PURSUING A RESERVES  GROWTH STRATEGY
	1993 ANNUAL REPORT
Form 10-K Excerpts

PART 1

Items 1 and 2. Business and Properties

General

Swift Energy Company (the "Company") 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, 1993, the Company’s proved oil and gas reserves were estimated to be 64.5 Bcf of natural gas and 4.3 MMBbl of oil, with an estimated reserve life of 13 years. Approximately 72% 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 public partnership offerings, raising a total of approximately $44.1 million in 1993, bringing the cumulative amount of funds raised by the Company through its partnership offerings to an approximate $400.4 million. The Company also raises capital through joint ventures and private drilling partnerships.

(Note: See page 47 for explanations of abbreviations used herein.)

Acquisition of Producing Properties

In 1993, the Company purchased approximately $83.5 million in producing properties in 10 transactions, 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, each property package meriting further consideration is reviewed by the Company’s property acquisition team. 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 1993, approximately 234 packages were reviewed by the Company, of which only 10 packages were purchased.

Development of Producing Properties

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.

In 1993, Swift participated in the drilling of 34 wells, 22 of which were development wells. Twenty-six of the wells drilled were successful (21 development and 5 exploratory), placing into production for the Company’s account proved reserves of approximately 1.6 million BOE and adding newly proved undeveloped reserves of 0.9 million BOE. 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, 1993:

(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)Most 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 each development well exists primarily to the extent of its partnership interest. Given the indirect nature of the Company’s ownership, its net interest in development wells is therefore typically  limited.

(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.

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 "The AWP Olmos Field" under "Major Producing Properties."

Exploration

The Company’s exploration program is conducted by a 17-member staff, assisted by approximately 15 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 65,000 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, 1993, the Company had an inventory of 33 exploration prospects in four main geological basins:

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

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.

Powder River Basin. In the Rocky Mountain Region, in Campbell County, Wyoming, targeting 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.

Gulf Coast Basin. In the Gulf Coast Region in the Miocene Frio, the Austin Chalk, the Wilcox, and the Yegua trends at an average depth of 9,000 feet. In the Austin Chalk formation, the Company has already participated in eight successful horizontal wells and plans to drill additional wells in 1994.

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, 1993, the Company acted as operator of approximately 795, or 19%, of the 4,202 wells in which it owned interests. The Company-operated wells accounted for 64% 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.

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 range from $50 to $1,333 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, 1993. The Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.

During 1993, the Company entered into its first natural gas price hedging contract providing a minimum price of $1.75 per MMBtu for approximately 50% of the Company’s and its partnerships’ natural gas production for the five-month period ending September 30, 1993.

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, 1993. "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.

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 a capital commitment of up to $5,000,000. The Company also is pursuing opportunities in Venezuela. These activities are described in greater detail in Note 9 to the Company’s financial statements.

Major Producing Properties

Due to the diversity of properties held within its partnerships, no single field or area other than the AWP Olmos Field and the Weatherford Area accounted for a significant portion of the Company’s proved oil and gas reserves as of December 31, 1993.

The AWP Olmos Field. The AWP Olmos Field, located in McMullen County, Texas, represents approximately 22% of the Company’s proved reserves at December 31, 1993. Interests are owned in 79 wells producing from the Olmos Sand Formation at a depth of 10,000 feet, and the Company is the operator of all 79 wells. Working interests owned by the Company and its partnerships range from 86.5% to 100%. During 1993 the Company drilled three wells in this field. These three wells placed into production over 0.7 million BOE for the Company in 1993 at a cost of $1.77 per BOE. 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.

The Weatherford Area. The Weatherford Area, located in Caddo, Custer, and Washita Counties in southwestern Oklahoma, represents approximately 9% of the Company’s proved reserves at December 31, 1993. Interests are owned in 142 gas wells 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 43 wells (to which approximately 78% 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 1993 the Company participated in five successful wells in the field, which placed in production 116,736 net BOE. The Company also manages a gas gathering system, including pipelines and compressors, and two condensate recovery systems in the field.

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 165 service wells in 1993, 131 service wells in 1992, and 68 service wells in 1991.

(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, 1993:

(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 substantial majority of the Company’s acreage is owned by virtue of earned interests from limited partnerships. The net acreage reflected on this table shows the Company’s interests assuming that an after payout status is achieved. At December 31, 1993, none of the limited partnerships had achieved payout status.

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, 1993, 1992, and 1991. 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, 1993, were estimated based upon weighted average prices of $2.50 per Mcf of natural gas and $12.87 per barrel of oil, compared to $2.45 and $2.07 per Mcf of natural gas and $17.52 and $17.28 per barrel of oil as of December 31, 1992 and 1991, 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 the Notes 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 1993, 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 1994 and thereafter will be made at an unrestricted level.

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 reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve 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, reserve 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 substantial majority 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 assume that a majority 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, 1993.

Sponsorship of SDI Partnerships

The Company sponsors 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 1993, the Company raised approximately $42.7 million under the SDI program.

The Company acts as managing general partner for the SDI partnerships. Each partnership also has a special general partner. The Company has full and exclusive power to administer the business of the SDI partnerships, but may consult with the special general partner as to certain financial matters.

     Payments and Fees to Company from SDI Partnerships

From each SDI partnership the Company receives the following payments and fees for its activities as managing general partner of the partnership. The special general partner also receives certain payments and fees.

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. Payout occurs when aggregate cash distributions to investors equal or exceed the sum of their aggregate capital contributions. None of the SDI partnerships had achieved payout status at December 31, 1993.

Earned Interest. The Company earns a promoted earned interest in each SDI partnership, which is in addition to the paid interest to which the Company is entitled by reason of its capital contribution to the partnership. The amount of the earned interest is recognized as revenue by the Company as the SDI partnership acquires producing oil and gas properties. The amount recognized with respect to a particular acquired property essentially equals the percentage of the purchase price for the property that is paid by the partnership on behalf of the Company.

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 legal, accounting, reporting, geological, engineering, land, employee, and other reasonable and incidental 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, except that during the first year of a partnership’s existence the incentive amount instead equals 1.5% of investor subscriptions.

     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 include (i) selling commissions payable to broker-dealers participating in the offering, (ii) payments to the dealer manager as compensation for managing the SDI offering and as reimbursements for due diligence expenses, and (iii) all formation costs, including printing expenses, legal and accounting fees and expenses, and securities registration and qualification fees. Selling and offering expenses will vary from year to year but over the life of the program are expected to average 13% of investor subscriptions. These 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 or funding identified development projects, 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 175 broker-dealers. SEMCO is a wholly owned subsidiary of the Company. The special general partner of the SDI partnerships is VJM Corporation.

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. The Company will continue to seek opportunities to perform acquisition services on behalf of industry co-venturers and institutional investors in the future.

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. At December 31, 1993, one partnership had been formed under this program, with subscriptions of approximately $1.4 million.

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.

Competition

The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from many other oil and gas producers, including many that possess substantial financial resources, in acquiring economically desirable producing properties and exploratory drilling prospects, and in obtaining equipment and labor to operate and maintain its properties. In marketing its SDI and SEDV partnership programs, the Company competes with other oil and gas companies sponsoring similar programs and with numerous other investment opportunities.

Regulations

     Environmental Regulations

The federal government and various state and local governments have adopted laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas or where pollution arises, and impose substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. These laws and regulations may also increase the costs of routine drilling and operation of wells. Because these laws and regulations change frequently, the costs to the Company of compliance with existing and future environmental regulations cannot be predicted.

     Federal Regulation of Natural Gas

The transportation and sale of natural gas in interstate commerce is heavily regulated by agencies of the federal government. The following discussion is intended only as a summary of the principal statutes, regulations, and orders that may affect the production and sale of the Company’s natural gas. This summary should not be relied upon as a complete review of applicable natural gas regulatory provisions.

Price Controls. Prior to January 1, 1993, the sale of natural gas production was subject to regulation under the Natural Gas Act and the Natural Gas Policy Act of 1978 ("NGPA"). However, under the Natural Gas Wellhead Decontrol Act of 1989 all price regulation under the NGPA and Natural Gas Act rate, certificate and abandonment requirements were phased out effective as of January 1, 1993.

FERC Order No. 636. In April 1992 the Federal Energy Regulatory Commission ("FERC") issued Order No. 636 pertaining to pipeline restructuring. This rule requires interstate pipelines to unbundle transportation and sales services by separately stating the price of each service and by providing customers only the particular service desired, without regard to the source for purchase of the gas. The rule also requires pipelines to (i) provide nondiscriminatory "no-notice" service allowing firm commitment shippers to receive delivery of gas on demand up to certain limits without penalties, (ii) establish a basis for release and reallocation of firm upstream pipeline capacity, and (iii) provide non-discriminatory access to capacity by firm transportation shippers on a downstream pipeline. The rule requires interstate pipelines to use a straight fixed variable rate design.

     State Regulations

Production of any oil and gas by the Company will be affected to some degree by state regulations. Many states in which the Company operates have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit.

     Federal Leases

Some of the Company’s properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and orders affect the terms of leases, exploration and development plans, methods of operation, and related matters.

Employees

At December 31, 1993, the Company employed 188 persons. None of the Company’s employees are represented by a union. Relations with employees are considered to be good.

Facilities

The Company and SEMCO occupy approximately 61,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a four year lease expiring in 1995. The lease requires payments of approximately $73,000 per month. A subsidiary of the Company maintains an office in Denver, Colorado. The Company has field offices in various locations from which Company employees supervise local oil and gas operations.

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 six Mcf of natural gas to one barrel of oil, condensate, or natural gas liquids.

"Mcf" means thousand cubic feet.

"MMcf" means million cubic feet.

"Bcf" means billion cubic feet.

"Bbl" means barrel or barrels.

"MMBbl" means million barrels.

"MMBtu" means a million British thermal units.

Item 3. Legal Proceedings – None other than those incident to the Company’s ordinary business.

Item 4. Submission of Matters to a Vote of Security Holders – None submitted in the fourth quarter of 1993.

PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters – See inside back cover herein.

Item 6. Selected Financial Data – See pages 20 to 21 herein. The table on these pages contains all required data except for fully diluted income per share. For the year ended December 31, 1993, which is the only year presented which had fully dilutive income per share, the amount was $0.77.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – See pages 22 to 26 herein.

Item 8. Financial Statements and Supplementary Data – See pages 27 to 41 herein.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure – None.

PART III

Items 10–13. Information on the Company’s Directors and Executive Officers, Executive Compensation, Security Ownership of Certain Beneficial Owners and Management, and Certain Relationships and Related Transactions will be included in the proxy statement for the 1994 annual meeting of stockholders to be mailed prior to April 30, 1994.

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.

No reports on Form 8-K were filed during the fourth quarter of 1993.

 

Financial Statement Schedules IV, V, VI, and X or exhibits filed as part of the Form 10-K 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.

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