-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, O1w07BeEu6DpyVTd3U4bH8Iuejml/feO0M4spGkmT8gmtyEh3ivQlsLB7qW+gqK9 KF7yoFHPsSxGNSVhB8hkbA== 0000930661-97-000842.txt : 19970409 0000930661-97-000842.hdr.sgml : 19970409 ACCESSION NUMBER: 0000930661-97-000842 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970407 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: CODA ENERGY INC CENTRAL INDEX KEY: 0000356799 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 751842480 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 000-10955 FILM NUMBER: 97575612 BUSINESS ADDRESS: STREET 1: 5735 PINELAND DR STREET 2: STE 300 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2146921800 MAIL ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 FORMER COMPANY: FORMER CONFORMED NAME: CHAPMAN ENERGY INC DATE OF NAME CHANGE: 19891012 FORMER COMPANY: FORMER CONFORMED NAME: DALLAS SUNBELT ENERGY INC DATE OF NAME CHANGE: 19821116 10-K/A 1 FORM 10-K/A AMENDMENT #2 FORM 10-K\A NO.2 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) ----- OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 OR ----- TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-10955 CODA ENERGY, INC. (Name of Registrant) State of Delaware 75-1842480 (State of Incorporation) (IRS Employer Identification Number) 5735 PINELAND DRIVE SUITE 300 DALLAS, TEXAS 75231 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (214) 692-1800 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO ----- ----- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ---- As the Company's Common Stock is not traded on a public market, the market value held by non-affiliates is undeterminable. As of March 1, 1997, the Registrant had outstanding 913,611 shares of Common Stock. PART I Item 1. BUSINESS -------- GENERAL Coda Energy, Inc., an independent energy company, is principally engaged in the acquisition and exploitation of oil and natural gas properties. The Company also owns and operates natural gas processing and liquids extraction facilities and natural gas gathering systems. Unless the context otherwise requires, the term "Registrant" or "Coda" refers to Coda Energy, Inc. only and "Company" refers to Coda and its subsidiaries. The Company seeks to acquire oil and natural gas properties whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs and development of the properties. The Company's producing properties are concentrated in the mid-continent region of the United States. At December 31, 1996, the Company had proved reserves of 43.0 Mmbbls of oil and 39.0 Bcf of natural gas, aggregating 49.5 Mmboe. Company operated properties accounted for approximately 93% of its 1996 production of 3.5 Mmboe. The Company's strategy is to increase oil and natural gas reserves, production and cash flow by selectively acquiring and exploiting producing oil and natural gas properties, especially those properties with enhanced recovery and other lower-risk development potential. The Company's exploitation efforts include, where appropriate, the drilling of lower-risk development wells, the initiation of secondary recovery projects, the renegotiation of marketing agreements and the reduction of drilling, completion and lifting costs. Cost savings may be principally achieved through reductions in field staff and the more effective utilization of field facilities and equipment by virtue of geographic concentration. As a result of its acquisition and exploitation activities, the Company has shown significant growth in reserves, production and EBITDA (earnings before interest, income taxes and depletion, depreciation and amortization and in 1996 before non-cash stock option compensation expense) the last three years. Since January 1, 1994, the Company has purchased properties for an aggregate cost of $70.0 million. Proved reserves have increased from 36.1 Mmboe at January 1, 1994 to 49.5 Mmboe at December 31, 1996. The present value of estimated future net revenues of the Company's proved reserves discounted at 10% has increased from $217.5 million at December 31, 1994, to $447.9 million at December 31, 1996, while the Company received $107.5 million in oil and gas revenues, net of operating expenses during that period. Average net daily production has increased from 9,534 BOE in 1994 to 10,997 BOE for 1996. EBITDA increased at a 37% compound annual growth rate from $27.6 million in 1994 to $52.0 in 1996. The Company operated 2,265 of the 2,983 gross producing and water injection wells in which it owned an interest as of December 31, 1996. On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda, Joint Energy Development 1 Investments Limited Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per share in cash (for an aggregate purchase price of approximately $176.2 million). Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with members of management (the "Management Group"), providing for a continuing role of management in the Company after the Merger. Following consummation of the Merger, the Management Group owns approximately 5% of Coda's common stock on a fully-diluted basis. JEDI owns the remaining 95%. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. The Company was incorporated in 1981 as a Delaware corporation. The Company's executive offices are located at 5735 Pineland Drive, Suite 300, Dallas, Texas 75231 (telephone: (214) 692-1800). As of December 31, 1996, the Company had 159 full time employees. FORWARD-LOOKING STATEMENTS All statements in this document concerning the Company other than purely historical information (collectively "Forward-Looking Statements") reflect the current expectation of management and are based on the Company's historical operating trends, estimates of proved reserves and other information currently available to management. These statements assume, among other things, (i) that no significant changes will occur in the operating environment for the Company's oil and gas properties, gas plants and gathering systems and (ii) that there will be no material acquisitions or divestitures. The Company cautions that the Forward-Looking Statements are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for, oil and gas reserves. These risks include, but are not limited to, commodity price risk, environmental risk, drilling risk, reserve, operations and production risks, regulatory risks and counterparty risk. Many of these risks are described elsewhere herein. The Company may make material acquisitions or dispositions, enter into new or terminate existing oil and gas sales or hedging contracts, or enter into financing transactions. None of these can be predicted with any certainty and, accordingly, are not taken into consideration in the Forward-Looking Statements made herein. For all of the foregoing reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely. RECENT ACQUISITION ACTIVITIES In February 1997, the Company purchased 123 producing oil and gas properties from J. M. Huber Corporation for an aggregate purchase price of approximately $13.1 million, of which $6.5 million was financed under the Company's credit agreement. The properties are predominately located in Texas, Oklahoma and Arkansas. The Company estimates the properties have proved reserves of approximately 1.5 million barrels of oil and 13.0 Bcf of gas. 2 OIL AND GAS OPERATIONS DEVELOPMENT AND EXPLORATION GENERAL The Company concentrates on exploiting proved producing properties, including those with development potential, through workovers, recompletions in other productive zones, secondary recovery operations, the drilling of development wells or infill wells and other exploitation techniques. The Company has conducted or intends to conduct significant secondary recovery/infill drilling programs on many of its properties. Secondary recovery projects have represented the Company's primary development focus over the past four years. Generally, "secondary recovery" refers to methods of oil extraction in which fluid or gas (usually water, natural gas or CO//2//) is injected into a formation through input (injector) wells, and oil is removed from surrounding wells. "Waterflooding" is one proven method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing the oil out of the reservoir rock and into the bore of a producing well. Waterflood projects are engineered to suit the type of reservoir, depth and condition of the field. The Company has considerable experience with and actively employs waterflood techniques in many of its fields in order to stimulate production. The Company also seeks to exploit its properties through cost reduction measures, including the reduction of labor, electrical and materials costs. It seeks to take advantage of volume discounts in the purchase of equipment and supplies and more effectively utilize field facilities and equipment by virtue of its geographical concentration. The Company attempts to negotiate more favorable marketing agreements upon completion of an acquisition, particularly for oil production. Certain oil purchasers have paid in the past and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. The Company has budgeted capital spending of between $15 million and $20 million in 1997. The Company makes only limited investments in exploratory drilling. Several of the Company's more significant projects are discussed below. DEVELOPMENT PROJECTS CROOKED CREEK PROSPECT - The Company's study of the Cleveland reservoir in the Crooked Creek prospect began in early 1995. The Company acquired its first interest in the field in September 1995. Unitization efforts are currently underway. The leases the Company either owns or has commitments on will give the Company a 74% working interest in the proposed unit. 3 The proposed Crooked Creek Cleveland Unit ("CCCU") is located in Kingfisher County, Oklahoma, and contains 4,580 acres. The Company expects the CCCU to be effective May 1, 1997. Gross development capital expenditures will be approximately $5.3 million. CCCU will initially have six injection wells and 21 producing wells. Additional wells will be converted to injection as project performance dictates. The Company expects to drill two wells, convert two wells and install injection facilities during 1997 at a cost to the Company of approximately $2.4 million. OAKDALE REDFORK UNIT - In 1989 in its search for attractive secondary recovery candidates, the Company recognized the waterflood potential of the Red Fork sand in the Oakdale Field. The Company acquired its first interest in the field in May 1990 and continued to actively acquire additional interest through the April 1991 unitization and initial development stages of the project. The May 1995 acquisition of a 29.4% interest was the last acquisition of significant interest in the field. The Company currently has an 88.9% working interest in the project. The 3,560 acre Oakdale Red Fork Unit ("Oakdale") is located in southeastern Woods County, Oklahoma. The Unit currently has 19 injection wells and 22 producing wells. During December 1996 the average daily production was 1,756 barrels of oil with 766 barrels of water. The Company's plans for future development include the drilling of eleven wells over the next three years. Capital expenditures in 1997 are budgeted at approximately $1.5 million and anticipate the drilling of four wells, converting five wells and facilities improvements. ANDREWS UNIT - On January 1, 1993, the Company took over the operations of three leases in the Andrews Wolfcamp and Penn Fields. The Company recognized the waterflood potential of these fields and began acquiring offset leases. In July 1994, the Company purchased a 100% working interest in three adjacent properties with five active wells. In December 1994, the Company purchased a 100% working interest in two additional leases and a 93.8% working interest in a third lease. The Company acquired several additional minor leases in 1995. The last lease was purchased in July of 1996, during unitization of the field. The Andrews Unit located in Andrews County, Texas contains 3,280 acres. During the unitization process, the Company obtained approval to consolidate the two fields into the Wolfcamp/Penn field in August 1995. The Company has a working interest in 98.58% in Phase I and 97.96% in Phase II. The Company initiated a waterflood in this field in September 1996. The capital costs were dramatically reduced by modifying and expanding the existing injection facilities in the Shafter Lake San Andres Unit. The Andrews Unit produced 514 barrels of oil and 790 Mcf of gas per day from 25 wells on this Unit in December 1996. The Company plans to drill one well and convert six wells in 1997 at a cost to the Company of approximately $1.0 million. CALUMET COTTAGE GROVE UNIT - In its search for attractive waterflood candidates, the Company identified the potential of a Cottage Grove waterflood in the Calumet Field in 1990. The Company acquired its first interest in the field in May 1991 and continued to actively acquire additional interest 4 through the unitization and initial development stages of the project. The Company currently has a 44.1% working interest in the project. Unitization was accomplished in May 1992. The Calumet Cottage Grove Unit ("Calumet") is located in Canadian County, Oklahoma, and contains 11,400 acres. First injection was in August 1992. Initial response to injection occurred in December 1992 and peak production of approximately 3,500 barrels of oil occurred in January 1995. A fracture stimulation program has maintained Calumet production at approximately 2,900 barrels of oil per day for 1996. Calumet currently has 28 injection wells and 74 producing wells. December 1996 average daily production was 2,744 barrels of oil with 3,881 barrels of water. The Company's plans for future development include the drilling of nineteen wells and the conversion to injection of ten wells over the next four years. The Company expects to drill four wells, convert nine wells and improve facilities during 1997 at a cost to the Company of approximately $1.4 million. SHAFTER LAKE SAN ANDRES UNIT - On January 1, 1993, the Company became the operator of the Shafter Lake San Andres Unit ("SLSAU") in Andrews County, Texas by acquiring a 49% working interest in the SLSAU from the prior operator. This property was part of a large acquisition made from a major oil company. The Company has since increased its working interest to over 62% in eleven separate transactions. The SLSAU was unitized in 1967 and water injection began in 1968 on this 12,720 acre Unit. When the Company became the operator in January 1993, the SLSAU produced 728 barrels of oil and 150 Mcf of gas per day. In 1993, the Company expanded the east-west drive waterflood pattern by converting eight wells to water injection. The Company continued expanding this pattern in 1994, 1995 and 1996 by drilling 27 additional producing wells and converting 26 wells to water injection. In December 1996, average daily production was 881 barrels of oil and 280 Mcf of gas from 117 producing wells and 40 injection wells. The Company has identified 43 additional proven drilling locations as well as continued secondary response. During 1997, the Company plans to drill six wells and convert four wells at a cost to the Company of approximately $1.1 million. MARKETS, COMPETITION AND MARKETING The oil and natural gas industry is highly competitive. Competitors include major oil companies, other independent oil and natural gas concerns, and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those of the Company. In addition, the Company encounters substantial competition in acquiring oil and natural gas properties, marketing oil and natural gas and securing trained personnel. When possible, the Company tries to avoid open competitive bidding for acquisition opportunities. The principal means of competition with respect to the sale of oil and natural gas production are product availability and price. While it is not possible for the Company to state accurately its position in the oil and natural gas industry, the Company believes that it represents a minor competitive factor. 5 Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and the Company. Enron and certain of its subsidiaries and other affiliates collectively participate in nearly all phases of the oil and natural gas industry and are, therefore, competitors of the Company. Because of these various conflicting interests, ECT, the Company, JEDI and the Management Group have entered into the Business Opportunity Agreement which is intended to make it clear that Enron and its affiliates have no duty to make business opportunities available to the Company in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of the Company. The Business Opportunity Agreement may limit the business opportunities available to the Company. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which the Company will offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, the Company may be unable to pursue it. The market for oil, natural gas and natural gas liquids produced by the Company depends on factors beyond its control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, natural gas and natural gas liquids, the price of imports of oil and natural gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. The oil and natural gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. With the exception of the operations of Taurus Energy Corp. ("Taurus") (see "--Gas Plants and Gathering Systems Operations" below), the Company does not refine or process any of the oil and natural gas it produces. The Company's oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. The Company is currently able to sell, under contract or in the spot market, all of the oil and natural gas it is capable of producing at current market prices. Substantially all of the Company's oil and natural gas is sold under short term contracts or contracts providing for periodic price adjustments or in the spot market; therefore, its revenue streams are highly sensitive to changes in current market prices. Certain of the Company's oil purchasers have paid in the past and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. The Company's principal markets for natural gas are natural gas processing and marketing companies as opposed to end users. Oil prices have been subject to significant fluctuations over the past decade. Levels of production maintained by the Organization of Petroleum Exporting Countries member nations and other major oil producing countries are expected to continue to be a major determinant of crude oil price movements in the near term. The market price for natural gas has fluctuated significantly from month to month and year to year for the past several years. The Company cannot predict oil or gas price movements with any certainty. In an effort to reduce the effects of the volatility of the price of crude oil and natural gas on the Company's operations, management has adopted a policy of hedging oil and gas prices, on a portion 6 of the Company's production, whenever market prices are in excess of the prices anticipated in the Company's operating budget and profit plan through the use of commodity futures, options and swap agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Changes in Prices and Hedging Activities" and Note 11 of Notes to the Company's Consolidated Financial Statements. During the year ended December 31, 1994, sales of oil and natural gas to Amoco Production Company and EOTT Energy Operating Limited Partnership ("EOTT"), a subsidiary of Enron, accounted for 13% and 22%, respectively, of the Company's consolidated revenues. During the year ended December 31, 1995, sales of oil and natural gas to Amoco Production Company and EOTT accounted for 10% and 18%, respectively, of the Company's consolidated revenues. During the 319 day period ended December 31, 1996, sales of oil and gas to EOTT accounted for 20% of the Company's consolidated revenues. EOTT is a subsidiary of Enron and an affiliate of the Company, ECT and ECT Securities, Inc. See "Certain Transactions." Management believes that in the event this purchaser were to discontinue its purchases, the Company could quickly locate other buyers and, therefore, the loss of this purchaser would not have a material impact on the Company's financial condition or results of operations. However, short term disruptions could occur while the Company sought alternative buyers. REGULATION The Company's operations are affected from time to time in varying degrees by political develop ments and federal and state laws and regulations. In particular, oil and gas production operations and economics are or have been affected by price control, tax and other laws relating to the oil and gas industry, by changes in such laws and by changing administrative regulations. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil and gas industry and its individual members, compliance with which is often difficult and costly and some of which carry substantial penalties for the failure to comply. The Company cannot predict how existing regulations may be interpreted by enforcement agencies or court rulings, nor whether amendments or additional regulations will be adopted, nor what effect such changes may have on its business or financial condition. Federal Taxation -- The Federal government is continually proposing tax initiatives that may affect the oil and gas industry, including the Company. Due to the preliminary nature of these proposals, the Company is unable to determine what effect, if any, the proposals would have on product demand or the Company's results of operations. Environmental Laws -- The Company's management believes that its present operations substantially comply with applicable federal and state pollution control, toxic waste, and environmental protection laws and regulations. The Company also believes that such laws have had no material effect on the Company's operations to date, and that the cost of such compliance has not 7 been material. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require the Company to incur costs to remedy the discharge. The Company does not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. Nevertheless, no assurance can be given that environmental laws will not, in the future, adversely affect the Company's operations and financial condition. Pollution and similar environmental risks generally are not fully insurable. State Regulation -- The various states in which the Company conducts activities regulate the drilling, operation and production of oil and gas wells, such as the method of developing new fields, spacing of wells, the prevention and clean-up of pollution, and maximum daily production allowables based on market demand and conservation considerations. CERTAIN RISK FACTORS RELATING TO THE OIL AND GAS INDUSTRY During the last few years, the oil and gas industry has been affected by variations in supplies of crude oil and natural gas, which has tended to result in significant fluctuations in oil and natural gas prices and created difficulty in estimating future prices for such products. The Company is unable to predict the future stability or direction of either oil or natural gas prices. The Company's oil and gas business is subject to all of the operating risks normally associated with the exploration for and production of oil and gas, including blowouts, cratering, pollution and fires, each of which could result in damage to or destruction of oil and gas wells, formations, production facilities or properties, or in personal injury. In accordance with customary industry practices, the Company maintains insurance coverage limiting financial loss resulting from certain of these operating hazards. Losses and liabilities arising from uninsured or underinsured events could reduce revenues and increase costs to the Company. GAS PLANTS AND GATHERING SYSTEM OPERATIONS On April 29, 1994, the Company acquired by merger all of the issued and outstanding common stock of Taurus, in exchange for 1,500,000 shares of Coda's common stock, valued at approximately $7.3 million, and $3.25 million cash. Coda assumed existing Taurus indebtedness of approximately $9.75 million. Taurus operates three natural gas processing facilities and owns interests in approximately 700 miles of natural gas gathering systems primarily located in west central Texas. In July 1994, Taurus acquired ownership of the Shackelford gas processing plant and gathering system ("Shackelford"). Taurus had previously been operating the system and plant under operating leases. The plant is a 30,000 MCF per day capacity refrigerated lean oil absorption plant located near Putnam, Texas. In related transactions, Taurus entered into an agreement to sell 10,000 MMBTU per day to the former owner of Shackelford for a period of 48 months. Simultaneously, Taurus entered into a gas purchase agreement with an unrelated third party for similar quantities over the same term. Pricing under both the gas sales agreement and the gas purchase agreement is structured to allow Taurus to earn a margin on all volumes sold. These contracts will not be renewed when they expire 8 in July 1998. For the year ended December 31, 1996, Taurus received net proceeds under these contracts of approximately $1 million. In January 1995, Taurus acquired the remaining 42% interest in the Hamlin gas gathering system and gas processing plant ("Hamlin"). The Hamlin gathering system consists of about 450 miles of low pressure gathering lines and twelve compressor stations in Fisher, Cottle, Taylor, Stonewall, Jones, Haskell, King and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic process and has a processing capacity of 20,000 Mcf per day. Gas supply to the system consists almost entirely of high BTU casinghead gas. The Hamlin plant produces a demethanized stream which is delivered into a products pipeline. The following table shows certain financial data related to Taurus' gas gathering and processing operations, by source, for the periods indicated.
=================================================================================================== TAURUS ENERGY CORP. REVENUES (in thousands) =================================================================================================== Pro forma 47 days 319 days year ended ended ended Year ended December 31, February 16, December 31, December 31, ------------------------- ------------ ------------- ------------ (Unaudited) (Unaudited) 1994 1995 1996 1996 1996 ---- ---- ---- ---- ---- Gas Sales $12,261 $21,038 $3,487 $25,243 $28,730 Natural Gas Liquids Sales 7,771 14,597 1,862 14,283 16,145 Operating Margin 2,724 5,161 755 6,728 7,483 - ---------------------------------------------------------------------------------------------------
Sales and markets -- Taurus' two largest plants and gathering systems, Shackelford and Hamlin (See Item 2. Properties - GAS PLANTS AND GATHERING SYSTEMS), account for the majority of Taurus' revenue. Taurus sells its residue gas from Shackelford to a variety of large gas purchasers under short-term contracts at market sensitive prices. Residue gas from Shackelford can be delivered into either one of two major pipeline systems. These connections provide significant marketing flexibility by giving access to major marketing hubs in East Texas, West Texas and the Gulf Coast. Major gas consuming markets in California, the Midwest, the Northeast as well as along the Texas Gulf Coast can be 9 accessed through these market hubs. Generally residue gas is sold under short- term contracts either at the tailgate of the Shackelford plant or out of the intrastate pipeline. The Shackelford plant produces a demethanized stream which is delivered into a products pipeline. Ethane and natural gasoline components of the product stream are generally sold as they enter the pipeline. The remaining components of the product stream are then sold under short-term agreements to various customers at a central marketing point in Mont Belvieu, Texas. A transportation and fractionation fee is paid on all gallons not sold to the pipeline owner. Residue gas from Hamlin can be delivered into either Palo Duro Pipeline or Lone Star Gas Pipeline. These connections afford the Company the opportunity to offer residue gas from both Hamlin and Shackelford as a package which increases the marketing flexibility and leverage of both plants. Since assuming operation of Hamlin, all residue gas has been sold under short-term contracts at market sensitive prices to a variety of large purchasers. The Hamlin plant produces a demethanized stream which is delivered into a products pipeline. All of Hamlin's liquids production is being sold under agreements that provide for market index prices less a transportation and fractionation fee. Purchases -- Taurus purchases gas for Shackelford from approximately 250 wells in Shackelford, Callahan, Stephens and Throckmorton Counties. The majority of the production connected to the gathering system is low volume casinghead gas. The system is operated at low pressure with lateral line pressures ranging from 15 to 150 psi. The mainline pressure averages about 300 psi. Taurus utilizes two base forms of gas purchase agreements: percentage of proceeds and fixed price. Percentage contracts provide that the seller is allocated its proportionate share of residue gas sales and natural gas liquids production. Fixed price contracts, which generally provide for acreage dedications, are for primary terms of up to twenty years with annual renewals thereafter. The purchase price to be paid is stated in the contract and is subject to annual price redetermination if certain specific conditions are met. The gas connected to Shackelford is purchased primarily under percentage of proceeds contracts with some fixed price contracts. The majority of the gas connected to Hamlin is being purchased utilizing percent of proceeds contracts. There are about 200 gas purchase agreements covering over 450 wells connected to Hamlin. Item 2. PROPERTIES ---------- OIL AND GAS RESERVES For certain information concerning the Company's oil and gas reserves and estimates of future net revenues attributable thereto, see Note 14 of the Notes to Consolidated Financial Statements which comprise a part of this Annual Report on Form 10-K. 10 GENERAL The following tables summarize certain information regarding the estimated proved oil and gas reserves as of December 31, 1994, 1995, and 1996. Such estimated reserves and future net revenues, as set forth herein and in Note 14 of Notes to Consolidated Financial Statements which accompany this report, are based upon reports prepared by Lee Keeling and Associates, Inc., independent consulting petroleum engineers. All such reserves are located in the United States. All reserves are evaluated at contract temperature and pressure which can affect the measurement of natural gas reserves. Reserve estimates are imprecise and may be expected to change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Re serve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. The Company emphasizes with respect to the estimates prepared by independent petroleum engineers that the discounted future net cash inflows should not be construed as representative of the fair market value of the proved oil and gas properties belonging to the Company, since discounted future net cash inflows are based upon projected cash inflows which do not provide for changes in oil and gas prices nor for escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For further information, see Note 14 of Notes to Consolidated Financial Statements. 11 PROVED OIL AND GAS RESERVES The following table sets forth proved reserves considered to be economically recoverable under normal operating methods and existing conditions, at prices and operating costs prevailing at the date thereof.
============================================================================= PROVED OIL AND GAS RESERVES (000's omitted) ============================================================================= December 31, --------------------------------------------------- 1994 1995 1996 --------------- --------------- --------------- Oil Gas Oil Gas Oil Gas (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) ------ ------ ------ ------ ------ ------ Proved Developed Reserves........... 20,151 32,890 25,877 31,496 33,895 33,255 Proved Undeveloped Reserves........... 19,056 6,918 16,713 5,634 9,142 5,790 ------ ------ ------ ------ ------ ------ Total Proved Reserves........... 39,207 39,808 42,590 37,130 43,037 39,045 ====== ====== ====== ====== ====== ====== - -----------------------------------------------------------------------------
Definition of Reserves -- The reserve categories are summarized as follows: Proved developed reserves are those quantities of crude oil, natural gas ------------------------- and natural gas liquids which, upon analysis of geological and engineering data, are expected with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. This classification includes: (a) proved developed producing reserves which are -------------------------- those expected to be recovered from currently producing zones under continuation of present operating methods; and (b) proved developed non-producing reserves ------------------------------ which consist of (i) reserves from wells which have been completed and tested but are not yet producing due to lack of market or minor completion problems which are expected to be corrected, and (ii) reserves currently behind the pipe in existing wells which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the well. Proved undeveloped reserves are those reserves which may be expected either --------------------------- from existing wells that will require a major expenditure to develop or from undrilled acreage adjacent to productive units which are reasonably certain of production when drilled. No major discovery or other favorable or adverse event is believed to have caused a significant change in these estimates of the Company's proved reserves since January 1, 1997. 12 Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves", filed with the United States Department of Energy, no other estimates of total proven net oil and gas reserves have been filed by the Company with, or included in any report to, any United States authority or agency pertaining to the Company's individual reserves since the beginning of the Company's last fiscal year. Reserves reports in Form EIA 23 are comparable to the reserves reported by the Company herein. OIL AND GAS OPERATIONS DATA The following table sets forth the total gross and net productive wells in which the Company owned an interest as of December 31, 1996. The oil well category includes 599 gross and 439 net active water injection and utility wells which are necessary for the operation of the Company's waterflood projects.
======================================== PRODUCTIVE WELLS ======================================== Gross/1/ Net/1/ ---------- ---------- Oil Gas Oil Gas ----- --- ----- --- Texas 2,396 17 1,829 9 Oklahoma 468 24 280 9 Kansas 67 6 62 4 Other 5 -- 1 -- ----- --- ----- --- 2,936 47 2,172 22 ===== === ===== === ----------------------------------------
1 The number of gross wells is the total number of wells in which a fractional working interest is owned. The number of net wells is the sum of the fraction al working interests owned by the Company in gross wells. Includes wells with multiple completions. The following table shows the net production attributable to the Company's oil and gas interests, the average sales price per barrel of oil and Mcf of natural gas and the average production and depletion, depreciation and amortization expenses attributable to the Company's oil and gas production for the periods indicated. 13
====================================================================================== PRODUCTION ECONOMICS ====================================================================================== 47 days 319 days Pro forma Year ended ended ended year ended December 31, February 16, December 31, December 31, -------------- 1994 1995 1996 1996 1996/ 1/ ------ ------ ------ ------ --------- Oil and Gas Production - ---------------------- Oil (MBbls) 2,650 3,165 405 2,974 3,379 Natural Gas (MMcf) 4,982 4,416 500 3,310 3,810 Average Sales Prices/2/ - ----------------------- Oil (Per Bbl) $15.86 $17.08 $17.57 $20.58 $20.22 Natural Gas (Per Mcf) 1.74 1.57 1.82 2.28 2.22 Average Production - ------------------ Cost/3/ ------- Per BOE/4/ $6.22 $6.95 $7.34 $8.11 $8.01 Per dollar of sales .43 .44 .44 .42 .42 Depletion, Depreciation - ----------------------- and Amortization ---------------- Per BOE/4/ $4.27 $4.33 $4.40 $5.89 $5.90 Per dollar of sales .29 .28 .27 .30 .31 - --------------------------------------------------------------------------------------
1 See Notes 1 and 2 of Notes to Consolidated Financial Statements 2 Before deduction of production taxes and net of hedging results for the periods shown. 3 Excludes depletion, depreciation and amortization. Production cost includes lease operating expenses and production and ad valorem taxes, if applicable. 4 Gas production is converted to equivalent barrels of oil at the rate of six Mcf of natural gas per barrel, representing the estimated relative energy content of natural gas and oil. 14 DRILLING ACTIVITIES The following tables set forth the results of the Company's drilling activities (wells completed or abandoned as of fiscal period end) for the periods covered. In January and February 1997, the Company drilled one well. There were no wells drilled during the 47-day period ended February 16, 1996.
====================================================================== DRILLING ACTIVITIES ====================================================================== 319 days Year ended December 31, ended ---------------------------------- December 31, 1994 1995 1996 ---------------- ---------------- ---------------- Gross/1/ Net/1/ Gross/1/ Net/1/ Gross/1/ Net/1/ -------- ------ -------- ------ -------- ------ Exploratory: Oil -- -- -- -- -- -- Gas 1 0.38 2 0.75 -- -- Dry -- -- -- -- -- -- -- ----- --- ----- -- -- Total 1 0.38 2 0.75 -- -- == ===== === ===== == == Development: Oil 26 12.07 109 98.88 21 17 Gas -- -- -- -- 4 2 Dry -- -- -- -- -- -- -- ----- --- ----- -- -- Total 26 12.07 109 98.88 25 19 == ===== === ===== == == Total: Oil 26 12.07 109 98.88 21 17 Gas 1 0.38 2 0.75 4 2 Dry -- -- -- -- -- -- -- ----- --- ----- -- -- Total 27 12.45 111 99.63 25 19 == ===== === ===== == == ----------------------------------------------------------------------
1 The number of gross wells is the total number of wells in which a fractional working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed in whole numbers and decimal fractions thereof. For purposes of the table above an "exploratory well" is a well drilled to find and produce oil or gas in an unproved area, to find a reservoir in a field previously found to be productive of oil or gas in 15 another reservoir or to extend a known reservoir. A "development well" is a well drilled within the proven boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive. A "dry well" is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. DEVELOPED AND UNDEVELOPED ACREAGE The following table sets forth the approximate gross and net acres of productive properties in which the Company owned a leasehold interest as of December 31, 1996. "Gross" acres refers to the total acres in which the Company has a working interest, and "net" acres refers to the fractional working interests owned by or attributable to the Company multiplied by the gross acres in which the Company has a working interest. Developed acreage is that acreage spaced or assignable to productive wells. Undeveloped acreage is considered to be that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. At December 31, 1996, the Company had no significant amount of undeveloped acreage.
============================== LEASEHOLD ACREAGE ============================== Developed --------------- Gross Net ------- ------ Texas 48,273 24,940 Oklahoma 95,315 54,492 Kansas 16,359 13,872 Other 5,317 1,817 ------- ------ Total 165,264 95,121 ======= ====== ------------------------------
Essentially all of the Company's oil and gas interests are leasehold working interests or overriding royalty interests under standard on-shore oil and gas leases, rather than mineral or fee interests. GAS PLANTS AND GATHERING SYSTEMS Taurus owns and operates three natural gas processing facilities and owns approximately 700 miles of natural gas gathering systems primarily located in west central Texas. One of the plants was acquired in 1991 and is not significant in size. The other two plants are discussed below. In July 1994, Taurus acquired ownership of Shackelford, which previously had been operated by Taurus under operating leases for approximately five years. Shackelford consists of approximately 16 250 miles of pipeline located in Shackelford, Callahan, Stephens and Throckmorton Counties, Texas. The plant is a 30,000 MCF per day capacity refrigerated lean oil absorption plant located near Putnam, Texas. The Shackelford plant produces a demethanized stream which is delivered into a products pipeline. The steel gathering lines range in size from 3 inches to 10 inches in diameter. There are over 100 purchase, check and sales meters. The system utilizes 20 compressors with over 4,500 total horse power. In January 1995, Taurus acquired the remaining 42% interest in the Hamlin. The Hamlin gathering system consists of about 450 miles of low pressure gathering lines and twelve compressor stations in Fisher, Stonewall, Jones, Haskell, King and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic process and has a processing capacity of 20,000 MCF per day. Gas supply to the system consists almost entirely of high BTU casinghead gas. The Hamlin plant produces a demethanized stream which is delivered into a products pipeline. OTHER PROPERTIES The Company owns or has interests in numerous oil and gas production facilities relating to its oil and gas production operations. In addition, the Company owns or leases office space and other properties for its operations. In December 1992, the Company purchased a building in Dallas, Texas, containing approximately 65,000 square feet to serve as its corporate headquarters. The Company currently occupies approximately two-thirds of the office space and has made the balance available for lease. 17 SIGNATURES Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CODA ENERGY, INC. (Registrant) By: /s/ Grant W. Henderson ---------------------------------- Grant W. Henderson Chief Financial Officer DATE: April 4, 1997 18 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated. Name Capacities - ------------------------------ ----------------------- Chairman of the Board and Chief /s/ Douglas H. Miller* Executive Officer - ------------------------------ Douglas H. Miller President, Chief Financial Officer (Principal Financial and Accounting /s/ Grant W. Henderson Officer) and Director - ------------------------------ Grant W. Henderson Vice Chairman of the Board and Chief /s/ Jarl P. Johnson* Operating Officer - ------------------------------ Jarl P. Johnson* /s/ Richard B. Buy* Director - ------------------------------ Richard B. Buy /s/ Timothy J. Detmering* Director - ------------------------------ Timothy J. Detmering /s/ James V. Derrick, Jr.* Director - ------------------------------ James V. Derrick, Jr. /s/ C. John Thompson* Director - ------------------------------ C. John Thompson * Executed on behalf of the indicated person by Douglas H. Miller, duly appointed attorney-in-fact. By: /s/ Grant W. Henderson --------------------------- Granr W. Henderson Attorney-in-fact 19 -----END PRIVACY-ENHANCED MESSAGE-----