RESERVES GROWTH WITH  A REGIONAL FOCUS
	1994 ANNUAL REPORT
Form 10-K Excerpts

PART 1

Items 1 and 2. Business and Properties

General

Swift Energy Company (the "Company"), a Texas corporation organized in October 1979, is engaged in the acquisition, development, operation, and exploration of oil and gas properties, with particular emphasis on U.S. onshore natural gas reserves. As of December 31, 1994, the Company's proved oil and gas reserves were estimated to be 76.3 Bcf of natural gas and 4.6 MMBbl of oil, with an estimated reserve life of 13 years. Approximately 74% of the Company's oil and gas reserves consist of U.S. onshore natural gas.

The Company has historically financed most of its acquisitions with capital raised through partnership offerings, raising a total of approximately $34.7 million in 1994, bringing the cumulative amount of funds raised by the Company through its partnership offerings to an approximate $435.1 million. The Company also raises capital through joint ventures and private drilling partnerships.

(Note: See page 48 for explanations of abbreviations used herein.)

Exploration and Development Activities

In 1994, Swift's exploration and development program added 24.8 Bcfe (4.1 BOEs) to the Company's proved reserves, including 16.3 Bcfe of proved undeveloped reserves. The 44 wells drilled--32 of which were successful (26 development and 6 exploratory)--placed 12.4 Bcfe of the Company's reserves into production--8.5 Bcfe of the newly proved reserves and 3.9 Bcfe of previously proved undeveloped reserves.

The proved reserves added through exploration and development activities in 1994 were the highest in the Company's history, providing almost twice the volume of new reserves as were provided through the acquisition of producing properties. Exploration and development costs during 1994 totaled $12.7 million--a reserves addition cost of $0.51 per Mcfe. Approximately 83% of the proved reserves added through exploration and development were natural gas.

The Company's success rate for 1994 drilling activity was 43% for exploratory wells (6 out of 14 drilled) and 87% for development wells (26 out of 30 drilled). Nine of the Company's successful wells (eight of which were development) were drilled in the South Texas region. This region includes the Company's largest field, the AWP Olmos Field, which contains 37% of the Company's total proved reserves. Six successful horizontal development wells were drilled in the Texas Austin Chalk, and three successful exploratory wells and five successful development wells were drilled in the Texas Gulf Coast, principally in the Yegua trend. Finally, five successful development wells were drilled in the Weatherford Area of Oklahoma, along with two successful exploratory wells and two successful development wells drilled in other areas. The Company has identified 66 locations available for drilling during 1995. The number of wells to be drilled depends upon field success, capital resources, pricing, and other factors.

The Company does not itself drill development wells on properties for which it acts as operator. Drilling operations are conducted by independent contractors engaged and supervised by the Company.

The following table sets forth the results of the Company's drilling activities during the three fiscal years ended December 31, 1994:

(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 which 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.

The Company's exploration program is conducted by an in-house exploration staff, assisted by professionals from other departments, all of whom are experienced reservoir engineers, geologists, geophysicists, petrophysicists, landmen, or drilling and operations engineers. The staff has a library of approximately 85,000 miles of seismic lines, including data from its own seismic surveys in Oklahoma and Texas. The seismic data are analyzed and enhanced with state-of-the-art computer systems utilizing more than 100 diagnostic and enhancement programs, many of which have been customized by Company employees.

At December 31, 1994, the Company had an inventory of exploration prospects in four main geological basins:

Gulf Coast Basin. In South Texas (Railroad Commission Districts 1 and 4) and the Texas Gulf Coast (Railroad Commission Districts 2 and 3), targeting the Miocene Frio, the Wilcox, and the Yegua trends at an average depth of 9,000 feet; in the Austin Chalk formation, where the Company has already participated in 14 successful horizontal wells; and in South Louisiana, focusing on the Miogyp and Marg Howei trends at an average depth of 18,000 feet.

Anadarko Basin. In the Weatherford area of Oklahoma, targeting the Red Fork Formation at an approximate depth of 12,000 feet.

Powder River Basin. In the Rocky Mountain Region, in Campbell and Crook Counties, Wyoming, focusing on the Minnelusa Formation at an average depth of 9,500 feet. The Company has a detailed analysis of virtually every producing field in the Minnelusa, which includes evaluations of 5,000 wells.

N. Louisiana Salt Dome Basin. In the Ark-La-Tex area, where the borders of Texas, Louisiana, and Arkansas meet, targeting three areas of exploration--the Meakin, the Jurassic Smackover, and the Cotton Valley formations. The Company has access to a 7,000-mile seismic database in this region.

Acquisition of Producing Properties

In 1994, the Company purchased approximately $18.1 million in producing properties in one transaction, both on behalf of Company-managed partnerships and for its own account.

Producing 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, future prices and costs, and various factors affecting the marketing of production. The producing properties presented to the Company for review and possible acquisition are typically "packages" of properties, consisting of various wells in a number of different fields, often located in several states. After initial screening, the Company's property acquisition team reviews each property package meriting further consideration. The property acquisition team submits an analysis of each property package, together with a recommended bid price, to a property acquisition review committee comprised of senior members of management, which makes the final determination as to whether or not the Company will seek to purchase that package. Of the property packages reviewed, few are ultimately approved for purchase. During 1994, approximately 210 packages were reviewed by the Company, of which only one package was purchased.

Operation of Producing Properties

Wherever possible, the Company seeks to be named as operator for wells in which it or its partnerships and joint ventures have acquired a significant interest, although this typically occurs only when the Company or its partnerships and joint ventures own at least a plurality of the working interest in a particular well or field. At December 31, 1994, the Company acted as operator of approximately 750, or 18%, of the 4,172 wells in which it owned interests. The Company-operated wells accounted for 61% of the Company's total proved reserves.

For wells as to which it has been designated as operator, the Company exercises substantial influence over development and enhancement of the well, and supervises the operation and maintenance of the well on a day-to-day basis, making all decisions with respect to necessary labor and equipment, construction of processing facilities or pipelines, and marketing of production. As operator, the Company is also responsible for payment of applicable taxes, purchase of necessary insurance, and payment of royalties and other production revenues. The Company employs experienced petroleum engineers, geologists, and other operations and production specialists who attempt to improve rates of production from, increase reserves attributable to, and/or lower the cost of operating the oil and gas properties in which the Company or its partnerships own interests.

In connection with its duties as an operator of oil and gas wells, the Company constantly seeks to identify properties on which the drilling of development wells or application of secondary recovery techniques may generate significantly improved rates of production or permit recovery of additional reserves. The Company employs a technical staff of petroleum engineers and geologists specifically dedicated to the identification of such properties and the supervision of enhancement operations thereon.

Secondary recovery techniques employed by the Company include water flooding, fracturing reservoir rock through injection of high-pressure fluid, insertion of 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 from the Company's largest single property, the AWP Olmos Field. See "South Texas Olmos" under "Major Properties."

Oil and gas properties are customarily operated under the terms of an operating agreement and accompanying joint accounting procedures, which provide for reimbursement to the operator of its direct expenses of operating a property and for monthly per-well supervision fees. Per-well supervision fees vary widely depending on 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 1994 ranged from $50 to $1,372 per month.

Marketing of Production

The Company's gas production is sold 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's oil production is generally sold at posted prices. The Company does not refine any oil it produces. No single oil or gas purchaser accounted for 10% or more of the Company's consolidated revenues during the year ended December 31, 1994. 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, 1994. "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 1994, 1993, and 1992 includes 1,358,375, 1,581,206, and 1,148,862 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, the Company is committed to deliver approximately 9.5 Bcf of gas meeting certain heating equivalent and quality standards over an eight-year period. Since entering into this agreement, these properties have produced in excess of the required delivery requirements.

During 1994, the Company entered into three natural gas price hedging contracts covering a small portion of the Company's and its affiliated partnerships' natural gas production. Two contracts covered 300,000 MMBtu of such production, one covering the first two months of 1994 and one the last two months, providing for minimum prices of $2.25 and $1.58 per MMBtu, respectively. The third contract covered 1,000,000 MMBtu for July, August and September production with a floor price of $1.77.

Foreign Activities

During 1993, the Company entered into a Participation Agreement with 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 Agreement, the Company would receive a minimum 5% net profits interest in return for an initial budgeted capital expenditure of up to $5,000,000. The Company also is pursuing opportunities in Venezuela. These activities are described in greater detail in Note 10 to the Company's financial statements.

Major Properties

Due to the diversity of properties held within its partnerships, no single field or area other than the AWP Olmos Field, Texas Austin Chalk, the Weatherford Area, and East Mud Lake and Second Bayou Fields accounted for a significant portion of the Company's proved oil and gas reserves as of December 31, 1994.

South Texas Olmos. The AWP Olmos Field and an adjacent 8,830-acre leasehold acquired in 1994, located in McMullen County, Texas, represent approximately 37% of the Company's proved reserves at December 31, 1994. Interests are owned in 85 wells producing from the Olmos Sand Formation at a depth of 10,000 feet, and the Company is the operator of all 85 wells. Working interests owned by the Company and its partnerships in this field range from 86.5% to 100%. During 1994, the Company drilled four 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 increase 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.

Texas Austin Chalk. The Texas Austin Chalk Area located primarily in Fayette County, Texas, and other adjacent counties, represents approximately 8% of Swift's proved reserves. Since 1992, Swift has participated in 14 horizontal wells in the Austin Chalk trend with a 100% drilling success rate. The Austin Chalk horizontal wells are initially high-deliverability wells that provide strong cash flows, usually reaching payout in less than a year. In 1994, Swift participated in six successful development wells in the area. The Company has a substantial amount of undeveloped proved reserves in this area with plans to drill seven more development wells in 1995.

The Weatherford Area. The Weatherford Area, located in Caddo, Custer, and Washita Counties in southwestern Oklahoma, represents approximately 6% of the Company's proved reserves at December 31, 1994. Interests are owned in 144 properties producing primarily from the Red Fork and Springer (Britt) Formations at average depths of 12,500 and 15,000 feet, respectively. The Company is the operator of 40 wells (to which approximately 75% of its proved reserves in the field are attributable), with the remainder operated by various third parties. Working interests owned by the Company and its partnerships range from 0.2% to 98%. During 1994 the Company participated in five successful wells in the field, which placed into production 153,732 net Mcfe. The Company also manages a gas gathering system, including pipelines and compressors, and two condensate recovery systems in the field.

South Louisiana East Mud Lake and Second Bayou Fields. The East Mud Lake and Second Bayou Fields located adjacently in Cameron Parish, Louisiana, represent approximately 6% of the Company's proved reserves. The Company owns working interests ranging from 4% to 14% in various wells, which are outside operated. Mainly, this field produces natural gas and the field has a significant amount of proved undeveloped reserves that are expected to be producing in the next few years.

Proved Reserves and Future Net Cash Flows

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, 1994, 1993, and 1992. 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., independent petroleum engineers in Houston, Texas. Proved reserves as of December 31, 1994, were estimated based upon weighted average prices of $1.85 per Mcf of natural gas and $15.09 per barrel of oil, compared to $2.50 and $2.45 per Mcf of natural gas and $12.87 and $17.52 per barrel of oil as of December 31, 1993 and 1992, respectively. The Company has interests in certain tracts which are estimated to have additional hydrocarbon reserves which cannot be classified as proved and are not reflected in the following table.

 

The table also sets forth estimates of the present value of future net cash flows from proved reserves prior to income taxes, presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the Securities and Exchange Commission, discounted at 10% per annum. Operating costs and development costs and certain production-related taxes were deducted in arriving at the estimated present value of future net cash flows. No provision was made for income taxes. The estimates of future net cash flows and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in Note 10 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 1994, gas projections used to estimate future net cash flows were based on the reduced gas purchases for the affected producing properties. The assumption was made that purchases in 1995 and thereafter will be made at an unrestricted level.

The Company's total proved reserves have increased substantially since December 31, 1993, as shown above and in Note 10 to the Company's financial statements. A substantial amount of the increases realized was in proved undeveloped reserves primarily through the Company's 1994 exploration efforts. Proved developed natural gas reserves decreased, however, primarily due to production and through revisions of previous quantity estimates. Changes in quantity estimates are affected by the change in crude oil and natural gas prices at the end of each year, as is the estimated present value of proved reserves. As discussed above, proved reserves as of December 31, 1994, were based upon $1.85 per Mcf and $15.09 per barrel of oil, compared to $2.50 per Mcf and $12.87 per barrel of oil as of December 31, 1993.

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 partnerships it manages. 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 partnerships in which the Company owns an interest had achieved payout status at December 31, 1994.

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 31 service wells in 1994, 165 service wells in 1993, and 131 service wells in 1992.

(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, 1994:

(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 is 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, 1994, none of the limited partnerships had achieved payout status.

SDI Partnerships

Since 1991, the Company has offered Swift Depositary Interests ("SDI"), a publicly offered partnership program under which partnerships are formed to acquire interests in producing oil and gas properties. Under the SDI program, partnerships are formed on a sequential basis, typically at quarterly intervals. In 1994, the Company raised approximately $32.1 million under the SDI program.

The Company acts as managing general partner for the SDI partnerships. Each partnership also has a special general partner (VJM Corporation).

Payments and Fees to Company from SDI Partnerships. The Company receives the following payments and fees for its activities as managing general partner of each SDI partnership.

Cash Distributions. On at least a quarterly basis, each SDI partnership distributes to its partners all revenues remaining after payment of partnership expenses and establishment of any necessary cash reserves. The Company is entitled to receive 14.25% of the net revenues distributed by each SDI partnership prior to payout and 24.25% of such net revenues distributed after payout. None of the SDI partnerships had achieved payout status at December 31, 1994.

General and Administrative Overhead Allowance. The Company receives from each SDI partnership an annual, fully accountable allowance equal to up to 2.0% of total investor capital contributions as reimbursement for customary and routine general and administrative expenses incurred in the conduct of the partnership's business.

Incentive Amount. The Company receives from each SDI partnership an annual, nonaccountable incentive amount equal to 1.25% of all partnership net revenues (1.5% of investor subscriptions during the first year of a partnership's existence).

Obligations of Company to SDI Partnerships. For the SDI partnerships, the Company pays all of the selling and offering expenses incurred in connection with the offering, which vary from year to year but over the life of the program are expected to average 16% of investor subscriptions. Amounts paid by the Company are treated as a capital contribution to each SDI partnership. The Company does not bear any portion of the costs incurred by the SDI partnerships in acquiring properties, but bears approximately 14.25% of all other continuing costs (approximately 24.25% after payout).

As managing general partner of the SDI partnerships, the Company is solely responsible for the day-to-day conduct of the partnerships' affairs. The Company, together with the special general partner, has unlimited liability for expenses and liabilities of the production partnerships that cannot be paid out of available insurance proceeds and partnership assets. The Company maintains comprehensive general liability insurance in an amount not less than $10,000,000, as well as general partner liability insurance.

Marketing of Interests in SDI Partnerships. Interests in the SDI program are marketed on a nationwide basis through a network of broker-dealers. The dealer manager for the SDI offering is Swift Energy Marketing Company ("SEMCO"), which oversees a network of approximately 151 broker-dealers. SEMCO is a wholly owned subsidiary of the Company.

Drilling Partnerships

In September 1993, the Company began offering interests in Swift Energy Drilling Ventures, a privately offered partnership program under which partnerships are formed to engage in drilling development wells and exploratory wells. As of March 15, 1995, three partnerships had been formed under this program (one in each of 1993, 1994, and 1995), with total subscriptions of approximately $9.0 million. The Company anticipates formation of at least one additional private drilling partnership in 1995.

The drilling partnership program, like the SDI program, is a "no-load" offering under which the Company pays all selling and offering expenses of the offering. In exchange, the Company is entitled to receive 20% of net revenues distributed by each partnership prior to payout, 30% distributed after payout, and 35% distributed after 200% payout. The Company is also entitled to a general and administrative overhead allowance and an incentive amount in the same amounts as are described above for the SDI partnerships.

Joint Ventures for Producing Property Acquisitions

From time to time, the Company has entered into joint ventures with unaffiliated industry co-venturers pursuant to which the Company has located, analyzed, and negotiated the acquisition of producing properties on behalf of such industry co-venturers. No such joint ventures were entered into in 1993 or 1994.

Employees

At December 31, 1994, the Company employed 209 persons. None of the Company's employees are represented by a union. Relations with employees are considered to be good.

Abbreviations

The following are abbreviations used above in this section to describe quantities of oil and gas:

"BOE" means a barrel of oil equivalent, which is determined using the ratio of 6 Mcf of natural gas to one barrel of oil, condensate, or natural gas liquids.

"Mcf" means thousand cubic feet.

"Mcfe" means thousand cubic feet equivalent.

"MMcf" means million cubic feet.

"Bcf" means billion cubic feet.

"Bcfe" means billion cubic feet equivalent.

"Bbl" means barrel or barrels.

"MMBbl" means million barrels.

"MMBtu" means a million British thermal units.

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Those portions of the Form 10-K Report for the year ended December 31, 1994, 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), which items were either inapplicable or as to which 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 77060-9968. 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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