SWIFT ENERGY COMPANY 2000 ANNUAL REPORT

Form 10-K Excerpts

PART 1

Items 1 and 2. Business and Properties

See pages 55 and 56 for explanations of abbreviations and terms used herein.

General

Swift Energy Company, a Texas corporation formed in October 1979, engages in the development, exploration, acquisition, and operation of oil and gas properties, with a focus on U.S. onshore natural gas reserves located in Texas and Louisiana as well as onshore oil and natural gas reserves in New Zealand. As of December 31, 2000, we had interests in 1,528 wells located domestically in eight states and in federal offshore waters as well as in New Zealand. We operated 817 of these wells representing 91% our proved reserves. At year-end 2000, we had estimated proved reserves of 629.4 Bcfe, of which approximately 67% was natural gas and 45% was proved developed. Our proved reserves are concentrated 54% in Texas, 22% in Louisiana, and 20% in New Zealand.

We currently focus primarily on development and exploration in four domestic core areas as well as New Zealand:

The AWP Olmos area is characterized by long-lived reserves that we expect to be steadily produced over a long period of time. The Brookeland, Giddings, and Masters Creek areas are characterized by shorter-lived reserves with high initial rates of production that decline rapidly. We believe these shorter-lived reserves complement our long-lived reserves in the AWP Olmos area. Based on 2000 year-end domestic proved reserves and 2000 domestic production, our average reserve life was 12.0 years.

We purchased interests in the Brookeland and Masters Creek areas from Sonat Exploration Company in the third quarter of 1998 for approximately $85.8 million in cash. Of this purchase price, $55.5 million was spent for producing properties, $15.0 million for 20% interests in two natural gas processing plants, and $15.3 million for leasehold properties. This acquisition generated two new core areas and extended our holdings in the Austin Chalk formation. Then in late December 1999, we purchased additional working interests in the Masters Creek area from Dominion Reserves, Inc., for approximately $14.0 million and purchased additional working interests in the S. Burr Ferry portion of the Masters Creek area for approximately $1.9 million from Union Pacific. We expect to use our operating expertise in this geological trend to continue to successfully develop and exploit these properties.

In addition to our continuing production, development, and exploration in the AWP Olmos, Brookeland, Giddings, and Masters Creek areas, we are currently pursuing development and exploration activities in the Gulf Coast Basin and in New Zealand.

Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. In addition, we seek to enhance the results of our drilling and production efforts through the implementation of advanced technologies. During 1998, as a result of lower oil and gas prices, we reduced capital expenditures for drilling and redirected a portion of those expenditures to the acquisition of producing properties, primarily the Brookeland and Masters Creek areas. In 1998, development and exploration drilling expenditures for the year, concentrated in the first half of the year, totaled $67.4 million. We spent $59.5 million for the acquisition of producing properties in 1998, almost all in the third quarter of 1998. For 1999, again in response to lower oil and gas prices in 1998 that continued in the first half of 1999, we decreased our capital expenditures budget to $54.2 million, of which $36.0 million was targeted for drilling, $31.3 million for development drilling, and $4.7 million for exploratory drilling. The remaining $18.2 million was targeted principally for leasehold, seismic, and geological costs of prospects. After oil and gas prices rebounded in the second half of the year, we increased our capital expenditures during the fourth quarter. We funded the $78.1 million of capital expenditures spent in 1999 primarily through our internally generated cash flows of $73.6 million, while the remainder was funded with net proceeds from our third quarter 1999 public offering of common stock and Senior Notes that remained after paying off our bank debt.

For 2000, in response to the strengthening of oil and gas prices and the resulting increase in cash flows generated from these commodity prices, we increased our capital expenditures to $173.3 million, of which $105.8 million was targeted for drilling in the United States, with $90.3 million for development drilling, and $15.5 million for exploratory drilling. We spent $9.7 million in drilling to further delineate our Rimu discovery in New Zealand. Additionally, $33.4 million was spent for producing property acquisitions. The remaining $24.4 million was used principally for leasehold, seismic, and geological costs of prospects. We funded the $173.3 million of capital expenditures in 2000 primarily through our internally generated cash flows of $128.2 million, while the remainder was funded with net proceeds from our third quarter 1999 public offering of common stock and Senior Notes that remained after paying off our bank debt and funding capital expenditures in 1999.

We have increased our proved reserves from 176.1 Bcfe at year-end 1995 to 629.4 Bcfe at year-end 2000, which has resulted in the replacement of 375% of our production during the same five-year period. In 2000, we increased our proved reserves by 38%, which replaced 517% of our 2000 production. Our five-year average reserves replacement costs were $0.94 per Mcfe. While 2000 production was relatively flat in relation to 1999 production, we have increased our production from 11.2 Bcfe at year-end 1995 to 42.4 Bcfe at year-end 2000. Primarily due to increased production, along with strong 2000 commodity prices, this has resulted in average annual growth in net cash provided by operating activities of 55% per year from year-end 1995 to year-end 2000.

Properties

AWP Olmos Area. As of December 31, 2000, we owned approximately 31,162 net acres in South Texas. We have extensive expertise in this area and a long history of experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 92% gas. At year-end 2000, we owned interests in and were the operator of 483 wells in this area producing gas from the Olmos Sand formation at a depth of approximately 10,000 to 11,500 feet. We own nearly 100% of the working interests in all wells in which we have an interest there.

In 2000, we drilled 27 development wells in the AWP Olmos area, 25 of which were successful. At year-end 2000, we had 160 proved undeveloped locations. Also in 2000, we purchased interests in the AWP Olmos area from partnerships we manage. Our planned 2001 capital expenditures of $13.2 million in this area will focus on drilling 12 wells and on wells currently on production, performing fracture extensions and installing coiled tubing velocity strings.

Brookeland Area. As of December 31, 2000, we owned drilling and production rights in 130,180 gross acres, 82,080 net acres, and 15,000 fee mineral acres containing substantial proved undeveloped reserves. This area was part of the acquisition from Sonat in 1998. The Brookeland area is located in southeast Texas near the border of Louisiana in Jasper and Newton counties. This area primarily contains horizontal wells producing gas from the Austin Chalk formation. The reserves are approximately 65% gas. In 2000, we drilled or participated in the drilling of five development wells there, all of which were successful. At year-end 2000, we had 25 proved undeveloped locations. We plan to drill or participate in 17 development wells in 2001, 10 to be operated by us. Our planned 2001 capital expenditures in this area are $21.8 million.

Giddings Area. As of December 31, 2000, we owned drilling and production rights in 67,595 net acres in the Giddings area. This area is located in Washington, Colorado, Fayette, and Austin counties in southeast Texas. The reserves are approximately 84% gas. In 2000, seven development wells were drilled, four successfully. One of the seven development wells drilled was to the Edwards formation and was unsuccessful, while the other six drilled were to the Austin Chalk formation. Also four exploratory wells were drilled, with one success. One of the four exploratory wells drilled was to the Edwards formation and was unsuccessful, while the other three drilled were to the Austin Chalk formation. At year-end 2000, we had two proved undeveloped locations. No drilling in this area is planned for 2001.

Masters Creek Area. As of December 31, 2000, we owned drilling and production rights in 182,356 gross acres, 137,188 net acres, and 141,000 fee mineral acres in this area containing substantial proved undeveloped reserves. This area was also part of the acquisition from Sonat in 1998. It is located near the Texas-Louisiana border in the two parishes of Vernon and Rapides in Louisiana. The Masters Creek area contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 40% gas. In 2000, we drilled or participated in the drilling of 12 development wells, 11 of which were successful. Also two successful exploratory wells were drilled, both targeting the Saratoga formation. At year-end 2000, we had 27 proved undeveloped locations. We plan to drill or participate in 10 development wells in 2001, all to be operated by us. Three of these development wells are in the S. Burr Ferry portion of this area. One development well will target the Saratoga formation. The other six are in the Masters Creek field targeting the Austin Chalk formation. Our planned 2001 capital expenditures in this area are $39.3 million.

Exploration and Development Drilling Activities

We pursue a "controlled risk" approach to exploratory and development drilling, focusing our domestic activities on specific regions in which our technical staff has considerable experience and which are located close to known producing horizons. In our foreign operations, we chose New Zealand based on its hydrocarbon potential combined with its political and economic attributes. We seek to minimize our exploration risk by investing in multiple prospects, farming out interests to third parties, using advanced technologies, and drilling in diverse types of geological formations, often in areas with multiple objectives. We use basin studies to analyze targeted formations based on their potential size, risk profile, and economic characteristics.

In 1991, we began an intensive effort to develop an inventory of exploration and development drilling prospects, identifying drilling locations through integrated geological and geophysical studies of our undeveloped acreage and other prospects. As a result, we added 73.9 Bcfe of proved reserves through drilling in 1998, 64.9 Bcfe in 1999, and 184.7 Bcfe in 2000 (122.5 Bcfe from New Zealand). In the second half of 1998, in response to lower oil and gas prices, we deferred drilling projects scheduled for the second half of the year and continued into 1999 with a conservative drilling budget. Accordingly, reserves added by drilling were lower in 1998 and 1999 compared to previous years and to 2000, when market conditions were more favorable for drilling. The 2000 additions were a result of our development success rate of 89%, as 54 of 61 development wells drilled were successful, and of five of nine exploratory wells being successful.

Our development strategy is designed to maximize the value and productivity of our existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying our technical expertise and resources to exploit producing properties efficiently. We utilize various recovery techniques, which include employing water flooding and acid treatments, fracturing reservoir rock through the injection of high-pressure fluid, and inserting coiled tubing velocity strings to enhance and maintain gas flow. We believe that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area.

Our exploration and development activities are conducted by our staff of professionals, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and production engineers. We believe that one of the keys to our success has been our team approach, which integrates multiple disciplines to maximize efficient utilization of information leading to drillable projects.

We have increasingly used advanced seismic technology to enhance the results of our drilling and production efforts, including 2-D and 3-D seismic analysis, amplitude versus offset studies, and detailed formation depletion studies. We have a number of computer workstations from which seismic data is analyzed and enhanced with advanced software programs, including Landmark, Geographix, and SMT workstations. As a result, we have maintained internal seismic expertise and have compiled an extensive database.

During 1997, we completed our first international seismic acquisition program in two key areas of our block in New Zealand. In the Rimu prospect, we acquired 30 kilometers (18.7 miles) of 2-D cross-swath data, as well as 14.5 kilometers (9 miles) of 2-D line data in the Tawa prospect, complementing existing 2-D seismic coverage. Following our 1999 Rimu discovery, we conducted a second seismic acquisition in March 2000 in which we obtained 42 kilometers (26 miles) of 2-D lines to more fully identify the extent of the Rimu structure. We also obtained approximately 72.5 kilometers (45 miles) of data from a number of 2-D transitional zone seismic lines tied to existing marine and land seismic grids in order to study the Kauri structure to the southeast of Rimu. Based on interpretation of these data, a location has been selected to drill the first well on the Kauri prospect in 2001. Further processing and analysis of the data will continue in 2001.

Also in 1997, we acquired 21 miles of 2-D data in the AWP Olmos area in south Texas and 51 miles of data in the Fayette County portion of the Giddings area. Two more prospects in the North Louisiana Salt Basin were shot in the form of 2-D swaths of approximately 16 miles each. During 1998, we performed two additional 2-D acquisitions in Fayette County, Texas. In all our current and future projects, we have an on-going program in which we license existing seismic data for reprocessing with available new technologies. In certain areas we also complement existing data with proprietary seismic data designed for specific geologic targets. This results in an integrated approach to exploration (multidiscipline data analysis and interpretation) that has helped identify a number of exploration prospects for 2001.

In addition to development and exploration activities in the AWP Olmos, Brookeland, and Masters Creek areas, we are currently pursuing development and exploration activities in the Gulf Coast Basin and in New Zealand.

Gulf Coast Basin. This area includes all the Texas counties and Louisiana parishes along the Gulf Coast and extending into Mississippi and Alabama. In 2000, we drilled four successful development wells out of five and two successful exploratory wells out of three in this area. In 2001, 10 exploratory wells are scheduled for drilling in the Gulf Coast Basin, primarily in Texas. Our planned 2001 capital expenditures in this area are $11.9 million.

New Zealand. We operate a permit with a 90% working interest. After working several years and analyzing extensive seismic data, a successful exploratory well, the Rimu-A1, commenced drilling in July 1999. In 2000, we drilled two successful Rimu development wells with a third in progress. Our permit contains 100,652 gross acres, including 12,800 adjacent offshore acres. In 2001, four wells are scheduled for drilling, with one well being an exploratory test of the Kauri prospect. Plans also include the building of production facilities. We are also participating as a non-operator in three other exploration permits which at year-end 2000 contained 143,773 gross acres. An exploratory well on one of these permits was temporarily abandoned in January 2001, pending further evaluation.

The following table sets forth the results of our drilling activities during the three years ended December 31, 2000:

Operations

We generally seek to be operator in the wells in which we have significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide all the equipment and personnel. We employ drilling, production and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties.

Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator’s direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or gas. The fees for these activities paid to us in 2000 ranged from $200 to $2,091 per well per month and totaled $6.9 million.

Marketing of Production

We typically sell our oil and gas production at market prices near the wellhead, although in some cases it must be gathered and delivered to a central point. Gas production is sold in the spot market on a monthly basis, while we sell our oil production at prevailing market prices. We do not refine any oil we produce. Two oil or gas purchasers accounted for 10% or more of our total revenues during the year ended December 31, 2000, with those purchasers accounting for approximately 37% of revenues in the aggregate. For the year ended December 31, 1999, one purchaser accounted for approximately 19% of our total revenues. However, due to the availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues.

In 1998, we entered into gas processing and gas transportation agreements for our gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one-year extensions unless earlier terminated. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future. Additionally, the gas processed and transported under these agreements may be sold to El Paso based upon current natural gas prices.

Much of our Giddings area production from Fayette and Washington counties, Texas, is currently dedicated under long-term gas purchase and gas processing contracts with Aquila Southwest Pipeline Corporation ("Aquila"). We believe that these contracts adequately provide for the gas purchase and processing needs of our Giddings area production, subject to practical limitations inherent in gas field operations. The prices received are redetermined monthly to reflect the current natural gas price.

Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our gas production from these areas is processed under long-term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market.

The following table summarizes sales volumes, sales prices, and production cost information for our net oil and gas production for the three-year period ended December 31, 2000. All of our oil and gas operations are domestic. New Zealand operations are expected to commence in 2001. "Net" production is production that is owned by us either directly or indirectly through partnerships or joint venture interests and is produced to our interest after deducting royalty, limited partner, and other similar interests.

¹Natural gas production for 2000, 1999, and 1998 includes 405,130, 728,235 and 866,232 Mcf, respectively, delivered under the volumetric production payment agreement pursuant to which we were obligated to deliver certain monthly quantities of natural gas (see Note 1 to the Consolidated Financial Statements).

Under the volumetric production payment entered into in 1992, we delivered the last remaining commitment of gas in October 2000, when such agreement expired.

Acquisition Activities

We use a disciplined, market-driven approach to acquisitions. Generally we seek to acquire properties with the potential for additional reserves and production through development and exploration efforts. In 140 transactions since 1979, we have acquired approximately $590.2 million of producing oil and gas properties on behalf of ourselves and our co-investors. We acquired, for our own account, approximately $233.7 million of producing properties, with original proved reserves estimated at 339.7 Bcfe. Our producing property acquisition expenditures in the past three years were $34.2 million in 2000, $18.5 million in 1999, and $59.5 million in 1998. Our acquisition costs have averaged $0.71 per Mcfe over this three-year period. Our acquisition cost in 2000 averaged $0.86 per Mcfe.

Foreign Activities

New Zealand

Swift Operated Permit. Our activity in New Zealand began in 1995 with the issuance of the first of two petroleum exploration permits. After a 1998 surrendering of a portion of our permit acreage, a combining of the two permits, and a 1999 expansion of the permit, as of year-end 2000 our permit 38719 covers approximately 100,700 acres in the Taranaki Basin of New Zealand’s North Island, with all but 12,800 acres onshore. We have a 90% working interest in this permit and have fulfilled all current obligations under this permit.

In late 1999, we completed our first exploratory well on this permit, the Rimu-A1, and a production test was performed. During the second half of 2000, we drilled and successfully tested two delineation wells, the Rimu-B1 and the Rimu-B2. We commenced drilling our third delineation well, the Rimu-A2, during December 2000. The Rimu-A2 has been drilled with casing set. Logging results indicate that the well encountered the Upper Tariki sands also present in the Rimu-A1. Completion activity will take place on this zone following the drilling of the Rimu-A3. Our portion of the drilling, completion, and testing costs incurred on the wells within our permit area during 2000 was approximately $10.7 million. Our portion of prospect costs on our permit area during 2000 was approximately $4.4 million, which included obtaining 2-D seismic data in the first half of the year. We incurred $1.1 million on the initial phases of production facilities. In 2001, we plan to drill four wells, one exploratory well on our Kauri prospect to the southeast of the Rimu discovery and three wells to further delineate the Rimu area, and to build production facilities with $35.9 million budgeted to be spent, compared to $17.4 million spent in 2000 and $7.0 million spent in 1999.

Our New Zealand production is subject to a royalty which is a hybrid consisting of a 5% ad valorem royalty, or "AVR," and a 20% accounting profits royalty, or "APR." Until a mining permit is obtained for our producing area, only the AVR will apply to all production, and thereafter the royalty will be the greater of the AVR or APR, calculated on an annual basis. The AVR is based on net sales revenues. The APR is based on the excess of net sales revenues over allowable deductions which deductions include production, capital and indirect costs, but not for interest or income tax expense or "head office costs" above 2.5% of other costs. Operating losses and capital costs may be carried forward to subsequent periods until fully utilized.

Non-Operated Permits. In 1998, we entered into agreements for a 25% working interest in an exploration permit held by Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5% working interest held by Antrim Oil and Gas Limited, a Canadian company in a permit operated by Marabella. In turn, Bligh and Antrim each became 5% working interest owners in our permit. Unsuccessful exploratory wells were drilled on these two permits, and we charged $400,000 against earnings in 1998 and $290,000 in 1999. All of the acreage on the permit we had a 25% working interest in was surrendered in 2000. The exploratory well on the 7.5% working interest permit has been temporarily abandoned pending a further evaluation.

In 2000, we entered into agreements with Fletcher Challenge Energy Limited whereby we will earn a 20% participating interest in petroleum exploration permit 38718 containing approximately 57,400 acres and a 25% participating interest in permit 38730 with approximately 48,900 acres. In January 2001, the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718 pending further analysis. The permit now contains approximately 28,700 acres after a scheduled surrender during December 2000.

Costs Incurred. During 2000 our portion of all costs incurred in New Zealand totaled $17.4 million, including $11.8 million for drilling, $4.5 million for prospect costs, and $1.1 million for production facilities. These costs included $1.2 million of costs incurred on permits operated by others: $1.1 million of drilling costs and $0.1 million of prospect costs. As of December 31, 2000, our investment in New Zealand totaled approximately $29.8 million. At year-end we recorded proved undeveloped reserves relating to our successful drilling activities. Accordingly, $21.1 million of our investment costs have been included in the proved properties portion of oil and gas properties and $8.7 million is included as unproved properties. The development strategy includes marketing oil and gas, with the intent of having production on line for oil and gas sales in New Zealand in 2001.

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, prior to its impairment in the third quarter of 1998, was approximately $10.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. We retain a minimum 6% net profits interest from the sale of hydrocarbon products from the fields, the value of which depends upon the successful development of production from the fields by others, which may or may not occur.

Venezuela

In 1993, we formed a wholly owned subsidiary, Swift Energy de Venezuela, C. A., for the purpose of submitting a bid under the Venezuelan Marginal Oil Field Reactivation Program and entered into an agreement with two Venezuelan companies to jointly formulate and submit a proposal to Petroleos de Venezuela, S. A., for the construction and operation of a methane pipeline. Our investment in Venezuela, prior to its impairment in the third quarter of 1998, was approximately $2.8 million. See Note 1 to the Consolidated Financial Statements for a more detailed discussion of the impairment. 

Oil and Gas Reserves

The following table presents information regarding proved reserves of oil and gas attributable to our interests in producing properties as of December 31, 2000, 1999, and 1998. The information set forth in the table regarding Domestic Reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy’s domestic audit was based upon review of production histories and other geological, economic, ownership, and engineering data provided by us. The information set forth in the table regarding New Zealand reserves is based on gross proved reserves reports independently estimated by Gruy. Gruy’s New Zealand estimates were based on volumetric calculations, equation-of-state compositional simulation models, and production forecasting methods. The net reserves and cash flows for New Zealand were prepared by us.

In accordance with Securities and Exchange Commission guidelines, estimates of future net revenues from our proved reserves and the PV-10 Value must be made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. Proved reserves as of December 31, 2000, were estimated based upon prices in effect at year-end. The weighted averages of such year-end prices domestically were $11.25 per Mcf of natural gas and $25.50 per barrel of oil, compared to $2.58 and $23.69 in 1999 and $2.23 and $11.23 in 1998. The weighted averages of such year-end 2000 prices for New Zealand were $0.71 per Mcf of natural gas and $22.30 per barrel of oil. The weighted averages of such year-end 2000 prices for all our reserves, both domestically and in New Zealand, were $9.86 per Mcf of natural gas and $24.62 per barrel of oil. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following table. The proved reserves presented for all periods also exclude any reserves attributable to the volumetric production payment.

The table sets forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the Securities and Exchange Commission and their PV-10 Value. Operating costs, development costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in Supplemental Information to our Consolidated Financial Statements, which is calculated after provision for future income taxes.

At year-end 2000, 55% of the proved reserves were undeveloped reserves. This reflects the increased emphasis on development and exploration activities. In 1999, 51% of proved reserves were undeveloped and 49% were proved developed.

Changes in quantity estimates and the estimated present value of proved reserves are affected by the change in crude oil and natural gas prices at the end of each year. While our total proved reserves quantities, on an equivalent Bcfe basis, at year-end 2000 increased by 38% over reserves quantities a year earlier, the PV-10 Value of those reserves increased 310% from the PV-10 Value at year-end 1999. Our total proved reserves quantities at year-end 1999 increased by 4% over reserves quantities a year earlier, while the PV-10 Value of those reserves increased 66% from the PV-10 Value at year-end 1998. These PV-10 Value increases were heavily influenced by pricing increases at year-end 2000 as compared to year-end 1999, and also from year-end 1999 as compared to year-end 1998. Product prices for natural gas increased 282% during 2000, from $2.58 per Mcf at December 31, 1999, to $9.86 per Mcf at year-end 2000, while oil prices increased 4% between the two dates, from $23.69 to $24.62 per barrel. Product prices for natural gas increased 16% during 1999, from $2.23 per Mcf at December 31, 1998, to $2.58 per Mcf at year-end 1999, while oil prices increased 111% between the two dates, from $11.23 to $23.69 per barrel. Conversely, while our total proved reserves quantities at year-end 1998 increased by 21% over reserves quantities a year earlier, the PV-10 Value of those reserves decreased 3% from the PV-10 Value at year-end 1997. This decrease was due almost entirely to pricing declines at year-end 1998 as compared to year-end 1997, which more than offset the 21% Bcfe increase in reserves quantities. Product prices for natural gas declined 20% during 1998, from $2.78 per Mcf at December 31, 1997, to $2.23 per Mcf at year-end 1998, matched by a 29% decrease in the price of oil between the two dates, from $15.76 to $11.23 per barrel.

Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves.

A portion of our proved reserves has been accumulated through our interests in the limited partnerships for which we serve as general partner. The estimates of future net cash flows and their present values, based on period end prices, assume that some of the limited partnerships in which we own interests will achieve payout status in the future. At December 31, 2000, 27 of the limited partnerships managed by us had achieved payout status.

No other reports on our reserves have been filed with any federal agency.

Oil and Gas Wells

The following table sets forth the gross and net wells in which we owned an interest at the following dates:

¹Excludes 25 service wells in 2000, 33 service wells in 1999, and 36 service wells in 1998. Also excludes 3 wells in New Zealand, temporarily shut-in awaiting marketing and processing arrangements.

Oil and Gas Acreage

As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so.

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2000:

¹Fee minerals acquired in the Brookeland and Master Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 114,655 undeveloped fee mineral acres for a total of 141,000 fee mineral acres.

Partnerships

Prior to 1995, we funded a substantial portion of our operations through 109 limited partnerships which we formed and for which we have served as managing general partner. These partnerships raised a total of $509.5 million of capital, with the largest portion (81%) raised to acquire interests in producing properties. Eight of the earliest partnerships and 13 of the most recently formed partnerships were created to drill for oil and gas. In all of these partnerships Swift paid for varying percentages of the capital or front-end costs and continuing costs of the partnerships and, in return, received differing percentage ownership interests in the partnerships, along with reimbursement of costs and/or payment of certain fees. At year-end 2000, we continued to serve as managing general partner of 80 of these various partnerships, of which 67 are production purchase partnerships that have been in existence from five to fourteen years and the remainder are drilling partnerships that have been in existence from two to seven years.

During 1997 and 1998, eight drilling partnerships formed between 1979 and 1985 and 21 of the production purchase partnerships sold their properties and were dissolved, in each case following a vote of the investors in the particular partnerships approving such liquidations. Between 1999 and 2001, the investors in all but six of the remaining partnerships voted to sell the properties or their interests in the partnership and dissolve. We anticipate that the liquidation and dissolution of these 74 partnerships should be substantially completed by the end of 2001. The remaining six partnerships will continue to operate.

Risk Management

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, oil spills, and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, we are solely responsible for the day-to-day conduct of the limited partnerships’ affairs and accordingly have liability for expenses and liabilities of the limited partnerships. We maintain comprehensive insurance coverage, including general liability insurance in an amount not less than $35.0 million, as well as general partner liability insurance. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.

Employees

At December 31, 2000, we employed 181 persons. None of our employees are represented by a union. Relations with employees are considered to be good.

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Glossary of Abbreviations and Terms

The following abbreviations and terms have the indicated meanings when used in this report:

Bbl — Barrel or barrels of oil.

Bcf — Billion cubic feet of natural gas.

Bcfe — Billion cubic feet of natural gas equivalent (see Mcfe).

Development Well — A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

Discovery Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.

Dry Well — An exploratory or development well that is not a producing well.

Exploratory Well — A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir.

Gross Acre — An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

Gross Well — A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

MBbl — Thousand barrels of oil.

Mcf — Thousand cubic feet of natural gas.

Mcfe — Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.

MMBbl — Million barrels of oil.

MMBtu — Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.

MMcf — Million cubic feet of natural gas.

MMcfe — Million cubic feet of natural gas equivalent (see Mcfe).

Net Acre — A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Net Well — A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Producing Well — An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved Developed Oil and Gas Reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Oil and Gas Reserves — The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made.

Proved Undeveloped Oil and Gas Reserves — Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved Undeveloped (PUD) Locations — A location containing proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10 Value — The estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.

Reserves Replacement Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period.

Volumetric Production Payment — The 1992 agreement pursuant to which we financed the purchase of certain oil and natural gas interests and committed to deliver certain monthly quantities of natural gas.

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Those portions of the Form 10-K Report for the year ended December 31, 2000, not included in this Annual Report to Shareholders (including certain portions of Item 1–Business pertaining to "Competition" and "Regulations," Item 3–Legal Proceedings, Item 4–Submission of Matters to a Vote of Security Holders, Item 9–Changes in and Disagreements with Accountants on Accounting and Financial Disclosure, and Item 14–Exhibits, Financial Statement Schedules, and Reports on Form 8-K), with no disclosures having been made as to Items 4 and 9, will be provided without charge to shareholders making a written request to Bruce H. Vincent, Executive Vice President, Swift Energy Company, 16825 Northchase Drive, Suite 400, Houston, Texas 77060-6098. Exhibits filed as part of the Form 10-K will be provided to shareholders making a written request as set forth above at a reasonable charge sufficient to cover the Company’s cost in providing such exhibits.

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