MANAGING GROWTH IN THE 21st CENTURY
	SWIFT ENERGY COMPANY 1999 ANNUAL REPORT
Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the Company’s 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. Virtually all of our revenues are from oil and gas sales attributable to our production.

Proved Oil and Gas Reserves. At year-end 1999, our total proved reserves were 454.8 Bcfe with a PV-10 Value of $564.1 million. In 1999, our proved natural gas reserves decreased 22.4 Bcf, or 6%, while our proved oil reserves increased 6.8 MMBbl, or 49%, for a total equivalent increase of 18.6 Bcfe, or 4%. From 1997 to 1998, we increased our proved natural gas reserves by 38.1 Bcf, or 12%, and our proved oil reserves by 6.1 MMBbl, or 78%, for a total equivalent increase of 74.7 Bcfe, or 21%. We added reserves from 1998 to 1999 through our drilling activity and through purchases of minerals in place, primarily in the Masters Creek area. Through drilling we added 64.9 Bcfe of proved reserves in 1999, 73.9 Bcfe in 1998, and 120.2 Bcfe in 1997. Through acquisitions we added 20.1 Bcfe of proved reserves in 1999, 97.6 Bcfe in 1998, and 33.8 Bcfe in 1997. A substantial portion of these reserves are proved undeveloped. At year-end 1999, 51% of our total proved reserves were proved undeveloped, compared with 45% at year-end 1998, and 40% at year-end 1997.

While our total proved reserves quantities at year-end 1999 increased by 4% over those at year-end 1998, the PV-10 Value of those reserves increased 66%, almost entirely due to increased prices between year-end 1998 and year-end 1999. Between those two dates, there was a 16% increase in natural gas prices and a 111% increase in oil prices. Gas prices were $2.58 per Mcf at year-end 1999 compared to $2.23 per Mcf at year-end 1998. Oil prices were $23.69 per Bbl at year-end 1999 compared to $11.23 a year earlier.

Under SEC guidelines, estimates of proved reserves are made using year-end oil and gas sales prices and are held constant throughout the life of the properties. The prices used to calculate the PV-10 Value may not be indicative of future sales prices ultimately received.

Liquidity and Capital Resources

During 1999, we primarily relied upon internally generated cash flows of $73.6 million to fund capital expenditures of $78.1 million. Capital expenditures were also partially funded with the remaining net proceeds, after repayment of our bank borrowings, from our third quarter issuance of senior subordinated notes and common stock. During 1998, we used $138.3 million borrowed under our credit facilities, along with internally generated cash flows, to fund capital expenditures and property acquisitions totaling $183.8 million.

Net Cash Provided by Operating Activities. In 1999, net cash provided by our operating activities increased by 36% to $73.6 million, as compared to $54.2 million in 1998 and $55.3 million in 1997. 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. The slight decrease of $1.1 million in net cash provided in 1998 was primarily due to the offset of our 54% increase in production volumes by:

• the 25% decrease in average commodity prices received;

• the associated 50% increase in oil and gas production costs; and

• a decrease in interest income and an increase in interest expense due to our use in 1997 of the net proceeds of our 1996 sale of convertible notes, resulting in increased bank borrowings during 1998.

Existing Credit Facilities. At December 31, 1999, we had no outstanding borrowings under our credit facility. Our credit facility consists of a $250.0 million revolving line of credit with a $100.0 million borrowing base at December 31, 1999. The borrowing base is redetermined at least every six months. Our $250.0 million 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 currently in compliance with the provisions of this agreement. The credit facility extends until August 2002. At December 31, 1998, we had outstanding borrowings of $146.2 million under that facility.

Working Capital. Our working capital has increased from $3.8 million at December 31, 1998, to $16.5 million at December 31, 1999, primarily due to the remaining proceeds from our third quarter 1999 public offerings of senior notes and common stock.

Common Stock Repurchase Program. In March 1997, we commenced a common stock repurchase program which terminated pursuant to its terms as of June 30, 1999. We spent approximately $13.3 million to acquire 927,774 shares at an average cost of $14.34 per share. In March 1999, we used 68,318 shares of common stock held as treasury stock to fund our employer contribution in the 401(k) program for our employees.

Capital Expenditures. In 1999, we spent approximately $78.1 million to fund capital expenditures, including:

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

• $20.6 million, or 26%, spent 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%, spent on prospect costs, principally leasehold, seismic, and geological costs of unproven prospects for our account;

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

• $1.6 million, or 2%, spent 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%, spent on field compression facilities.

In 1999, we participated in drilling 22 development wells and five exploratory wells, of which 19 development wells and one exploratory well were successes, while another exploratory well is still under evaluation. Two of the exploratory wells were drilled in New Zealand. The first well in which we had a 10% working interest was unsuccessful and was drilled by another operator. The second well, which Swift drilled with a 90% working interest, has been completed and a ten-day production test has been performed. We believe that this discovery will result in proved reserves upon further evaluation and analysis. Our $57.7 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 2000 are estimated to be approximately $114.8 million. Approximately $59.6 million of the 2000 budget is allocated to development and exploration drilling, primarily in our four core areas: AWP Olmos, Brookeland, Giddings, and Masters Creek. We anticipate drilling 36 development wells and 11 exploratory wells in 2000. Approximately $35.6 million is targeted towards the acquisition of producing properties. The remaining $19.6 million will be used primarily for leasehold, seismic, and geological costs, including approximately $2.7 million of such costs in New Zealand.

The Company believes that 2000’s anticipated internally generated cash flows, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2000 capital expenditures.

Our capital expenditures were approximately $183.8 million for 1998 and $132.0 million for 1997. During 1997, we relied upon net proceeds from the sale in 1996 of $115.0 million of convertible notes due 2006 and on internally generated cash flows, along with $7.9 million of bank borrowings, to fund capital expenditures. During 1998, we used $138.3 million of bank borrowings, along with internal cash flows of $54.2 million, to fund capital expenditures. Capital expenditures in 1998 included:

• $59.5 million, or 32%, spent on producing properties acquisitions, almost all of which was used to acquire the Brookeland and Masters Creek areas;

• $54.8 million, or 30%, spent on developmental drilling, primarily in the AWP Olmos and Giddings areas;

• $34.7 million, or 19%, spent on domestic prospect costs, principally leasehold, seismic, and geological costs of unproven prospects, including $15.2 million for leaseholds in the Brookeland and Masters Creek areas acquisition;

• $15.0 million, or 8%, spent for the purchase of a 20% interest in two gas processing plants as part of the Brookeland and Masters Creek areas acquisition;

• $12.6 million, or 7%, spent on exploratory drilling;

• $3.9 million, or 2%, invested in foreign business opportunities, consisting of $2.9 million in New Zealand, $0.4 million in Venezuela, and $0.6 million in Russia, as described in Note 8 to the Consolidated Financial Statements;

• $2.2 million, or 1%, spent on field compression facilities; and

• $1.0 million, or 1%, spent on fixed assets.

In 1998, we participated in drilling 61 development wells and 14 exploratory wells, of which 53 development wells and five exploratory wells were successes.

Results of Operations

Revenues. Our revenues in 1999 increased by 34% over revenues in 1998 and by 10% in 1998 over 1997 revenues, principally due to increases in oil and gas sales.

Oil and gas sales revenues in 1999 increased by 36%, or $28.8 million, over those revenues for 1998. In 1998, oil and gas sales revenues increased by 16%, or $11.1 million, over those revenues in 1997. Our net sales volumes in 1999, including the volumetric production payment associated with each year’s production, increased by 10%, or 3.8 Bcfe, over net sales volumes in 1998. In 1998, net sales volumes increased by 54%, or 13.6 Bcfe, over net sales volumes in 1997. Average prices for oil decreased from $17.59 per Bbl in 1997 to $11.86 per Bbl in 1998, and then increased to $16.75 per Bbl in 1999. Average gas prices decreased from $2.68 per Mcf in 1997 to $2.08 per Mcf in 1998, and then increased to $2.40 per Mcf in 1999.

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

• 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; and

• 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.

In 1998, our $11.1 million increase in oil and gas sales resulted from:

• Volume increases that added $38.3 million of sales, with $19.9 million of the increase coming from the 1.1 MMBbl increase in oil sales volumes and $18.4 million of the increase coming from the 6.9 Bcf increase in gas sales volumes; and

• Offsetting price variances that had a $27.2 million unfavorable impact on sales, $16.9 million of which was attributable to the 22% decrease in average gas prices received, and $10.3 million of which was attributable to the 33% decrease in average oil prices received.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four core areas in 1999 and 1998:

Even though we scaled back our 1999 capital expenditures budget from budgeted amounts in prior years, oil and gas sales volumes increased in 1999 when compared to 1998, primarily due to the full year of production from the Brookeland and Masters Creek areas, as the 1998 amounts from these two areas included production only from the second half of 1998. However, due to the decrease in the 1999 capital expenditures budget and the resulting curtailment of drilling, 27 gross wells in 1999 as compared to 75 and 182 gross wells in 1998 and 1997, respectively, the natural production declines in the Giddings and the AWP Olmos areas were not offset by newly developed production. This scaled-back 1999 budget was in response to the low oil and gas prices experienced in 1998 and the first half of 1999. However, due to the improvement in oil and gas prices in the second half of 1999, our 2000 capital expenditures budget has increased to a planned $114.8 million, which should translate into increased sequential quarterly production volumes in 2000 when compared to the fourth quarter of 1999.

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

Revenues from our oil and gas sales comprised 98% of total revenues for 1999, 97% of total revenues for 1998, and 92% of total revenues for 1997. Our acquisition of interests in the second half of 1998 in the Brookeland and Masters Creek areas, which have a higher percentage of production from oil, has decreased the predominance of gas in our production volume mix to 64% in 1999 from 72% in 1998 and 84% in 1997.

Costs and Expenses. Our general and administrative expenses in 1999 increased $0.6 million, or 17%, from the level of such expenses in 1998, while 1998 general and administrative expenses increased $0.3 million, or 9%, over 1997 levels. The variances in these costs over the three-year period reflect the increase in our corporate activities, while our partnership management activities are decreasing. However, our general and administrative expenses per Mcfe produced have decreased from $0.14 per Mcfe in 1997 to $0.10 per Mcfe in both 1998 and 1999. The portion of supervision fees netted from general and administrative expenses were $3.2 million for 1999, $2.7 million for 1998, and $2.6 million for 1997.

Depreciation, depletion, and amortization of our assets, or DD&A, increased $3.0 million, or 8%, in 1999 from 1998, while 1998 DD&A increased $15.1 million, or 62%, over 1997 levels. This was primarily due to additions in our reserves and associated costs and to the related 10% increase in production in 1999 over 1998 and the 54% increase in production in 1998 over 1997. Our DD&A rate per Mcfe of production was $0.99 in 1999, $1.01 in 1998, and $0.95 in 1997, reflecting variations in the per unit cost of reserves additions.

Our production costs in 1999 increased $6.5 million, or 50%, over such expenses in 1998, while those expenses in 1998 increased $4.4 million, or 50%, over 1997 costs. The increases relate to the 10% increase in production volumes in 1999 and the 54% increase in 1998. The higher percentage increase in costs, in relation to the increase in production in 1999, was due to planned increases in remedial well work, increased severance taxes, and increased ad valorem taxes. While the planned remedial well work is expected to increase production on those wells in the future, these costs were expensed as incurred. 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 due to certain wells in the Masters Creek area losing the gas severance tax exemption they received from Louisiana once they had been in production for more than two years or once payout of the well occurs, whichever event occurs first. 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 areas acquisition being subject to ad valorem taxes for the first time at the beginning of 1999. Our production costs per Mcfe produced were $0.46 in 1999, $0.34 in 1998, and $0.35 in 1997. The portion of supervision fees netted from production costs were $3.2 million for 1999, $2.7 million for 1998, and $2.6 million for 1997.

Interest expense on our senior notes due 2009, issued in July 1999, including amortization of debt issuance costs, totaled $5.3 million in 1999. Interest expense on our convertible notes due 2006, including amortization of debt issuance costs, totaled $7.5 million in each of the years 1999, 1998, and 1997. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $6.1 million in 1999, $5.6 million in 1998, and $0.1 million in 1997. In total, 1999’s 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. The 1997 total interest expense was $7.6 million, of which $2.6 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 1999 was attributable 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. The increase in interest expense in 1998 was attributable to the increase in amounts outstanding under our credit facilities.

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 full-cost domestic 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.

At December 31, 1999, our full-cost ceiling cushion was approximately $138.0 million, compared to our full-cost ceiling cushion at December 31, 1998, of approximately $25.0 million.

Net Income. Our net income in 1999 of $19.3 million was 65% higher and Basic earnings per share ("Basic EPS") of $1.07 were 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 primarily reflected the effect of the 10% increase in production volumes and the 41% increase in oil prices and 15% increase in gas prices. Oil and gas prices have risen rapidly since the second quarter of 1999, which is reflected by third- and fourth-quarter net income combining to represent 77% of net income for the year. The lower percentage increase in Basic EPS reflects 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.

Before the non-cash write-down of oil and gas properties in 1998, our net income of $11.7 million was 48% lower and Basic EPS of $0.71 was 47% lower than net income of $22.3 million and Basic EPS of $1.35 in 1997. These decreases primarily reflected the effect of a 33% decrease in oil prices and 22% decrease in gas prices, while costs and expenses increased in general proportion to the 54% increase in production.

Year 2000. The Year 2000 issue arose because many computer programs used only the last two digits to refer to a year. Therefore, those programs could not distinguish between the years 1900 and 2000, potentially causing systems failures, miscalculations, and the disruption of normal business activities. We formed a task force to prepare our business systems for the Year 2000, which included testing our in-house business systems and field operations systems, reviewing Year 2000 compliance certifications and reports issued by third parties, upgrading or replacing noncompliance systems, and preparing a contingency plan for unforeseen difficulties. We implemented this plan before 2000 began.

Our in-house business systems are almost entirely comprised of off-the-shelf software. These systems were either tested, certified as compliant by the licensor of the software, or categorized as not date specific. We upgraded or replaced the software that experienced difficulties addressing the Year 2000.

In our core business function, oil and gas exploration, the systems and equipment are primarily non-information technology systems that are not date specific. Our most reasonably likely worst case scenario would have been a prolonged disruption of external power sources upon which our core field operations equipment relies, resulting in a substantial decrease in our oil and gas production activities. We did not maintain on-site secondary power supplies, such as generators, as it was not economically feasible. A prolonged interruption could have materially affected our operations.

In our business, we also depend on third parties such as pipeline operators who transport natural gas, customers, and suppliers, any one of whom could have been prone to Year 2000 problems that we could not assess or detect. We have experienced no problems with these third parties.

The costs incurred to address the Year 2000 issue did not have a material effect on our results of operations or our liquidity and financial condition. We estimate our total cost to address the Year 2000 issue to have been less than $150,000, most of which was spent during the testing phase on equipment and software upgrades. We used both internal and external resources to complete our Year 2000 program and to perform tasks necessary to address the Year 2000 problem.

As of the filing of this report, we are not aware of any Year 2000 problems experienced either by us or by parties with which we do business, and we do not expect to experience such problems in the future. We will continue to assess any potential problems that might occur.

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, and therefore involve a number of risks and uncertainties. Such forward-looking statements concern, among other things, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves and potential reserves, hydrocarbon prices, liquidity, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "estimate," "expect," "budgeted," "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 and is subject to a number of risks and uncertainties. As a consequence, actual results may differ materially from expectations, estimates, or assumptions expressed in or implied by any forward-looking statements made by or on behalf of us, including those regarding our financial results, levels of oil and gas production or revenues, capital expenditures, and capital resources. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for oil and natural gas internationally or in the United States; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; competition and government regulations; as well as the risks and uncertainties discussed herein, including, without limitation, the portions referenced above and the uncertainties 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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