SWIFT ENERGY COMPANY 2000 ANNUAL REPORT

Management's Discussion and Analysis of
Financial Condition and Results of Operations

The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes thereto.

General

Over the last several years, we have emphasized adding reserves through drilling activity. We also add reserves through strategic purchases of producing properties when oil and gas prices are at lower levels and other market conditions are appropriate, as we did in the third quarter of 1998 with the purchase of the Brookeland and Masters Creek areas. During the past three years, we have used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production.

Proved Oil and Gas Reserves. At year-end 2000, our total proved reserves were 629.4 Bcfe with a PV-10 Value of $2.3 billion. In 2000, our proved natural gas reserves increased 88.7 Bcf, or 27%, while our proved oil reserves increased 14.3 MMBbl, or 69%, for a total equivalent increase of 174.6 Bcfe, or 38%. From 1998 to 1999, our proved natural gas reserves decreased by 22.4 Bcf, or 6%, while our proved oil reserves increased by 6.8 MMBbl, or 49%, for a total equivalent increase of 18.6 Bcfe, or 4%. We added reserves from 1999 to 2000 through our drilling activity and to a lesser extent through purchases of minerals in place. Through drilling we added 184.7 Bcfe (122.5 Bcfe of which came from New Zealand) of proved reserves in 2000, 64.9 Bcfe in 1999, and 73.9 Bcfe in 1998. Through acquisitions we added 39.7 Bcfe of proved reserves in 2000, 20.1 Bcfe in 1999, and 97.6 Bcfe in 1998. At year-end 2000, 55% of our total proved reserves were proved undeveloped, compared with 51% at year-end 1999 and 45% at year-end 1998.

While our total proved reserves quantities increased by 38% during 2000, the PV-10 Value of those reserves increased 310%, due to increased prices between year-end 1999 and year-end 2000. Between those two dates, there was a 282% increase in natural gas prices and a 4% increase in oil prices. Gas prices were $9.86 per Mcf at year-end 2000, compared to $2.58 per Mcf at year-end 1999. Oil prices were $24.62 per Bbl at year-end 2000, compared to $23.69 a year earlier. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant throughout the life of the properties. Subsequent changes to such year-end oil and gas prices could have a significant impact on the calculated PV-10 Value. The year-end 2000 gas price of $9.86 was significantly higher than the average gas price of $4.24 we received during 2000. Natural gas prices have declined since December 31, 2000, although through February 2001 they remain above the 2000 average gas price received. Had year-end reserves been calculated using the average 2000 prices we received, $29.35 for oil and $4.24 for gas, the PV-10 Value would have been approximately $1,125,000,000 compared to the $2,313,254,809 reported using year-end prices.

Liquidity and Capital Resources

During 2000, we primarily relied upon internally generated cash flows of $128.2 million to fund capital expenditures of $173.3 million. These capital expenditures were also funded with part of the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock. During 1999, we primarily used internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million.

Net Cash Provided by Operating Activities. In 2000, net cash provided by our operating activities increased by 74% to $128.2 million, as compared to $73.6 million in 1999 and $54.2 million in 1998. 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, interest expense, and general and administrative expense. The 1999 increase of $19.4 million was primarily due to $28.8 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, 2000, we had $10.6 million in outstanding borrowings under our credit facility. Our credit facility consists of a $250.0 million revolving line of credit with a $200.0 million borrowing base at year-end 2000. 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 August 2002. At December 31, 1999, we had no outstanding borrowings under this facility.

Working Capital. Our working capital has decreased from $16.5 million at December 31, 1999, to a working capital deficit of $22.5 million at December 31, 2000, primarily due to our using the remaining proceeds from our third quarter 1999 public offering of Senior Notes and common stock to fund capital expenditures in 2000.

Capital Expenditures. In 2000, our capital expenditures of approximately $173.3 million were spent as follows:

Domestic Activities:

• $90.3 million, or 52%, on developmental drilling;

• $33.4 million, or 19%, for producing properties acquisitions, approximately half of which was for the purchase of property interests from partnerships managed by us, with the other half purchased from a third party;

• $16.3 million, or 9%, on domestic prospect costs, principally leasehold, seismic, and geological costs;

• $15.5 million, or 9%, on exploratory drilling;

• $1.4 million, or 1%, for fixed assets;

• $0.8 million, or less than 1%, on two gas processing plants in the Brookeland and Masters Creek areas; and

• $0.2 million, or less than 1%, on field compression facilities.

New Zealand Activities:

• $7.6 million, or 4%, on developmental drilling to further delineate the Rimu area;

• $4.5 million, or 3%, on prospect costs, principally seismic and geological costs;

• $2.1 million, or 1%, for exploratory drilling;

• $1.1 million, or 1%, on the initial stages of production facilities; and

• $0.1 million, or less than 1%, for fixed assets, principally a field office and warehouse.

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. Our $55.5 million of unproved property costs not being amortized is indicative of our inventory of developmental and exploratory acreage to sustain drilling activity for future growth.

Capital expenditures for 2001 are estimated to be approximately $173.8 million. Approximately $97.8 million of the 2001 budget is allocated to domestic drilling, primarily development drilling in the AWP Olmos, Brookeland, and Masters Creek areas, and exploratory drilling in the Gulf Coast Basin. In New Zealand, approximately $17.7 million of the 2001 budget is allocated to development and exploration drilling, with another $14.5 million expected to be spent primarily for production facilities. In 2001, we anticipate drilling 39 development wells and 10 exploratory wells domestically, along with four wells in New Zealand. Approximately $33.8 million is targeted towards the acquisition of producing properties. The remaining $20.1 million will be used primarily for domestic leasehold, seismic, and geological costs, while approximately $3.7 million is budgeted for such costs in New Zealand. Dispositions of approximately $13.8 million are anticipated.

We believe that the anticipated internally generated cash flows for 2001, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2001 capital expenditures.

Our capital expenditures were approximately $78.1 million in 1999 and $183.8 million in 1998. During 1998, we used $138.3 million of bank borrowings, along with internal cash flows of $54.2 million, to fund capital expenditures. During 1999, we primarily used internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. Our capital expenditures in 1999 included:

• $34.0 million, or 44%, on developmental drilling;

• $20.6 million, or 26%, on producing properties acquisitions, almost all of which was for the purchase of additional working interests in the Masters Creek area;

• $10.4 million, or 13%, on prospect costs, principally leasehold, seismic, and geological costs;

• $10.0 million, or 13%, on exploratory drilling, $5.9 million of which was in New Zealand;

• $1.6 million, or 2%, on two gas processing plants in the Brookeland and Masters Creek areas;

• $1.3 million, or 2%, on fixed assets; and

• $0.2 million, or less than 1%, on field compression facilities.

In 1999, we participated in drilling 22 development wells and five exploratory wells, of which 19 development wells and two exploratory wells were successes. Two of the exploratory wells were drilled in New Zealand. The first well in New Zealand, in which we had a 7.5% working interest, was drilled by another operator and was temporarily abandoned. The second well, the Rimu-A1, which Swift drilled as operator with a 90% working interest, was successful.

Results of Operations

Revenues. Our revenues in 2000 increased by 73% over revenues in 1999 due to increases in oil and gas sales.

Oil and gas sales revenues in 2000 increased by 74%, or $80.2 million, over those revenues for 1999. Our net sales volumes in 2000, including the volumetric production payment associated with each year’s production, decreased by 1%, or 0.5 Bcfe, over net sales volumes in 1999. Average prices received for oil increased from $16.75 per Bbl in 1999 to $29.35 per Bbl in 2000. 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:

• Price variances that had an $81.7 million favorable impact on sales, $31.1 million of which was attributable to the 75% increase in average oil prices received and $50.6 million of which was attributable to the 77% increase in average gas prices received; and

• Volume variances that had a $1.5 million unfavorable impact on sales, with $1.6 million of decreases coming from the 93,000 Bbl decrease in oil sales volumes, partially offset by an increase of $0.1 million from the 40,000 Mcf increase in gas sales volumes.

Revenues in 1999 increased by 34% over 1998 revenues. In 1999, oil and gas sales revenues increased by 36%, or $28.8 million, over those revenues in 1998. In 1999, net sales volumes increased by 10%, or 3.8 Bcfe, over net sales volumes in 1998. Average oil prices received went from $11.86 per Bbl in 1998 to $16.75 per Bbl in 1999, and average gas prices received increased from $2.08 per Mcf in 1998 to $2.40 per Mcf in 1999.

In 1999, our $28.8 million increase in oil and gas sales resulted from:

• Price variances that had a $21.3 million favorable impact on sales, $12.6 million of which was attributable to the 41% increase in average oil prices received and $8.7 million of which was attributable to the 15% increase in average gas prices received; and

• Volume variances that added $7.5 million of sales, with $9.0 million of increases coming from the 0.8 MMBbl increase in oil sales volumes, partially offset by a decline of $1.5 million from the 0.7 Bcf decrease 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 four domestic core areas in 2000 and 1999:

We scaled back our budgeted 1999 capital expenditures from budgeted amounts in prior years in response to commodity price decreases experienced in the latter part of 1998 and first half of 1999. Drilling activity then resumed at an increased pace as commodity prices rebounded in 2000. However, due to the decrease in the 1999 capital expenditures budget and the resulting curtailment of drilling, we drilled 27 gross wells in 1999 as compared to 75 in 1998 and 70 in 2000. Thus, the natural production declines in the Giddings and the Brookeland areas were not offset by newly developed production.

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 2000, 98% of total revenues for 1999, and 97% of total revenues for 1998. Natural gas production made up 65% of our production volumes in 2000, 64% in 1999, and 72% in 1998.

Costs and Expenses. Our general and administrative expenses in 2000 increased $1.1 million, or 24%, from the level of such expenses in 1999, while 1999 general and administrative expenses increased $0.6 million, or 17%, over 1998 levels. These increases reflect the increase in our corporate activities. Our general and administrative expenses per Mcfe produced increased to $0.13 per Mcfe in 2000 from $0.10 per Mcfe in both 1999 and 1998. The portion of supervision fees netted from general and administrative expenses was $3.4 million for 2000, $3.2 million for 1999, and $2.7 million for 1998.

Depreciation, depletion, and amortization of our assets, or DD&A, increased $5.4 million, or 13%, in 2000 from 1999, while 1999 DD&A increased $3.0 million, or 8%, from 1998 levels. This was primarily due to additions in our reserves and increased associated costs in 2000 over 1999, while in the 1999 period it was primarily due to the 10% increase in production over 1998. Our DD&A rate per Mcfe of production was $1.13 in 2000, $0.99 in 1999, and $1.01 in 1998, reflecting variations in per unit cost of reserves additions.

Our production costs in 2000 increased $9.6 million, or 49%, over such expenses in 1999, while those expenses in 1999 increased $6.5 million, or 50%, over 1998 costs. Our production costs per Mcfe produced were $0.69 in 2000, $0.46 in 1999, and $0.34 in 1998. The portion of supervision fees netted from production costs was $3.4 million for 2000, $3.2 million for 1999, and $2.7 million for 1998. While our production costs increased 49% in 2000, our oil and gas sales increased 74%. That increase in oil 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 therefore 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.

The 50% increase in our production costs during 1999 relates to the 10% increase in production volumes in 1999 over 1998. The higher percentage increase in costs was due to planned increases in remedial well work, increased severance taxes, and increased ad valorem taxes. The increase in severance taxes was partially due to the increase in oil and gas prices received in 1999 when compared to 1998. Also, severance taxes increased on certain wells in the Masters Creek area as the gas severance tax exemption they had received from Louisiana expired once they had been in production for more than two years or once payout of the well occurred. The ad valorem tax increase resulted from wells we drilled in the first half of 1998 and wells drilled in 1998 that we acquired in the Brookeland and Masters Creek acquisition as those wells were subject to ad valorem taxes for the first time at the beginning of 1999.

Interest expense on our Senior Notes issued in July 1999, including amortization of debt issuance costs, totaled $13.1 million in 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 each of the years 1999 and 1998. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.7 million in 2000, $6.1 million in 1999, and $5.6 million in 1998. The total interest expense in 2000 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. The 1998 total interest expense was $13.1 million, of which $4.4 million was capitalized. We capitalize that portion of interest related to our exploration, partnership, and foreign business development activities. 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. The increase in interest expense in 1999 was attributed to the increase in amounts outstanding to fund our 1998 capital expenditures, which included the Brookeland and Masters Creek areas acquisition in the third quarter of 1998, and to the higher interest rate on our new Senior Notes when compared to our credit facility.

In the fourth quarter of 2000, we took 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.

In the third quarter of 1998, we took a 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 September 30, 1998, necessitated a pre-tax domestic full-cost ceiling write-down of $77.2 million, or $50.9 million after tax. Also, in the third quarter of 1998, we re-evaluated the capitalized unproved properties costs in Russia of $10.8 million and in Venezuela of $2.8 million, which resulted in a separate non-cash pre-tax charge to earnings of $13.6 million, or $9.0 million after tax. The combination of the non-cash domestic full-cost ceiling write-down and the non-cash foreign impairment charges resulted in a combined non-cash charge to earnings of $90.8 million pre-tax, or $59.9 million after tax.

Net Income. Our income before extraordinary item in 2000 of $59.8 million was 210% higher, and Basic earnings per share ("Basic EPS") before extraordinary item of $2.82 were 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.

Our net income in 1999 of $19.3 million was 65% higher and Basic EPS of $1.07 was 51% higher than 1998 income before the non-cash write-down of oil and gas properties of $11.7 million and Basic EPS of $0.71. These increases reflected the effect of the 10% increase in production volumes, the 41% increase in oil prices, and the 15% increase in gas prices. Oil and gas prices rose rapidly in the third and fourth quarters of 1999, as reflected by last half net income making up 77% of net income for the year. The lower percentage increase in Basic EPS reflected a 10% increase in weighted average shares outstanding in 1999, primarily due to our third-quarter 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.

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