Properties

 

The Company’s proved reserves are geographically concentrated, with approximately 87% of the Company’s proved reserves at December 31, 1996, attributable to its two largest properties, the AWP Olmos Field and the Austin Chalk trend.

AWP Olmos Field. The Company’s most significant property is located in the AWP Olmos Field in South Texas. The Company has extensive expertise in the AWP Olmos Field and a long history of experience with low-permeability tight-sand formations typical of this field. 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 overall costs and improve recoveries.

The AWP Olmos Field represented approximately 77% of the Company’s proved reserves at December 31, 1996, and approximately 57% of the Company’s 1996 production. At December 31, 1996, the Company owned interests in and was the operator of approximately 240 wells producing natural gas from the Olmos Sand Formation at a depth of approximately 10,000 feet. The Company has engaged in extensive fracturing operations to increase the permeability of the formation and flow of gas from the wells. In addition, the Company has used coiled tubing velocity strings in several wells to improve production rates and a system of BJ Services, Inc., by which the Company is capable of monitoring fracturing operations from its Houston headquarters through direct computer access to the field.

During 1996, the Company drilled 123 (119 successful) development wells in this field and one exploratory well which was successful. During the latter portion of 1996, the Company utilized eight drilling rigs in continuous operation in the AWP Olmos Field area, with each rig drilling approximately two wells per month. The working interest owned by the Company or entities managed by the Company in this field is 100%. During 1996, the Company acquired an additional 18,549 net acres in this area. These acquisitions have doubled the amount of acreage that the Company has under lease. The Company anticipates continuing its acquisition of acreage in this area in the future. The Company plans to drill approximately 146 additional development wells and three exploratory wells in this field in 1997. As part of this effort, the Company plans to conduct a three-dimensional seismic survey over a 20-square-mile area to supplement an ongoing study of stratigraphic traps based on available well log and seismic data.

Austin Chalk Trend. At December 31, 1996, the Company owned drilling and production rights in 74,010 net acres in the Austin Chalk trend containing substantial proved undeveloped reserves. The Austin Chalk trend represented approximately 10% of the Company’s proved reserves at December 31, 1996. Production from this field constituted 18% of oil and gas production in 1996. The wells in this trend are all horizontally produced natural gas wells that deliver high initial flow rates and strong initial cash flows which decline rapidly. The Company believes these reserves complement its long-lived reserves in the AWP Olmos Field. Since 1992, the Company has participated in 33 horizontal wells in the trend with a 97% success rate, including nine successful development wells drilled in 1996. 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. The Company anticipates drilling 12 wells in the Austin Chalk during 1997.

Substantial portions of its property interests in the Austin Chalk trend have been acquired through joint development arrangements with industry partners who are active participants in exploration of the Austin Chalk trend, beginning in 1993 in an arrangement that covered approximately 8,800 acres in which the Company currently has an average working interest of 25%. In September 1995, the Company entered into another joint development agreement providing for an area of mutual interest covering 19,500 gross acres and pursuant to which that industry partner and the Company alternate serving as operator of any wells drilled on the acreage. During 1996, the Company purchased its partner’s interest in 9,500 of these gross acres, and the joint development arrangement now covers a 10,000 gross acre block in which the Company expects to have an average working interest of 30% to 35% based on certain assumptions relating to elections to participants with respect to the drilling of various wells. The Company’s working interest in the 9,500 acres is now approximately 50%.

The most recent joint development arrangement covers approximately 8,000 acres in Washington County, Texas, in which the Company has a 25% working interest. The Company’s industry partner is operator, and it is anticipated that the results of the first exploratory well drilled on this acreage will be known in early 1997.

Also in 1996, the Company acquired approximately 39,157 net acres in Walker County, Texas, in which the Company has a 100% working interest. It is anticipated that the first exploratory well on this acreage will commence drilling in early 1997. Future operations will be defined by the results of the initial wells drilled.

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. During 1994, the Company added 25 Bcfe of proved reserves through drilling, and in 1995, reserves added by drilling had almost tripled to 72 Bcfe. In 1996, reserves added by drilling increased to 118 Bcfe with the Company’s success rate 64% for exploratory wells (7 out of 11 drilled) and 94% for development wells (134 out of 142 drilled). These successful drilling results have led to acquisition of substantial additional acreage during 1996 in the area of its two core properties, the AWP Olmos Field in South Texas and the Austin Chalk trend in Fayette, Walker, and Washington counties in central and eastern Texas.

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 which are in close proximity to known producing horizons 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, particularly in 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 and amplitude versus offset (AVO) studies. During the second quarter of 1996, the Company completed two 3-D seismic programs, one in northern Louisiana and the other in central Texas. The Company has a number of computer workstations from which seismic data is analyzed and enhanced with advanced software programs, including its three Landmark Systems® workstations. As a result, the Company has developed a significant internal seismic expertise and has compiled an extensive library of seismic data.

In addition to exploration and development activities in the AWP Olmos Field and the Austin Chalk trend, the Company is currently focusing its exploration activities in three main geographical areas: the Gulf Coast Basin, the Wyoming Powder River Basin, and the North Louisiana Salt Dome Basin.

Gulf Coast Basin. In 1996, two successful development wells (out of four) and one successful exploratory well (out of three) were drilled in the Gulf Coast Basin, following one successful exploratory well and four successful development wells drilled in 1995. The locations were selected utilizing traditional geologic studies combined with analyses of available seismic data. To reduce its exploration and development risks, 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 drilling potential. In 1997, up to five exploratory wells are scheduled for drilling in the Gulf Coast Basin.

Wyoming Powder River Basin. In 1996, the Company successfully drilled one out of three exploratory wells and also one out of three 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. Two seismic surveys were conducted in 1996 and at least two more are scheduled for 1997. 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 wells in 1997, three wells to the Minnelusa in Campell County and another well to the Sussex/Parkman formation in Converse County.

North Louisiana Salt Dome. The North Louisiana Salt Dome covers the neighboring corners of Arkansas, Louisiana, and Texas. In 1996, the Company drilled five wells (four exploratory wells and one development well) all of which were successful. 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. This region was the focus of several seismic surveys conducted by Swift during 1996, including a 3-D survey in Claiborne Parish, Louisiana, a 2-D seismic swath in Lafayette County and Hempstead County, Arkansas, a 2-D seismic line in Lafayette County, Arkansas, and a 2-D seismic line in Columbia County, Arkansas. In addition, Swift conducted an airborne magnetic survey over Nevada County, Arkansas, for correlation with existing seismic data. During 1997, two additional sets of 2-D seismic swaths will be conducted in Lafayette County, Arkansas, and one will be conducted in Webster Parish, Louisiana. The Company plans to drill seven exploratory wells in the region in 1997.

The following table sets forth the results of the Company’s drilling activities during the three fiscal years ended December 31, 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 842 wells at December 31, 1996, which comprise approximately 99% 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 1996 ranged from $104 to $1,450 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 prevailing market prices. The Company does not refine any oil it produces. During the year ended December 31, 1996, three oil or gas purchasers each accounted for 10% or more of the Company’s revenues, with those purchasers together accounting for 51%. Only one oil or gas purchaser accounted for 10% or more of the Company’s revenues during the year ended December 31, 1995, with that purchaser accounting for approximately 12%. This change in concentration is a direct result of the concentration of the Company’s production in its two core areas, as discussed above. Because of the availability of other purchasers, the Company does not believe that the loss of any single oil or gas purchaser or contract would materially affect its sales.

The Company recently entered into gas processing and gas transportation agreements with respect to its natural gas production in the AWP Olmos Field with Valero Transmission, L.P. and its affiliates ("Valero") for up to 75,000 Mcf per day. These contracts have initial six-year terms, with automatic one-year extensions thereof unless earlier terminated. The Company anticipates that these arrangements will adequately provide for its gas transportation and processing needs in the AWP Olmos Field for the foreseeable future. Additionally, at the discretion of the Company and Valero, the gas processed and transported under these agreements may be sold to Valero at indexed prices based upon the Inside F.E.R.C. Gas Market Report Houston Ship Channel Monthly Price.

The following table summarizes sales volumes, sales prices, and production cost information for the Company’s net oil and gas production for the three-year period ended December 31, 1996. "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 1996, 1995, and 1994 includes 1,156,361, 1,211,255, and 1,358,375 Mcf, respectively, delivered under the volumetric production payment agreement pursuant to which the Company is obligated to deliver certain monthly quantities of natural gas.

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

(3) The above natural gas prices reflect the high Btu content of the natural gas produced from the Company’s AWP Olmos and Austin Chalk properties. Gas is sold on the basis of price per MMBtu, which measures the heating equivalent of such gas. The prices per Mcf above (Mcf being strictly a physical measure of natural gas volumes) are therefore higher than the prices which would be paid for natural gas with a lower Btu content.

Under the volumetric production payment entered into in 1992, as of December 31, 1996, the Company has a remaining commitment to deliver approximately 3.0 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.

Price Risk Management

 

During 1996, the Company entered into oil and natural gas price hedging contracts covering a portion of the Company’s and its affiliated partnerships’ oil and natural gas production. For January, 1,500,000 MMBtu of the natural gas production was covered, providing for a minimum price of $1.75 per MMBtu. February was covered for 1,500,000 MMBtu of natural gas and March was covered for 1,000,000 MMBtu of natural gas, both at a minimum price of $1.65. For the months of May, June, July, August, September, and October, 1,400,000 MMBtu was covered, providing for a minimum price of $1.80. November was covered for 1,400,000 MMBtu of natural gas at a minimum price of $2.20. December was covered for 1,400,000 MMBtu of natural gas at a minimum price of $2.00. For the months of March (70,000 Bbls) and April (35,000 Bbls), oil production was covered for a minimum price of $17.50 per Bbl. For the months of May through September, 70,000 Bbls of oil production was covered, providing for minimum prices of $16.00. For the months of October through December, 70,000 Bbls of oil production was covered, providing for a minimum price of $17.00. Costs related to 1996 hedging activities totaled approximately $800,000, and no payments were received in 1996 as actual prices received exceeded these minimum prices. The Company had five open contracts at December 31, 1996, covering 2,000,000 MMBtu of the natural gas production for February 1997, and 70,000 Bbls of oil production for the months of February and March 1997, providing for minimum prices of $2.00 per MMBtu and prices of $17.00 and $20.00 per Bbl. The costs related to the open contracts totaled approximately $127,000 and had a market value of $68,400 as of December 31, 1996.

Acquisition Activities

 

Since 1979, the Company has acquired approximately $469.0 million of producing oil and natural gas properties on behalf of itself and its co-investors in 124 separate transactions. The Company has acquired for its own account approximately $113.1 million of producing properties, with original proved reserves estimated at 148.4 Bcfe. The Company’s acquisition activities have declined over the past three years, with approximately $13.1 million, $3.5 million, and $1.5 million of properties acquired in 1994, 1995, and 1996, respectively. The Company’s acquisition costs have averaged $0.83 per Mcfe over this three-year period. For 1997 for its own account, the Company anticipates spending $3.0 million primarily 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.

Foreign Activities

 

Russia. On September 3, 1993, the Company signed a Participation Agreement with Senega, a Russian Federation joint stock company (in which the Company has an indirect interest of less than 1%), to assist in the development and production of reserves from two fields in Western Siberia providing the Company with a minimum 5% net profits interest from the sale of hydrocarbon products from the fields for providing managerial, technical, and financial support to Senega. Additionally, the Company purchased a 1% net profits interest from Senega for $300,000. In May 1995, the Company executed a Management Agreement with Senega, under which, in return for undertaking to obtain financing for development of these fields, Swift is entitled to receive a 49% interest in production income derived by Senega from this project after repayment of costs.

On July 12, 1996, the Company entered into a partnership agreement which provides for the Company to contribute its rights under the Participation and Management Agreement to the partnership and for the partners to share equally revenues and costs of developing the Samburg Field and funding and management of the license areas, all in conjunction with Senega. The partnership is to be funded by the partners upon fulfillment of certain conditions and completion of certain further arrangements with Senega. It is currently anticipated that any funding of these activities will be principally through project financing. At December 31, 1996, the Company’s investment in Russia was approximately $9,530,000 and is included in the unproved properties portion of oil and gas properties.

Venezuela. The Company formed a wholly owned subsidiary, Swift Energy de Venezuela, C.A., for the purpose of submitting a bid on August 5, 1993, under the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did not win the bids, it continued to pursue cooperative ventures involving other fields and opportunities in Venezuela. Currently, the Company is evaluating a number of Blocks being offered by Petroleos de Venezuela, S.A. under the Third Operating Agreement Round. At December 31, 1996, the Company’s investment in Venezuela was approximately $1,610,000 and is included in the unproved properties portion of oil and gas properties net of impairments of $45,668.

New Zealand. Since October 1995, the Company has been issued two Petroleum Exploration Permits by the New Zealand Minister of Energy. The first permit covers approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covers approximately 69,300 adjacent acres. Under the terms of these permits, the Company is obligated to analyze and interpret certain seismic data, acquire certain new seismic data, and drill one exploratory well, to be followed by a development well or additional seismic work, all of which is to be performed on a staged basis in order to maintain the permits over periods extending through July 2000 for the first permit and August 1999 for the second permit. At December 31, 1996, the Company’s investment in New Zealand was approximately $750,000 and is included in the unproved properties portion of oil and gas properties.

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, 1996, 1995, and 1994. 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, 1996, were estimated based upon weighted average prices of $4.47 per Mcf of natural gas and $23.75 per barrel of oil, compared to $2.41 and $1.85 per Mcf of natural gas and $18.07 and $15.09 per barrel of oil as of December 31, 1995 and 1994, respectively. Natural gas prices have declined significantly since December 31, 1996. Accordingly, the estimates of future net revenues from the Company’s proved reserves and the PV-10 Value would be reduced if subsequent gas prices were used. 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 1996, 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 1997 and thereafter will be made at an unrestricted level.

The Company’s total proved developed and undeveloped reserves have increased substantially (47%) at December 31, 1996, 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 1996 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. Three of the limited partnerships had achieved payout status at December 31, 1996.

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 26 service wells in 1996, 39 service wells in 1995, and 31 service wells in 1994.

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, 1996:

(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 portion of the Company’s acreage is owned by virtue 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, 1996, three of the limited partnerships had achieved payout status.

Partnerships

 

For many years, the Company relied on limited partnerships as its principal financing vehicle to fund its activities. The Company has formed 104 limited partnerships which have raised a total of approximately $485.3 million at December 31, 1996. 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.

During 1996, the limited partners in 18 partnerships, which had been in operation over nine years and have produced a substantial majority of their reserves, voted to sell their remaining properties and liquidate the limited partnerships. In 1996, 10 of the earliest public income partnerships were liquidated, and in early 1997 eight private drilling partnerships will be liquidated. The Company intends to make similar proposals to other partnerships for an orderly sale of their properties and liquidation of the partnerships over the next several years. The Company may offer to acquire certain portions of the remaining property interests owned by these limited partnerships.

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, 1996, eight partnerships had been formed (one in 1993, one in 1994, three in 1995, and three in 1996) with aggregate investor contributions of approximately $41.9 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.

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.

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 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 brief 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.

FERC Orders. Several major regulatory changes have been implemented by the Federal Energy Regulatory Commission ("FERC") from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry that remain subject to the FERC’s jurisdiction. In April 1992, the 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.

FERC Order No. 500 affects the transportation and marketability of natural gas. Traditionally, natural gas has been sold by producers to pipeline companies, which then resold the gas to end-users. FERC Order No. 500 alters this market structure by requiring interstate pipelines that transport gas for others to provide transportation service to producers, distributors and all other shippers of natural gas on a nondiscriminatory, "first-come, first-served" basis ("open access transportation"), so that producers and other shippers can sell natural gas directly to end-users. FERC Order No. 500 contains additional provisions intended to promote greater competition in natural gas markets.

It is not anticipated that the marketability of and price obtainable for the Company’s natural gas production will be significantly affected by FERC Order No. 500. Gas produced normally will be sold to intermediaries who have entered into transportation arrangements with pipeline companies. These intermediaries will accumulate gas purchased from a number of producers and sell the gas to end-users through open access transportation.

      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, 1996, the Company employed 191 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 75,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The lease requires payments of approximately $85,000 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.

Forward-Looking Information

 

The statements contained in this Annual Report on Form 10-K ("Annual Report") that are not historical facts, including, but not limited to, statements found in this Items 1 and 2. Business and Properties and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, and therefore involve a number of risks and uncertainties. The actual results of the future events described in such forward-looking statements in this Annual Report could differ materially from those stated in such forward-looking statements. Among the factors that could cause actual results to differ materially are: general economic conditions, competition and government regulations and fluctuations in oil and natural gas prices, as well as the risks and uncertainties discussed in this Annual Report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings, and public statements.

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Glossary of Abbreviations and Terms

 

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

Bbl — Barrel or barrels of oil.

Bcf — Billion cubic feet of natural gas.

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

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

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

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

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

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

MBbl — Thousand barrels of oil.

Mcf — Thousand cubic feet of natural gas.

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

MMBbl — Million barrels of oil.

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

MMcf — Million cubic feet of natural gas.

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

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

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

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

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

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

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

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

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