Liquidity and Capital Resources

During 2001, we relied both upon internally generated cash flows of $139.9 million and $123.4 million of additional borrowings from our bank credit facility to fund capital expenditures of $275.1 million. During 2000, we primarily used internally generated cash flows of $128.2 million to fund capital expenditures of $173.3 million, along with the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock.

Net Cash Provided by Operating Activities. In 2001, net cash provided by our operating activities increased by 9% to $139.9 million, as compared to $128.2 million in 2000 and $73.6 million in 1999. The 2001 increase of $11.7 million was primarily due to reductions in working capital as oil and gas sales receivables decreased in 2001 along with a reduction in interest expense of $3.3 million. These increases in cash flow were offset by an $8.0 million reduction of oil and gas sales, a $7.5 million increase in oil and gas production costs, and a $2.6 million increase in general and administrative expense. The 2000 increase of $54.6 million was primarily due to $80.2 million of additional oil and gas sales, partially offset by $12.2 million of increases in oil and gas production costs and interest expense.

Existing Credit Facilities. At December 31, 2001, we had $134.0 million in outstanding borrowings under our credit facility. Our credit facility at year-end 2001 consisted of a $250.0 million revolving line of credit with a $200.0 million borrowing base. The borrowing base is redetermined at least every six months. 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. The credit facility extends until October 2005. At December 31, 2000, we had $10.6 million in outstanding borrowings under this facility.

Subsequent to December 31, 2001, upon the closing of the New Zealand TAWN acquisition, the credit facility was increased to $300.0 million and the borrowing base became $275.0 million.

Working Capital. Our working capital decreased from a deficit of $22.5 million at December 31, 2000, to a deficit of $36.5 million at December 31, 2001. The decrease was primarily due to reductions in oil and gas sales receivables, as oil and gas prices were lower at year-end 2001, and an increase in payables to partnerships related to December 2001 oil and gas property sales.

Domestic Activities of $224.3 million as follows:

New Zealand Activities of $50.8 million as follows:

In 2001, we participated in drilling 40 development wells and 13 exploratory wells, of which 38 development wells and six exploratory wells were successes. Four of the development wells were drilled in New Zealand to delineate the Rimu and Kauri areas, two of which were successful. Two of the exploratory wells were drilled in New Zealand; one unsuccessful and one was temporarily abandoned. Of our $95.9 million of unproved property costs, $72.3 million relates to our inventory of developmental and exploratory acreage to sustain drilling activity for future growth, while the remaining $23.6 million pertains to the Rimu Production Station which will be reclassified to proved properties once it comes on-line near the end of the first quarter of 2002.

Capital expenditures for 2002 are estimated to be approximately $132.5 million. Approximately $39.8 million of the 2002 budget is allocated to domestic drilling, primarily in the Lake Washington area. In New Zealand, approximately $11.2 million of the 2002 budget is allocated to drilling, with another $8.7 million expected to be spent primarily for production facilities. In 2002, we anticipate drilling 20 development wells and 2 exploratory wells domestically, along with six development wells and one exploratory well in New Zealand. Approximately $54.6 million is targeted towards producing property acquisitions, the majority for the TAWN properties in New Zealand that closed in January 2002. Of the remainder $13.5 million will be used primarily for domestic leasehold, seismic, and geological costs, and $4.7 million is budgeted for such costs in New Zealand. This $132.5 million budget also excludes any producing property acquisitions that may arise in this low price environment and also excludes any property sales. Although we expect our 2002 total production to increase by 10% to 20% over 2001 due to the focus of our budget in the Lake Washington area and in New Zealand, we expect production to decline in our other core areas as no new drilling is currently budgeted to offset their natural production decline.

We believe that the anticipated internally generated cash flows for 2002, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2002 capital expenditures. Should other producing property acquisitions activity become attractive in the current environment, the Company would intend to explore the use of debt and or equity offerings to fund such activity.

Our capital expenditures were approximately $173.3 million in 2000 and $78.1 million in 1999. During 1999, we used internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. During 2000, we primarily used internally generated cash flows of $128.2 million to fund capital expenditures of $173.3 million, along with part of the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock. Our capital expenditures in 2000 included:

Domestic Activities of $157.9 million as follows:

New Zealand Activities of $15.4 million as follows:

In 2000, we participated in drilling 61 development wells and nine exploratory wells, of which 54 development wells and five exploratory wells were successes. Two of the development wells were drilled in New Zealand to delineate the Rimu area, both of which were successful.

Subsequent Events

TAWN Acquisition. Through our subsidiary, Swift Energy New Zealand Limited, we acquired Southern Petroleum Exploration Limited ("Southern NZ") in January 2002 for approximately $54.4 million in cash. 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. As of December 31, 2001, the reserves associated with this acquisition were estimated to be approximately 62.1 Bcfe, all of which were proved developed. This acquisition was accounted for by the purchase method of accounting. Upon the closing of this acquisition, our credit facility was increased to $300.0 million, and the borrowing base became $275.0 million.

In conjunction with the TAWN acquisition, we granted Shell New Zealand a short-term option to acquire an undivided 25% interest in our permit 38719, which includes our Rimu and Kauri areas, as well as a 25% interest in our Rimu Production Station. We do not know if Shell New Zealand will exercise this option. The option would be subject to numerous notifications, governmental approvals and consents if exercised. If the option is exercised, our credit facility would be reduced to $275.0 million and our borrowing base would be $250.0 million.

Antrim Acquisition. We purchased through our subsidiary, Swift Energy New Zealand Limited, all of the New Zealand assets owned by Antrim Oil and Gas Limited for 220,000 shares of Swift Energy Company common stock. Antrim owned a 5% interest in permit 38719 and a 7.5% interest in permit 38716. As of December 31, 2001, the reserves associated with this acquisition were estimated to be approximately 5.7 Bcfe. This transaction closed in March 2002.

Results of Operations

Revenues. Our revenues in 2001 decreased by 4% compared to revenues in 2000 due primarily to decreases in oil prices.

Oil and gas sales revenues in 2001 decreased by 4%, or $8.0 million, from the level of those revenues for 2000 even though our net sales volumes in 2001 increased by 6%, or 2.4 Bcfe, over net sales volumes in 2000. Average prices received for oil decreased to $22.64 per Bbl in 2001 from $29.35 per Bbl in 2000. Average gas prices received decreased slightly to $4.23 per Mcf in 2001 from $4.24 per Mcf in 2000.

In 2001, our $8.0 million decrease in oil and gas sales resulted from:

Revenues in 2000 increased by 73% compared to 1999 revenues. In 2000, oil and gas sales revenues increased by 74%, or $80.2 million, over those revenues in 1999. In 2000, net sales volumes decreased by 1%, or 0.5 Bcfe, compared to net sales volumes in 1999. Average oil prices received went from $16.75 per Bbl in 1999 to $29.35 per Bbl in 2000, and average gas prices received increased from $2.40 per Mcf in 1999 to $4.24 per Mcf in 2000.

In 2000, our $80.2 million increase in oil and gas sales resulted from:

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four domestic core areas and New Zealand:

Our 2001 drilling activity increased production in the Brookeland area and stabilized production in the AWP Olmos area, but did not prevent a decline in production in the Masters Creek area.

The following table provides additional information regarding our oil and gas sales:

Revenues from our oil and gas sales comprised 99% of total revenues for both 2001 and 2000 and 98% of total revenues for 1999. Natural gas production made up 59% of our production volumes in 2001, 65% in 2000, and 64% in 1999.

Depreciation, depletion, and amortization of our assets, or DD&A, increased $11.7 million, or 25%, in 2001 from 2000, while 2000 DD&A increased $5.4 million, or 13%, from 1999 levels. In 2001, the increase was primarily due to additional dollars spent to add to our reserves and increased associated costs in an environment where demand for such services had increased compared to 2000, along with a 6% increase in production. In 2000, the increase was primarily due to the additional dollars spent to add to our reserves and associated costs in 2000 over 1999. Our DD&A rate per Mcfe of production was $1.33 in 2001, $1.13 in 2000, and $0.99 in 1999, reflecting variations in per unit cost of reserves additions.

Our production costs in 2001 increased $7.5 million, or 26%, over such expenses in 2000, while those expenses in 2000 increased $9.6 million, or 49%, over 1999 costs. Our production costs per Mcfe produced were $0.82 in 2001, $0.69 in 2000, and $0.46 in 1999. The portion of supervision fees netted from production costs was $3.1 million for 2001, $3.4 million for 2000, and $3.2 million for 1999. Approximately $1.7 million of the increase in production costs during 2001 was related to severance taxes. Severance taxes increased primarily from the expiration of certain specific well severance tax exemptions. The remainder of the increase reflected costs associated with new wells drilled and acquired and the related increase in costs in procuring such services in an environment where demand for such services has increased from the prior year.

While our production costs increased 49% in 2000, our oil and gas sales increased 74%. That increase in oil and gas sales had a direct impact on the increase in production costs, as severance taxes have a direct correlation to sales and were $4.9 million higher in 2000. Also, the increase in commodity prices brought increased demand and competition for field services that resulted in an increase in the cost of those services. Remedial well work and workover costs increased $1.2 million over 1999 levels. In the Masters Creek area, salt-water disposal charges, which increased $0.4 million over 1999 charges, increased as the volume of water associated with that production increased. Also in the Masters Creek area, production chemical costs increased $0.6 million as we began our scale inhibitor program in that area.

Interest expense on our Senior Notes issued in July 1999, including amortization of debt issuance costs, totaled $13.1 million in both 2001 and 2000 and $5.3 million in 1999. Interest expense on our Convertible Notes due 2006, including amortization of debt issuance costs, totaled $7.4 million in 2000 and $7.5 million in 1999. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $5.8 million in 2001, $0.7 million in 2000 and $6.1 million in 1999. The total interest expense in 2001 was $18.9 million, of which $6.3 million was capitalized. The 2000 total interest expense was $21.2 million, of which $5.2 million was capitalized. The 1999 total interest expense was $18.9 million, of which $4.5 million was capitalized. We capitalize that portion of interest related to our exploration, partnership, and foreign business development activities. The decrease in total interest expense in 2001 was attributed to the conversion and extinguishment of our Convertible Notes in December 2000 and the increase in capitalized interest, partially offset by the increase in interest paid on our credit facility. The increase in interest expense in 2000 was attributed to the replacement of our bank borrowings in August 1999 with the Senior Notes that carry a higher interest rate.

In the fourth quarter of 2001, we took a domestic non-cash write-down of oil and gas properties, as discussed in Note 1 to the Consolidated Financial Statements. Lower prices for both oil and natural gas at December 31, 2001, necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million, or $63.5 million after tax. In addition to this domestic ceiling write-down, we also expensed $2.1 million of non-recurring charges in the fourth quarter of 2001 for certain delinquent accounts receivable, the majority of which is related to gas sold to Enron, and a write-off of debt issuance costs for a planned offering that was cancelled based upon market conditions following the events of September 11, 2001.

As discussed in Note 1 to the Consolidated Financial Statements, we adopted SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $392,868, which is recorded as a Cumulative Effect of Change in Accounting Principle on our Consolidated Statement of Income.

In the fourth quarter of 2000, we recorded a $0.6 million non-recurring loss on the early extinguishment of debt (net of taxes), as discussed in Note 4 to the Consolidated Financial Statements. We called our Convertible Notes for redemption effective December 26, 2000. Holders of approximately $100.0 million of the Convertible Notes elected to convert their notes into shares of our common stock. Holders of the remaining $15.0 million of the Convertible Notes elected to redeem their notes for cash plus accrued interest. This cash redemption resulted in this non-recurring item.

Net Income (Loss). Our loss before extraordinary item and change in accounting principle in 2001 of $(22.0) million was 137% lower and Basic loss per share ("Basic EPS") before extraordinary item and change in accounting principle of $(0.89) was 132% lower than our 2000 net income of $59.8 million and Basic EPS of $2.82. These decreases reflected the effect of $101.0 million in non-recurring charges in 2001 as described above. The lower percentage decrease in Basic EPS reflects a 16% increase in weighted average shares outstanding in 2001, primarily due to the conversion of our Convertible Notes into 3.2 million shares of common stock in December 2000.

Our net loss for 2001 was $(22.3) million with a loss per share of $(0.90) per diluted share. Our net income for 2001, excluding non-recurring charges of $101.0 million as described above, totaled $42.5 million with EPS of $1.67 per diluted share. These amounts are lower than our 2000 net income of $59.8 million and EPS of $2.53 per diluted share, primarily due to significantly lower oil prices and overall increased costs.

Our income before extraordinary item in 2000 of $59.8 million was 210% higher and Basic EPS before extraordinary item of $2.82 was 164% higher than our 1999 net income of $19.3 million and Basic EPS of $1.07. These increases reflected the effect of the 75% increase in average oil prices received and 77% increase in average gas prices received. Oil and gas prices rose each quarter and resulted in quarterly sequential increases in earnings. The lower percentage increase in Basic EPS reflects an 18% increase in weighted average shares outstanding in 2000, primarily due to our third-quarter 1999 public sale of 4.6 million shares of common stock.

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 natural gas prices, internationally or in the United States; availability of services and supplies; 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.