recruit or hire, or assist any person, firm, corporation, association or other entity in the solicitation, recruitment or hiring of any person engaged by the Company as an employee, officer, director or consultant. (c) Employee's obligations under (a) and (b) of this section shall continue in force during all periods of Employee's employment by the Company, and after termination of employment for that portion of the Contract Term remaining during which (x) Employee actually receives cash payments under this Agreement or (y) Employee would have received such cash payments but for a lump sum payment being made in lieu thereof, whichever is longer, provided that (i) if cash payments to be made by the Company during the remainder of the Contract Term after the Termination Date (as defined below) are not then being made to Employee currently or (ii) if there has been a "Change in Control," as defined below, then the provisions of subsections (a) and (b) of this section shall have no further force and effect after the date that such payments stop or the date such Change of Control occurs, respectively. 7. Termination. (a) Either the Company or Employee may terminate Employee's employment during the Term of Employment upon 60 days' written notice. Such termination by the Company shall require the affirmative vote of a majority of the members of the Board of Directors of the Company then in office who have been or will have been directors for the two-year period ending on the date notice of the meeting or written consent to take such action is first provided to shareholders or directors, as the case may be, or those directors who have been nominated for election or elected to succeed such directors by a majority of such directors (the "Continuing Directors"). In the case of termination of Employee's employment during the Term of Employment, 36 except in those circumstances covered by Sections 7(b) or (c) below, Employee shall be paid over a period commencing on the day after the last day he worked on the Company's behalf pursuant to this Agreement (the "Termination Date") and continuing (the "Continuation Period") for one-half of the remainder of the Contract Term. The amount to be paid shall be equal to the sum of (x) the total salary otherwise payable to Employee over the period which is one-half of the remainder of the Contract Term, based upon the salary being paid to the Employee immediately prior to the Termination Date, plus (y) an additional amount equal to one week's salary (at Employee's then current salary) for every year of service to the Company (rounded up to the nearest full year of service). The total of these amounts shall be referred to as the "Post Termination Payment." The Post Termination Payment shall be paid out on a twice per month basis of equal installments during the Continuation Period so that the Post Termination Payment will be paid in full to Employee by the end of the Continuation Period. Additionally, the Company shall provide at its expense for the Continuation Period such medical and dental coverage as in effect on the Termination Date. Notwithstanding the foregoing, Employee shall not receive such compensation if the Company terminates his employment for Cause. "Cause" shall be defined as (i) commission of fraud against the Company, its subsidiaries, affiliates or customers, (ii) willful refusal without proper legal cause, after 30 days' advance written notice from the Chairman of the Board of the Company and/or the Chief Executive Officer, or, after a Change in Control, from the Continuing Directors, to faithfully and diligently perform Employee's duties as directed in such notice or correct or terminate those practices as described in such notice, all within the context of a forty-hour per week schedule, or (iii) breach of Section of this Agreement. Immediately prior to the date of termination of Employee's employment under this Agreement by either party, except in those circumstances covered by Sections 7(b) or 7(c) below, all outstanding unexercised options to purchase shares of common stock of the Company (granted on or after the date of this Agreement) held by Employee (as of the day prior to such termination) shall immediately vest or be deemed to have vested, and otherwise Employee shall retain such options with no change in the number of shares covered by such options, the date such options first become exercisable, the period over which they are exercisable, or their exercise price. (b) Change of Control. (1) In the event Employee's employment is terminated by the Company, after, by, on account of, or in connection with, a "Change of Control," as defined below, or in the event Employee resigns during the Contract Term hereunder following a "Change in Control," as defined, the Company (i) shall pay Employee on his last day of employment by the Company a lump sum equal to the total compensation which otherwise is payable to Employee for the remainder of the Contract Term, with total compensation to be based upon the salary being paid to Employee immediately prior to the Termination Date (without taking into effect any reduction in salary which may have taken place after, by, on account of, or in connection with a Change of Control), plus an additional amount equal to two weeks' of his then current salary for every year of service to the Company (rounded up to the nearest full year of service), and (ii) provide at the Company's expense for the Contract Term such medical and dental coverage as in effect on the Termination Date. Effective as of the day prior to such Change of Control, all outstanding unexercised stock options to purchase shares of common stock of the Company held by Employee as of such date will immediately become 100% vested and 100% exercisable. (2) Change of Control: "Change of Control," for purposes of this Agreement, shall be deemed to have occurred upon the occurrence of any one (or more) of the 37 following events, other than a transaction with another person controlled by, or under common control with, the Company: (A) Any person, including a "group" as defined in Section (3)(d)(3) of the Securities Exchange Act of 1934, as amended, becomes the beneficial owner of shares of the voting stock of the Company with respect to which 40% or more of the total number of votes for the election of the Board may be cast; (B) As a result of, or in connection with, any cash tender offer, exchange offer, merger or other business combination, sale of assets or contested election, or combination of the above, persons who were directors of the Company immediately prior to such event shall cease to constitute a majority of the Board; (C) The stockholders of the Company shall approve an agreement providing either for a transaction in which the Company will cease to be an independent publicly owned corporation or for a sale or other disposition of all or substantially all the assets of the Company; or (D) A tender offer or exchange offer is made for shares of the Company's Common Stock (other than one made by the Company), and shares of Common Stock are acquired thereunder ("Offer"). (3) Notwithstanding anything to the contrary in this Agreement, in the event that any payment, distribution, or other benefit provided by the Company to or for the benefit of Employee, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended, or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest or penalties, are hereinafter collectively referred to as the "Excise Tax"), the Company shall pay to Employee an additional payment (a "Gross-up Payment") in an amount such that after payment by Employee of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax imposed on any Gross-up Payment, Employee retains an amount of the Gross-up Payment equal to the Excise Tax imposed upon the Payments. The Company and Employee shall make an initial determination as to whether a Gross-up Payment is required and the amount of any such Gross-up Payment. Employee shall notify the Company immediately in writing of any claim by the Internal Revenue Service, which, if successful, would require the Company to make a Gross-up Payment (or a Gross-up Payment in excess of that, if any, initially determined by the Company and Employee) within fifteen days of the receipt of such claim. The Company shall notify Employee in writing at least ten days prior to the due date of any response required with respect to such claim if it plans to contest such claim. If the Company decides to contest such claim, Employee shall cooperate fully with the Company in such action; provided, however, the Company shall bear and pay directly or indirectly all costs and expenses (including additional interest and penalties) incurred in connection with such action and shall indemnify and hold Employee harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of the Compan's action. If, as a result of the Company's action with respect to a claim, Employee receives a refund of any amount paid by the Company with respect to such claim, Employee shall promptly pay such refund to the Company. If the Company fails to timely notify Employee whether it 38 will contest such claim or the Company determines not to contest such claim, then the Company shall immediately pay to Employee the portion of such claim, if any, which it has not previously paid to Employee. (c) In the event of termination due to Employee's death or as a result of total and permanent disability (as defined in the Company's long-term disability plan, or if the Company has no long-term disability plan in effect at the time of Employee's disability, permanent disability shall have the meaning provided in Section 22(e)(3) of the Code, as used herein "Permanent Disability") during the Term of Employment, the Company shall pay to the estate of Employee or Employee, as applicable, in the year of death or the year thereafter (as designated by Employee's estate), or the day after his employment terminates by reason of Permanent Disability, a lump sum payment equal to the total compensation which otherwise is payable to Employee if he worked for one-half of the Contract Term remaining as of the date of death or the day prior to termination of employment by reason of Permanent Disability, with total compensation to be based upon the salary being paid to Employee immediately prior to the date of death or Permanent Disability, plus (ii) an amount equal to one week's salary for every year of service to the Company (rounded up to the nearest full year of service). On the date of Employee's death or Permanent Disability, all outstanding unexercised stock options to purchase shares of common stock of the Company held by Employee immediately prior to such date will immediately become 100% vested and 100% exercisable by Employee's estate or by Employee, as applicable, and remain exercisable until expiration of each option under its original term. (d) In the event Employe's employment is terminated in those circumstances covered by Sections 7(a) or 7(b) above or by reason of Permanent Disability, the Company shall, for a one-year period following Employee's Termination Date, pay the scheduled premium payments (on or before their due dates) on any universal life insurance policy covering Employee's life which is in force immediately prior to the Termination Date; provided, however, that the Company shall be obligated to pay any such premiums only to the extent that, and on the same basis as, payments are made by the Company on the universal life insurance policies covering other employees of the Company with same or similar coverage. 8. Governing Law. This Agreement shall be governed by and construed under the laws of the State of Texas. Venue and jurisdiction of any action relating to this Agreement shall lie in Houston, Harris County, Texas. 9. Notice. Any notice, payment, demand or communication required or permitted to be given by this Agreement shall be deemed to have been sufficiently given or served for all purposes if delivered personally to and signed for by the party or to any officer of the party to whom the same is directed or if sent by registered or certified mail, return receipt requested, postage and charges prepaid, addressed to such party at its address set forth below such party's signature to this Agreement or to such other address as shall have been furnished in writing by such party for whom the communication is intended. Any such notice shall be deemed to be given on the date so delivered. 10. Severability. In the event any provisions hereof shall be modified or held ineffective by any court, such adjudication shall not invalidate or render ineffective the balance of the provisions hereof. 11. Entire Agreement. This Agreement constitutes the sole agreement between the parties and supersedes any and all other agreements, oral or written, relating to the subject matter covered by the Agreement with the exception of certain Indemnity Agreements which may exist between the Company and Employee, and which remain in force independent of this Agreement. 12. Waiver. Any waiver or breach of any of the terms of this Agreement shall not operate as a waiver of 39 any other breach of such terms or conditions, or any other terms or conditions, nor shall any failure to enforce any provisions hereof operate as a waiver of such provision or any other provision hereof. 13. Assignment. This Agreement is a personal employment contract and the rights and interests of Employee hereunder may not be sold, transferred, assigned or pledged. 14. Successors. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, representatives, successors and assigns. 15. Disputes. (a) Subject to Section 15(b) below, if a dispute arises under this Agreement related to the payment of amounts provided hereunder to be paid by the Company to Employee or the timing of such payments or their calculation, and the dispute cannot be settled through direct discussions, the Company and Employee agree that such disputes shall be resolved by submitting such disputes to mandatory binding fast-track arbitration with the American Arbitration Association in Houston, Texas. The Company will pay the actual fees and expenses of the arbitrators, and the parties shall bear equally all other expenses of such arbitration, unless the arbitrators determine that a different allocation would be more equitable. The award of the arbitrators will be the exclusive remedy of the parties for such disputes. Nothing in this Section 15(a) shall prevent either party from seeking provisional injunctive relief pending arbitration, by applying to any court of competent jurisdiction. (b) Section 15(a) to the contrary notwithstanding, it is expressly agreed that if based upon events which take place after, by, on account of, or in connection with, a Change of Control it becomes necessary in Employee's judgment for him to sue the Company in order to collect amounts to be paid to him under this Agreement or otherwise enforce his rights under this Agreement, then the Company will be obligated to pay both its own and Employee's legal fees in such litigation, including the obligation of the Company to pay Employee's legal fees within thirty days of receiving invoices therefor from Employee. (c) The jurisdiction and venue for resolution of any disputes involving this Agreement or Employee's employment by the Company shall be in the state courts of Houston, Harris County, Texas. 16. Lump Sum Payments. If payments to be made under any portion of this Agreement provide for such payments to be made over a period of time, Employee and the Company's Board of Directors may agree for such payments to be made in a lump sum, which shall be determined by discounting the periodic payments using a discount factor of 8% per annum 40 IN WITNESS WHEREOF, the parties hereto affixed their signatures hereunder as of the date first above written. SWIFT ENERGY COMPANY By: /s/ Terry E. Swift --------------------- Terry E. Swift Chief Executive Officer and President "EMPLOYEE" /s/ James P. Mitchell ------------------------ James P. Mitchell 14003 Torrey Village Houston, Texas 77014 41 Exhibit 12 SWIFT ENERGY COMPANY RATIO OF EARNINGS TO FIXED CHARGES
Nine months Years Ended December 31, Ended September 30, ---------------------------------------------------------------------- ------------- 1998 1999 2000 2001 2002 2003 ------------- ------------ ------------- ------------- ------------- ------------- GROSS G&A 21,010,960 20,518,843 23,793,995 25,974,568 26,074,408 22,053,045 NET G&A 3,853,812 4,497,400 5,585,487 8,186,654 10,564,849 10,564,959 INTEREST EXPENSE, NET 8,752,195 14,442,815 15,968,405 12,627,022 23,274,969 20,107,188 RENT EXPENSE 1,117,351 1,272,497 1,255,474 1,322,618 1,923,451 1,610,803 NET INCOME BEFORE TAXES & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (73,391,581) 29,736,151 93,079,346 (34,192,333) 18,408,289 38,450,916 CAPITALIZED INTEREST 3,849,665 4,142,098 5,043,206 6,256,222 6,973,480 5,156,559 DEPLETED CAPITALIZED INTEREST 292,267 323,124 307,249 280,929 215,433 386,877 CALCULATED DATA -------------------------------- UNALLOCATED G&A (%) 18.34% 21.92% 23.47% 31.52% 40.52% 47.91% NON-CAPITAL RENT EXPENSE 204,944 278,911 294,714 416,862 779,345 771,688 1/3 NON-CAPITAL RENT EXPENSE 68,315 92,970 98,238 138,954 259,782 257,229 FIXED CHARGES 12,670,175 18,677,883 21,109,849 19,022,198 30,508,231 25,520,976 EARNINGS (64,278,804) 44,595,061 109,453,238 (21,145,428) 42,158,473 59,202,210 RATIO OF EARNINGS TO FIXED CHARGES --- 2.39 5.18 --- 1.38 2.32 ============ =========== ============ ============ ============ ============
For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense net (which includes amortization of debt issuance costs and discounts), capitalized interest and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes and cumulative effect of change in accounting principle and from continuing operations before fixed charges (excluding capitalized interest, net of depletion). Due to the $98.9 million non-cash charge incurred in the fourth quarter of 2001 caused by a write-down in the carrying value of oil and gas properties, 2001 earnings were insufficient by $40.2 million to cover fixed charges in this period. If the $98.9 million non-cash charge is excluded, the ratio of earnings to fixed charges would have been 4.09 for 2001. Due to the $90.9 million non-cash charge incurred in the third quarter of 1998 caused by a write-down in the carrying value of oil and gas properties, 1998 earnings were insufficient by $76.9 million to cover fixed charges in this period. If the $90.8 million non-cash charge is excluded, the ratio of earnings to fixed charges would have been for 2.09 for 1998. 42 Exhibit 31.1 CERTIFICATION I, Terry E. Swift, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Swift Energy Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of Swift Energy as of, and for, the periods presented in this quarterly report; 4. Swift Energy's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for Swift Energy and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Swift Energy, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of Swift Energy's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and c) disclosed in this quarterly report any changes in Swift Energy Company's internal control over financial reporting that occurred during Swift Energy Company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Swift Energy Company's internal control over financial reporting; and 5. Swift Energy's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Swift Energy Company's auditors and the audit committee of Swift Energy Company's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect Swift Energy Company's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in Swift Energy Company's internal control over financial reporting. Date: November 14, 2003 (original signed by) ------------------------- Terry E. Swift President and Chief Executive Officer 43 Exhibit 31.2 CERTIFICATION I, Alton D. Heckaman, Jr., certify that: 1. I have reviewed this quarterly report on Form 10-Q of Swift Energy Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of Swift Energy as of, and for, the periods presented in this quarterly report; 4. Swift Energy's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) for Swift Energy and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Swift Energy, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of Swift Energy's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and c) disclosed in this quarterly report any changes in Swift Energy Company's internal control over financial reporting that occurred during Swift Energy Company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Swift Energy Company's internal control over financial reporting; and 5. Swift Energy's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Swift Energy Company's auditors and the audit committee of Swift Energy Company's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect Swift Energy Company's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in Swift Energy Company's internal control over financial reporting. Date: November 14, 2003 (original signed by) ------------------------------ Alton D. Heckaman, Jr. Senior Vice President - Finance Chief Financial Officer 44 Exhibit 32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 (the "Report") of Swift Energy Company ("Swift") as filed with the Securities and Exchange Commission on November 14, 2003, the undersigned, in his capacity as an officer of Swift, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Swift. Dated: November 14, 2003 (original signed by) --------------------------------- Alton D. Heckaman, Jr. Senior Vice President-Finance and Chief Financial Officer Dated: November 14, 2003 (original signed by) --------------------------------- Terry E. Swift President and Chief Executive Officer This certification made in accordance with Section 906 of the Sarbanes-Oxley Act of 2002 is furnished by Swift and accompanies the Quarterly Report on Form 10-Q of Swift for the period ended September 30, 2003. This certification shall not be deemed filed by Swift for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended. 45