RESERVES GROWTH THROUGH  ADVANCED TECHNOLOGIES
	1995 ANNUAL REPORT
Form 10-K Excerpts

PART 1

Items 1 and 2. Business and Properties

 

See page 47 for explanations of abbreviations and terms used herein.

General

Swift Energy Company (the "Company"), a Texas corporation organized in October 1979, is engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a primary focus on U.S. onshore natural gas reserves. The Company has interests in approximately 4,100 oil and gas wells located in 15 states, with over 90% of its proved reserves base concentrated in Texas, Oklahoma, and Louisiana. Between 1985 and 1993, the Company grew primarily through the acquisition of producing properties funded through limited partnership financing. Commencing in 1991, the Company began to re-emphasize the addition of reserves through increased exploration and development drilling activity. As a result of this re-emphasis on drilling activity, the Company added approximately 24.8 Bcfe and 72.4 Bcfe of proved reserves in 1994 and 1995, respectively, through exploration and development drilling at a three-year average discovery cost of $0.70 per Mcfe in 1994 and $0.47 in 1995.

At December 31, 1995, the Company had estimated proved reserves of 143.6 Bcf of natural gas and 5.4 MMBbls of oil (totaling approximately 176.1 Bcfe) with a present value (PV-10 Value) of approximately $147 million. The proved reserves at December 31, 1995, represent an increase of 70% over estimated amounts at December 31, 1994. Approximately 82% of the Company's proved reserve base at year-end 1995 was natural gas. The Company's reserve replacement cost over the last three years averaged $0.61 per Mcfe.

At December 31, 1995, the Company operated approximately 770 wells, which represented 86% of its proved reserve base, and managed reserves on behalf of limited partnerships that, exclusive of the Company's interests, had proved reserves of approximately 180.5 Bcfe. The Company's two largest properties accounted for 73% of the Company's PV-10 Value at December 31, 1995. The South Texas AWP Olmos Field, located in McMullen County, Texas, and the Austin Chalk Giddings Field, located primarily in Fayette County, Texas, accounted for 67% and 6%, respectively, of the Company's PV-10 Value as of such date. The Company believes that the Austin Chalk's prolific but short-lived wells complement the long-lived reserves of the AWP Olmos Field. The application of advanced technologies and achievement of operating efficiencies have enabled the Company to reduce costs and enhance reserves recoveries in these areas.

Exploration and Development Drilling Activities

In 1991, the Company began to increase its inventory of exploration and development drilling prospects. Drilling locations were selected through intensive geological and geophysical studies of the Company's undeveloped acreage and other prospects. The Company has recently begun to realize benefits from its drilling program, with proved reserves added through exploration and development drilling of approximately 13 times the amount added through the acquisition of producing properties in 1995, and approximately seven times that year's annual production. The Company's success rate for 1995 drilling activity was 50% for exploratory wells (4 out of 8 drilled) and 96% for development wells (65 out of 68 drilled).

The Company pursues a "controlled risk" approach to exploratory drilling. The Company focuses its exploration activities on specific U.S. regions where its technical staff has considerable experience and near proved productive properties where the potential for significant reserves exists. The Company seeks to minimize its exploration risk by investing in multiple prospects, farming out interests to industry partners and drilling funds, utilizing advanced technologies, and drilling in different types of geological formations.

The Company's development strategy is designed to maximize the value and productivity of its existing properties through development drilling and recovery methods, enhancing production results through improved field production techniques, lowering production costs, and applying the Company's technical expertise and resources to exploit producing properties efficiently. The Company employs various recovery techniques, which include water flooding, fracturing reservoir rock through the injection of high-pressure fluid, inserting coiled tubing velocity strings to speed gas flow, and acid treatments. The Company believes that the application of fracturing technology and coiled tubing has resulted in significant increases in production and decreases in drilling and operating costs in several of its fields, including the Company's largest single property, the AWP Olmos Field.

The Company's exploration and development activities are conducted by its in-house exploration staff, assisted by professionals from other departments, including reservoir engineers, geologists, geophysicists, petrophysicists, landmen, and drilling and operations engineers. The Company believes that one of the keys to its success has been its team approach, which integrates multiple disciplines to maximize utilization of the information provided by modern seismic techniques.

The Company has increasingly utilized advanced seismic technology to enhance the quality of its drilling efforts, including two-dimensional (2-D) and three-dimensional (3-D) seismic analysis, amplitude versus offset (AVO) studies, and detailed formation simulation studies. Utilizing the Company's computer workstations, seismic data are analyzed and enhanced with advanced software programs, many of which are proprietary. As a result, the Company has developed a significant internal seismic expertise and has compiled an extensive library of seismic data.

The following table sets forth the results of the Company's drilling activities during the three fiscal years ended December 31, 1995:

(1)An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A developmental well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

(2)Many of the development wells were drilled by Company-managed partnerships or joint ventures that own only a portion of the working interest in each development well. The Company's share of the fractional interest in these development wells exists primarily to the extent of its partnership interest.

(3)A producing well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

(4)A dry well is an exploratory or development well that is not a producing well.

At December 31, 1995, the Company had an inventory of development drilling prospects in two main fields and exploration prospects in four main geological basins:

South Texas AWP Olmos Field. The Company has extensive expertise in the AWP Olmos Field, where it drilled nine successful development wells on its original AWP leaseholds in 1995. The Company has a long history of experience with low-permeability tight-sand formations typical of its AWP Olmos Field properties. Since acquiring its first AWP Olmos Field acreage in 1988, the Company has made detailed studies of drainage patterns in the formation and has introduced innovations in fracture design and implementation methods and coiled tubing technology that substantially reduce drilling costs and improve recoveries.

In the fourth quarter of 1994, the Company acquired a leasehold position in 8,830 net acres in Two Rivers, immediately adjacent to its AWP leasehold acquired in 1988. The Company subsequently extended its geological and engineering studies to cover this acreage, and in 1995 drilled and completed 30 new wells. In 1995, the Company acquired an additional leasehold position in 400 net acres (Encino Ranch) and in 1995 drilled two successful new wells on this acreage. As a result of these efforts, Swift has identified numerous proved undeveloped locations in the AWP Olmos Field, where it currently plans to drill up to 76 development wells in 1996.

Austin Chalk Giddings Field. Wells in this area initially have high deliverability rates, with strong cash flows that decline rapidly. The Company believes these reserves complement its long-lived reserves in the AWP Olmos Field. As of year-end 1995, the Company had participated in 24 horizontal wells in the Giddings Field with a 96% success rate, including nine successful development wells in 1995. The Company believes its success is attributable to its ability to identify hydrocarbon-bearing fractures, relying on its expertise in seismic data analysis and its ability to drill and operate horizontal wells. In 1994, the Company acquired a 2-D swath of seismic data covering approximately 6,500 acres. In addition, the Company acquired undeveloped leasehold interests to provide additional flexibility in designing its development program. The Company currently plans to conduct a second 2-D swath seismic survey in the area, and to drill an additional eight development wells in the Austin Chalk in 1996.

Gulf Coast Basin. The Company's drilling program in the Gulf Coast Basin in 1995 consisted of one successful exploratory well and four successful development wells. The locations were selected utilizing traditional geologic studies combined with analyses of available seismic data. To reduce its exploration and development risk in the Gulf Coast Basin, the Company conducted a 3-D seismic survey in Jackson County, Texas, in 1994. The processing and interpretation has identified a number of potential drilling locations which have been further refined through AVO analysis. The Company owns interests in the South Louisiana East Mud Lake and Second Bayou fields with significant proved undeveloped reserves. Up to four exploratory wells and three development wells are scheduled for drilling in the Gulf Coast Basin through 1996, principally focusing on the Yegua, Frio, and Wilcox trends.

Anadarko Basin. The Company plans to continue exploration and development activities in the Anadarko Basin in Oklahoma, principally focusing on the Red Fork and Skinner formations. The Company participated in five successful development wells in this area in 1995. The Company's geologists and geophysicists search for the Red Fork formation's narrow channel sands using interactive software to integrate geologic and seismic data. By correlating the two sets of information, the presence of potential hydrocarbon accumulations is determined and optimum drilling sites are selected. For 1996, the Company plans to drill one exploratory well in this area.

Wyoming Powder River Basin. In 1995, the Company drilled two successful exploratory wells and three successful development wells in the Minnelusa trend in Campbell County, Wyoming. The Minnelusa trend has been the subject of extensive study by the Company's multidisciplinary teams in order to identify the location of stratigraphic hydrocarbon traps. The Company's staff has evaluated over 5,000 wells drilled in the area, utilizing 2-D and 3-D seismic data, and has conducted petrophysical studies to determine the hydrocarbon-bearing capacity of the rock. To increase the production in some areas, the Company has instituted secondary and tertiary recovery through water or polymer flooding in the Minnelusa fields. The Company intends to drill four exploratory and two development wells in this area in 1996.

North Louisiana Salt Dome. The North Louisiana Salt Dome covers the neighboring corners of Arkansas, Louisiana, and Texas. The Company has drilled two successful exploratory wells in the area during 1993 and 1994 and another successful exploratory well in 1995. In this area, the Smackover formation is a prolific hydrocarbon producer from multiple levels and from a variety of structures, including fault traps, salt anticlines, basement structures, and stratigraphic traps. The Company currently has access to a 7,000-mile seismic data base in the area and completed a 3-D seismic survey in the Smackover formation in early 1996. The Company plans to drill seven exploratory wells and two development wells in the region in 1996 and is currently evaluating the implementation of a water flood project in Arkansas.

Acquisition Activities

Since 1979, the Company has acquired approximately $465.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 122 separate transactions. The Company has acquired for its own account approximately $111.6 million of producing properties, with original proved reserves estimated at 145.2 Bcfe. The Company's acquisition activities have declined over the past three years, with approximately $21.8 million, $13.1 million and $3.5 million of properties acquired in 1993, 1994, and 1995, respectively. The Company's acquisition costs have averaged $0.78 per Mcfe over this three-year period. For 1996 for its own account, the Company anticipates spending only $0.5 million to purchase limited partner interests from existing limited partnerships through the right of presentment arrangement provided in those partnerships.

The Company uses a disciplined, market-driven approach to acquisitions. The Company generally seeks acquisition of properties for its own account that are in close proximity to its current reserves and provide the potential to add reserves through additional development efforts. As the market for acquisitions has become more competitive in recent years, the Company has taken the initiative in creating acquisition opportunities by directly soliciting property owners who have not placed their properties on the market. Properties are acquired after the Company has analyzed and evaluated available reservoir engineering, geological, and geophysical data. In evaluating producing properties prior to purchase, the Company assesses many factors, including estimated reserves, anticipated cash flow from production, production costs, and various factors affecting the marketing of production.

Properties

The South Texas AWP Olmos Field and the Austin Chalk Giddings Field accounted for a significant portion of the Company's proved oil and gas reserves as of December 31, 1995.

South Texas AWP Olmos Field. Swift's AWP leaseholds and its Two Rivers and Encino Ranch leaseholds are contained entirely within the AWP Olmos Field in McMullen County, Texas, and represented approximately 67% of the Company's proved reserves at December 31, 1995. Interests are owned in 123 wells producing from the Olmos Sand Formation at a depth of 10,000 feet, and the Company is the operator of all 123 wells. Working interests owned by the Company and its partnerships in this field range from 97% to 100%. During 1995, the Company drilled 41 successful development wells in this field. During the period it has operated wells in this field, the Company has engaged in extensive fracturing operations to enhance the permeability of the formation and flow of gas from the wells. The introduction of coiled tubing velocity strings in several wells speeds the velocity of gas flow, preventing produced liquids from condensing, falling back into the well and blocking gas flow. The Company has a substantial amount of undeveloped proved reserves in this area with plans to drill 76 more development wells in 1996.

Austin Chalk Giddings Field. This property, located primarily in Fayette County, Texas, and other adjacent counties, represents approximately 6% of Swift's proved reserves. As of year-end 1995, Swift had participated in 24 horizontal wells in the Austin Chalk trend since 1992, with a 96% drilling success rate. The Austin Chalk horizontal wells are initially high-deliverability wells that provide strong cash flows, often reaching payout in less than a year. In 1995, Swift participated in nine successful development wells in the area. The Company plans to drill eight more development wells in 1996.

Operations

The Company generally seeks to be named as operator for wells in which it or its affiliated limited partnerships and joint ventures have acquired a significant interest, although this typically occurs only when the Company or its affiliated limited partnerships and joint ventures own the major portion of the working interest in a particular well or field. The Company acts as operator of approximately 770 wells, which comprise approximately 86% of the Company's total proved reserves.

As operator, the Company is able to exercise substantial influence over development and enhancement of a well and to supervise operation and maintenance activities on a day-to-day basis. The Company does not conduct the actual drilling of wells on properties for which it acts as operator. Drilling operations are conducted by independent contractors engaged and supervised by the Company. The Company employs petroleum engineers, geologists, and other operations and production specialists who strive to improve production rates, increase reserves, and/or lower the cost of operating its oil and gas properties.

Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator's direct expenses and monthly per-well supervision fees. Per-well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas, and other factors. Such fees received by the Company in 1995 ranged from $50 to $1,433 per well per month.

Marketing of Production

The Company typically sells its gas production at or near the wellhead, although in some cases it must be gathered by the Company or other operators and delivered to a central point. Gas production is generally sold in the spot market at prevailing prices. The Company generally sells its oil production at posted prices. The Company does not refine any oil it produces. Only one single oil or gas purchaser accounted for 10% or more of the Company's consolidated revenues during the year ended December 31, 1995, with that purchaser accounting for approximately 12%. The Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.

The following table summarizes sales volume, sales price, and production cost information for the Company's net oil and gas production for the three-year period ended December 31, 1995. "Net" production is production that is owned by the Company either directly or indirectly through partnerships or joint venture interests and produced to its interest after deducting royalty, limited partner, and other similar interests.

(1) Natural gas production for 1995, 1994, and 1993 includes 1,211,255, 1,358,375, and 1,581,206 Mcf, respectively, delivered under the Company's volumetric production payment agreement.

(2) Converted to Mcf equivalents on a thermal equivalent basis of 6 Mcf per barrel of oil.

Under the volumetric production payment entered into in 1992, as of December 31, 1995, the Company has a remaining commitment to deliver approximately 4.1 Bcf of gas meeting certain heating equivalent and quality standards through October 2000, when such agreement expires. Since entering into this agreement, these properties have produced in excess of the required monthly delivery requirements.

During 1995, the Company entered into oil and natural gas price hedging contracts covering a small portion of the Company's and its affiliated partnerships' oil and natural gas production. For the months of January, February, March, and April, 300,000 MMBtu of the natural gas production was covered, providing for a minimum price of $1.58. For the months of November and December, 1,000,000 MMBtu and 1,250,000 MMBtu, respectively, were covered, providing for minimum prices ranging from $1.65 to $1.75. For the months of March through December, 75,000 Bbls of oil production was covered, providing for minimum prices ranging from $17.00 to $18.00. Costs related to 1995 hedging activities totaled approximately $448,000, and benefits received totaled approximately $140,000. Open contracts at December 31, 1995, cover 1,500,000 MMBtu of the natural gas production for the months of January and February 1996, 1,000,000 MMBtu for March 1996, and 35,000 Bbls of oil production for March and April 1996, providing for minimum prices ranging from $1.65 to $1.75 per MMBtu and $17.50 per Bbl. The costs related to the open contracts totaled approximately $148,000 and had a market value of $39,000 as of December 31, 1995.

Foreign Activities

During 1993, the Company entered into a Participation Agreement (the "Participation Agreement") with Senega, a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%), to develop and produce reserves in two fields in Western Siberia. Under this Participation Agreement, the Company will receive a minimum 5% net profits interest. Additionally, the Company purchased a 1% net profits interest from the Russian Federation joint stock company for $300,000. In May 1995, the Company executed a Management Agreement with Senega. In return for obtaining financing for development of these fields, the Company was given certain rights by Senega, including a 49% interest in production income derived by Senega from this project after repayment of costs. During 1995, the Company was approved for the grant of a Petroleum Exploration Permit by the New Zealand Minister of Energy. This permit covers approximately 65,000 acres in the onshore Taranaki Basin region. The Company also is pursuing opportunities in the oil and gas industry in Venezuela. These activities are described in greater detail in Note 9 to the Company's financial statements.

Oil and Gas Reserves

The following table presents information regarding proved reserves of oil and gas attributable to the Company's interests in producing properties as of December 31, 1995, 1994, and 1993. The information set forth in the table is based on proved reserves reports prepared by the Company and audited by H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy's estimates were based upon review of production histories and other geological, economic, ownership, and engineering data provided by the Company. In accordance with Securities and Exchange Commission guidelines, the Company's estimates of future net revenues from the Company's proved reserves and the PV-10 Value are 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, 1995, were estimated based upon weighted average prices of $2.41 per Mcf of natural gas and $18.07 per barrel of oil, compared to $1.85 and $2.50 per Mcf of natural gas and $15.09 and $12.87 per barrel of oil as of December 31, 1994 and 1993, respectively. The Company has 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 also 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 Note 9 to the Consolidated Financial Statements of the Company, which is calculated after provision for future income taxes. In cases where producing properties are subject to gas purchase contracts and the amount of gas purchased thereunder was reduced during 1995, gas projections used to estimate future net revenues were based on the reduced gas purchases for the affected producing properties. The assumption was made that purchases in 1996 and thereafter will be made at an unrestricted level.

The Company's total proved developed and undeveloped reserves have increased substantially (70%) since December 31, 1994, as shown above and in Note 9 to the Company's financial statements. A substantial portion of the increased reserves represent proved undeveloped reserves. This shift reflects the increased emphasis on exploration and development activities, which results in additions of substantial proved undeveloped reserves. The Company's higher level of proved developed reserves was due to increased development drilling, revisions of previous quantity estimates, and higher year-end 1995 prices. 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.

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 the Company's proved reserves has been accumulated through the Company's interests in the limited partnerships for which it serves 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 the Company owns interests will achieve payout status in the future. None of the limited partnerships had achieved payout status at December 31, 1995.

No other reports on the Company's reserves have been filed with any federal agency.

Oil and Gas Wells

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

(1) Excludes 39 service wells in 1995, 31 service wells in 1994, and 165 service wells in 1993.

(2) A gross well is 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.

(3) 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.

Oil and Gas Acreage

As is customary in the industry, the Company generally acquires oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although the Company has 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 the Company's judgment it would be uneconomical or impractical to do so.

The following table sets forth the developed and undeveloped leasehold acreage held by the Company at December 31, 1995:

(1) A gross acre is 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.

(2) 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.

(3) A material portion of the Company's acreage is owned by virture of its interests derived from limited partnerships. The net acreage reflected on this table shows the Company's interests assuming that an after payout status is achieved in these partnerships. At December 31, 1995, none of the limited partnerships had achieved payout status.

Partnerships

The Company has historically relied on limited partnerships as its principal financing vehicle to fund its activities. The Company has formed 101 limited partnerships which have raised a total of approximately $463.3 million at December 31, 1995. However, as the Company has increasingly shifted its emphasis to exploration and development activities and its reserves base has grown, the Company has significantly reduced its reliance on limited partnership financing.

Approximately 18 of the limited partnerships formed and managed by the Company have been in operation for over nine years and have produced a substantial majority of their reserves. Given the age of these limited partnerships, the Company has proposed that the limited partners in 10 of these limited partnerships vote to sell their remaining properties and liquidate the limited partnerships. The Company anticipates that these proposals will be approved by these partnerships' limited partners and that these partnerships will be liquidated in 1996. The Company intends to make the same proposal to the other eight partnerships later this year.

From 1991 to 1995, the Company offered Swift Depositary Interests ("SDI"), a publicly offered partnership program under which partnerships were formed to acquire interests in producing oil and gas properties. Since 1993, the Company also has offered private partnerships formed to engage in the drilling of development and exploratory wells.

The Company concluded the SDI Program upon the formation of its last two partnerships organized on December 14, 1995. Under the SDI program, partnerships were formed on a sequential basis and, in 1995, the Company raised approximately $12.4 million under the SDI program. The SDI partnerships acquire, manage, and ultimately sell interests in properties that are producing oil and gas in commercial quantities or which contain shut-in wells capable of such production. The SDI partnerships seek to profit primarily from the sale of oil and gas produced from the properties in which they own interests, and from the proceeds of the eventual sale of their interests.

In September of 1993, the Company began offering interests in private drilling partnerships. As of December 31, 1995, five partnerships had been formed (one in 1993, one in 1994, and three in 1995) with aggregate investor contributions of approximately $19.9 million.

The private drilling partnerships have been offered on a no-load basis under which the Company pays all selling and offering expenses of the offering. Amounts paid by the Company are treated as a capital contribution to each partnership. The Company also is entitled to a general and administrative overhead allowance and an incentive amount. In certain partnerships, the Company does not bear any of the costs incurred in acquiring or drilling properties. The Company pays approximately 20% of all continuing costs (approximately 30% after payout and 35% after 200% payout), and the Company is entitled to receive 20% of net revenues distributed by each such partnership prior to payout, 30% distributed after payout, and 35% distributed after 200% payout. As managing general partner of certain other partnerships, the Company pays out of its own corporate funds the capital costs (consisting of all prospect costs and the non-deductible, tangible portion of drilling and completion costs). The Company pays approximately 40% of all continuing costs (approximately 45% after payout and 50% after 200% payout), and the Company is entitled to receive 40% of net revenues distributed by each such partnership prior to payout, 45% distributed after payout, and 50% distributed after 200% payout.

Conflicts of Interest Between the Company and Limited Partnerships

Under the terms of the Company's limited partnership programs, the Company generally retains the right to engage in oil and gas exploration and production through other limited partnerships and joint ventures and for its own account. The partnership agreement for each limited partnership contains detailed provisions regarding the terms upon which a variety of transactions between the Company and the limited partnerships may be carried out, including (i) sales of properties by the Company to the limited partnerships, (ii) operation of limited partnership properties by the Company, (iii) rendering of oil field or drilling services by the Company to a limited partnership, (iv) handling of limited partnership funds by the Company, and (v) loans between the Company and a limited partnership. These restrictions, which may limit the ability of the Company to take certain actions, are intended to ensure that transactions between the Company and the limited partnerships are fair to such limited partnerships.

Risk Management

The Company's 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 the Company to substantial liability due to pollution and other environmental damage. Additionally, as managing general partner of limited partnerships, the Company is solely responsible for the day-to-day conduct of the limited partnerships' affairs and accordingly has liability for expenses and liabilities of the limited partnerships. The Company maintains comprehensive insurance coverage, including general liability insurance in an amount not less than $20.0 million, as well as general partner liability insurance. The Company believes that its 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, 1995, the Company employed 176 persons. None of the Company's 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 equivalent (see Mcfe).

Development Well -- A well drilled within the presently proved productive area of an oil or 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 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 gas reservoir or to greatly extend the known limits of a previously discovered reservoir.

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 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 equivalent (see Mcfe).

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 gas in sufficient quantities to justify completion as an oil or gas well.

Proved Developed Oil and Gas Reserves -- Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Oil and Gas Reserves -- Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which 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 -- 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, and without giving effect to non-property related expenses such as debt service, future income tax expense, or depreciation, depletion, and amortization.

Reserve Replacement Cost -- With respect to proved reserves, a three-year average 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 the Company financed the purchase of certain oil and 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, 1995, not included in this Annual Report to Shareholders (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), as to the first three of which items no disclosures have been made, will be provided without charge to shareholders making a written request to John R. Alden, Secretary, 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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