-----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, IpExmV9MukKOJfwMtRycGDL8u1WZglPws3VHFFyano/DOBPml7cmIBajl2pdnTok 42t99A5ZKr8UAnIkOdztUg== 0000930661-97-000751.txt : 19970401 0000930661-97-000751.hdr.sgml : 19970401 ACCESSION NUMBER: 0000930661-97-000751 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970331 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 SEC ACT: 1934 Act SEC FILE NUMBER: 000-10955 FILM NUMBER: 97568692 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 1 FORM 10-K Form 10-K 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. TABLE OF CONTENTS ----------------- Item Page - ---- ---- PART I ITEM 1. BUSINESS General..................................................... 1 Recent Acquisition Activities............................... 2 Oil and Gas Operations...................................... 3 Gas Plants and Gathering System Operations.................. 8 ITEM 2. PROPERTIES Oil and Gas Reserves........................................ 10 Oil and Gas Operations Data................................. 13 Drilling Activities......................................... 15 Gas Plants and Gathering Systems............................ 16 Other Properties............................................ 17 ITEM 3. LEGAL PROCEEDINGS............................................. 17 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS....................................................... 17 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS............................... 18 ITEM 6. SELECTED FINANCIAL DATA....................................... 18 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General..................................................... 19 Results of Operations....................................... 20 Changes in Prices & Hedging Activities...................... 24 Liquidity and Capital Resources............................. 26 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................................................... 31 i ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................................................... 31 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............ 31 ITEM 11. EXECUTIVE COMPENSATION........................................ 31 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................................... 31 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................ 31 The information required by Part III of this report was filed March 31, 1997 under Form 10K/A No. 1. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K....................................... 32 SIGNATURES.................................................... 39 ii 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 2,009 of the 2,713 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 Investments Limited Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade Resources 1 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 74% working interest in the proposed unit. 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 3 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 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 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. 4 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 Unit 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 and 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. 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 5 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 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 6 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 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 7 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 in July 1998. For the year ended December 31, 1996, Taurus received net proceeds under these contracts of approximately $1 million. 8 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 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. 9 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. Reserve 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 506 gross and 382 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 2,376 17 1,802 9 Oklahoma 254 17 155 6 Kansas 67 6 62 4 Other 5 -- 1 -- ----- --- ----- --- 2,673 40 2,020 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 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 ================================================================================================ | Pro forma 47 days | 319 days year Year ended December 31, ended | ended ended ----------------------- 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 17 15 Gas -- -- -- -- 4 2 Dry -- -- -- -- -- -- -- ----- --- ----- -- -- Total 26 12.07 109 98.88 21 17 == ===== === ===== == == Total: Oil 26 12.07 109 98.88 17 15 Gas 1 0.38 2 0.75 4 2 Dry -- -- -- -- -- -- -- ----- --- ----- -- -- Total 27 12.45 111 99.63 21 17 == ===== === ===== == == - --------------------------------------------------------------------
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. Item 3. LEGAL PROCEEDINGS ----------------- The Company is a defendant or codefendant in minor lawsuits that have arisen in the ordinary course of business. The Company does not expect any of these to have a material adverse effect on the Company's consolidated financial position. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS --------------------------------------------------- Not Applicable. 17 PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS --------------------------------------------------------------------- Not Applicable Item 6. SELECTED FINANCIAL DATA ----------------------- The following table sets forth for the period indicated selected historical and pro forma financial data of the Company. The selected historical financial data as of and for the five periods ended December 31, 1996 have been derived from the historical financial statements of the Company, which were audited by Ernst & Young LLP, independent auditors. The selected financial data as of and for the period ended February 16, 1996 has been derived from the unaudited consolidated financial statements of the Company. The pro forma selected financial data is derived from the pro forma information contained in the Company's Consolidated Financial Statements (Notes 1 and 2) included elsewhere herein. The Selected Financial Data reflects revenues and earnings since the of acquisition of various assets that materially affect comparability with prior years. See Note 4 of Notes to Consolidated Financial Statements. As a result of the Merger Agreement, JEDI acquired Coda effective February 1, 1996. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's 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. On September 30, 1994, the Company acquired by merger all of the issued and outstanding stock of Diamond Energy Operating Company and Diamond A Inc. (collectively, "Diamond"). The merger with Diamond has been accounted for as a pooling of interests. Accordingly, the merger of the equity interests has been given retroactive effect in the accompanying data for periods prior to the merger to represent the combined activities of the previously separate entities. 18 The information below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the notes thereto, included elsewhere in this report.
=========================================================================================================================== SELECTED FINANCIAL DATA (IN THOUSANDS) =========================================================================================================================== Predecessor | Successor ---------------------------------------------------------------------------------------- Year Year Year Year 47 days | 319 days Pro forma ended ended ended ended ended | ended year ended 12/31/92 12/31/93 12/31/94 12/31/95 2/16/96 | 12/31/96 12/31/96/(1)/ --------- --------- --------- --------- -------- | --------------- ------------- | Revenues $ 23,637 $ 40,050 $ 71,586 $ 97,838 $ 13,569 | $ 110,382 $ 123,951 Income (loss) available for | common stockholders (734) 2,334 3,329 5,755 (1,298) | (51,027)/(2)/ 1,278 Total assets at end of period 82,226 132,754 203,102 229,064 226,266 | 295,570 295,570 Long-term debt at end of period 56,563 59,651 105,063 123,907 122,290 | 174,966 174,996 15% cumulative preferred stock --- --- --- --- --- | 20,000 20,000 - ---------------------------------------------------------------------------------------------------------------------------
/(1)/ Reflects the pro forma effect of the Merger, the sale of the Notes and the application of the proceeds thereof to retire $100 million of debt to JEDI and pay down a portion of the outstanding borrowings under the Company's credit facility. See Notes 1 and 2 of Notes to Consolidated Financial Statements. The pro forma results of operations exclude a charge of approximately $53.3 million (net of related deferred taxes of $30.0 million) representing the adjustment of the carrying value of proved oil and gas properties pursuant to the full cost method of accounting. /(2)/ Includes a charge of $53.3 million (net of related deferred taxes of $30.0 million) for the writedown of oil and gas properties. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS ----------------------------------------------------------------------- OF OPERATIONS ------------- The Company is an independent energy company principally engaged in the acquisition and exploitation of producing oil and natural gas properties. The Company also owns and operates natural gas processing and liquids extraction facilities and natural gas gathering systems. Coda seeks to acquire 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 properties. 19 The Company's principal strategy is to increase oil and natural gas reserves 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. Coda'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. The Company expects to continue its efforts to acquire additional oil and natural gas properties. Future acquisitions, if any, would necessitate, in most cases, borrowing additional funds under the Company's credit facility. The ability to borrow such funds is dependent upon the Company's borrowing base from time to time and the effect upon the borrowing base under the Credit Agreement. 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 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). The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's 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. RESULTS OF OPERATIONS The following table sets forth certain operating data regarding the production and sales volumes, average sales prices, and costs associated with the Company's oil and gas operations and gas gathering and processing operations for the periods indicated. 20
Pre-Merger | Post Merger --------------------------------------------------------- Year Ended 47 Days | 319 Days Pro Forma -------------------------- Ended | Ended Year Ended December 31, December 31, February 16, | December 31, December 31, 1994 1995 1996 | 1996 1996 ------------ ------------ ------------ | ------------ ------------ | OIL AND GAS OPERATING DATA: | Net production: | Oil (MBbls) 2,650 3,165 405 | 2,974 3,379 Gas (MMcf) 4,982 4,416 500 | 3,310 3,810 | Average sales price: | Oil (per Bbl) $15.86 $17.08 $17.57 | $20.58 $20.22 Gas (per Mcf) $1.74 $1.57 $1.82 | $2.28 $2.22 | Average production cost | per BOE $6.22 $6.95 $7.34 | $8.11 $8.01 | GAS GATHERING AND PROCESSING OPERATING DATA: | Sales: | Gas sales (MMBTU) 6,725 13,356 1,555 | 10,768 12,323 Gas sales average price $1.82 $1.58 $2.24 | $2.34 $2.33 Natural gas liquids sales | (Mgallons) 26,193 53,284 5,868 | 37,957 43,825 Natural gas liquids | average price $.2967 $.2739 $.3127 | $.3763 $.3684 | Costs and expenses (in thousands): | Gas purchases $15,121 $26,547 $4,060 | $29,177 $33,237 Plant operating $2,203 $3,926 $507 | $3,648 $4,155
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1995 (HISTORICAL) AND 1996 (PRO FORMA) The unaudited pro forma combined information was prepared as if the Merger and the issuance of $110.0 million of 10 1/2% Senior Subordinated Notes (the "Notes") had occurred on January 1, 1996. The unaudited pro forma information was prepared by combining the two 1996 periods and giving effect to adjustments affecting (i) depletion, depreciation and amortization, (ii) interest expense, (iii) income taxes and (iv) certain other costs resulting from the Merger as more fully outlined in Notes 1 and 2 of the Notes to Consolidated Financial Statements. The comparisons below compare the unaudited pro forma combined information to historical information for 1995. Oil and gas sales for the year ended December 31, 1996, increased 26% to approximately $76.8 million from approximately $61.0 million in the comparable period in 1995 primarily due to a 7% increase in oil production and an increase of $3.14 per barrel and $.65 per Mcf in the average sales price of oil and gas, respectively. The increase in production is a result of the acquisition of producing oil and gas properties in the fourth quarter of 1995, the Company's development drilling program and 21 favorable responses from certain of the Company's waterflood units. This increase was partially offset by a 14% decrease in gas production due primarily to sales of properties and natural production declines. During the year ended December 31, 1996, 89% of oil and gas sales was attributable to oil production. Oil and gas prices remain unpredictable. See "- Changes in Prices and Hedging Activities" below. Gas gathering and processing revenues for the year ended December 31, 1996 increased 26% to approximately $44.9 million from approximately $35.6 million in the comparable period in 1995 primarily due to a 47% and a 35% increase in the average sales price for natural gas and natural gas liquids, respectively. This increase was partially offset by an 18% decrease in natural gas liquids volumes due to reduced plant throughput volumes as a result of the termination of a gas purchase contract in January 1996 and production declines. Other income for the year ended December 31, 1996 increased 91% to approximately $2.3 million from approximately $1.2 million for the same period in 1995 primarily due to an increase in interest income of $382,000 from the investment of higher available cash balances and gains on sales of marketable securities of $701,000. Oil and gas production expenses (including production taxes) for the year ended December 31, 1996 increased 19% to approximately $32.2 million from approximately $27.1 million for the same period in 1995, reflecting the effects of the increased production from the properties acquired in 1995 and from new wells drilled. Oil and gas production expenses for the year ended December 31, 1996 were $8.01 per BOE and are expected to remain near this level for 1997. Gas gathering and processing expenses for the year ended December 31, 1996 increased 23% to approximately $37.4 million from approximately $30.5 million in the comparable period in 1995 due primarily to an increase in the purchase price paid to producers. Gas gathering and processing purchases usually fluctuate in ratio with gas gathering and processing revenues. Pro forma depletion, depreciation and amortization expense for the year ended December 31, 1996, increased 39% to approximately $27.4 million from approximately $19.7 million for the historical period in 1995 reflecting the increase in the carrying value of the Company's assets as a result of the Merger, the increase in oil production from acquisitions in 1995 and property development. Oil and gas depletion, depreciation and amortization expense increased from $4.33 per BOE for the year ended December 31, 1995, to $5.90 per BOE on a pro forma basis for the year ended December 31, 1996. The Company anticipates that the depletion, depreciation and amortization rate per BOE will be approximately $5.75 for 1997 absent significant additional acquisitions or significant reserve revisions. General and administrative expenses for the year ended December 31, 1996 decreased 17% to approximately $2.4 million from approximately $2.9 million in the comparable period in 1995. This is primarily due to increased overhead charges billed to working interest owners on the properties acquired in 1995, being partially offset by additional employees needed as a result of acquisitions of 22 oil and gas properties. The Company expects base general and administrative expenses, net of overhead recoveries, to remain near this level, absent significant additional acquisitions. Pro forma interest expense for the year ended December 31, 1996 increased 96% to approximately $17.0 million from approximately $8.7 million for the historical period in 1995, primarily due to increases in outstanding debt levels as a result of the Merger which reduced the Company's bank debt by approximately $37.0 million, but added $110.0 million of senior subordinated debt bearing interest at 10 1/2%. Also contributing to the increase were amounts borrowed during 1995 to fund development drilling and property acquisitions which would have been outstanding for a full year in 1996. The historical results of operations for the period ended February 16, 1996, include approximately $3.2 million of stock option compensation expense as a result of the replacement of certain outstanding options and warrants with new options subject to a lower exercise price. The historical results for the period ended December 31, 1996 include a writedown of oil and gas properties of approximately $83.3 million to the full cost pool ceiling based on product prices at the date of the Merger. Pro forma net income for the year ended December 31, 1996, was approximately $4.5 million compared to approximately $5.8 million for the historical period in 1995. This decrease resulted primarily from increases in depletion, depreciation and amortization and interest expense as a result of the Merger partially offset by an increase in oil production and higher oil and natural gas prices. COMPARISON OF THE YEARS ENDED DECEMBER 31, 1994 AND 1995 Oil and natural gas sales for the year ended December 31, 1995 increased 20% to approximately $61.0 million from approximately $50.7 million in 1994 primarily due to a 19% increase in oil production and an increase of $1.22 per barrel in the average sales price for oil. The increase in production was a result of the acquisition of producing oil and natural gas properties during the fourth quarters of 1994 and 1995, the Company's development drilling program and favorable responses from certain of the Company's waterflood units. This increase was partially offset by an 11% decrease in natural gas production (due primarily to sales of properties) and a decrease in the average sales price for natural gas of $0.17 per Mcf. During the year ended December 31, 1995, 89% of oil and natural gas sales was attributed to oil production. Oil and natural gas prices remain unpredictable. See "--Changes in Prices and Hedging Activities." As a result of the acquisition of Taurus on April 29, 1994, gas gathering and processing revenues, expenses and gross profit increased significantly for the year ended December 31, 1995, compared to 1994. The year ended December 31, 1994 only included eight months of Taurus' operations. Contributing to the increases in revenues and expenses was the acquisition in January 1995 of the remaining ownership interest in one of Taurus' gas plants and associated facilities for $6.5 million, The levels of revenues and expenses attributed to Taurus' operations are largely dependent on natural gas and natural gas liquids prices and plant throughput volumes and, therefore, may fluctuate significantly. 23 Oil and natural gas production expenses (including production taxes) for the year ended December 31, 1995 increased 25% to approximately $27.1 million from approximately $21.6 million for 1994, reflecting the effects of the increased production from the properties acquired in 1994 and from new wells drilled. Oil and natural gas production expenses for the year ended December 31, 1995 were $6.95 per BOE. Depletion, depreciation and amortization expense for the year ended December 31, 1995 increased 20% to approximately $19.7 million from approximately $16.4 million for 1994, reflecting the increase in oil production from acquisitions in 1994, property development and the acquisition of Taurus in April 1994. The increase attributable to Taurus was approximately $1.2 million. Oil and natural gas depletion, depreciation and amortization expense increased to $4.33 per BOE for the year ended December 31, 1995 from $4.27 per BOE for 1994. The increase reflects the relatively higher purchase price of the reserves related to the properties acquired during 1994. General and administrative expenses for the year ended December 31, 1995 decreased to approximately $2.9 million from approximately $3.1 million for 1994. This decrease was primarily due to increased overhead charges billed to working interest owners on the properties acquired during the fourth quarter of 1994 and 1995, being partially offset by additional employees needed as a result of acquisitions of oil and natural gas properties and the acquisition of Taurus. Interest expense for the year ended December 31, 1995 increased 64% to approximately $8.7 million from approximately $5.3 million for 1994, primarily due to increases in outstanding debt levels used to fund development drilling, oil and natural gas property acquisitions and the acquisition of Taurus and related assets, and higher market interest rates in 1995. Business combination expenses of $1.8 million in 1994 were related to the acquisition of Diamond pursuant to a merger. The merger with Diamond was accounted for as a pooling of interests and accordingly the transaction costs were expensed when incurred. Net income for the year ended December 31, 1995 increased to approximately $5.8 million from approximately $3.3 million for 1994, primarily due to (i) an increase in oil production from the Company's waterflood units, the Company's development drilling program and the oil and natural gas property acquisitions during the fourth quarters of 1994 and 1995, (ii) an increase in the average sales price of oil by $1.22 per barrel and (iii) the lack of business combination expenses in 1995. CHANGES IN PRICES AND HEDGING ACTIVITIES Annual average oil and natural gas prices have fluctuated significantly over the past three years. The Company's weighted average oil price per Bbl during 1996 and at December 31, 1996, was $20.22 and $24.88, respectively. For the year ended December 31, 1996, the Company averaged $1.80 per barrel less (including an oil hedging price decrease of $.92 per barrel) and $.29 per Mcf less for its oil and natural gas sales, respectively, than the average NYMEX prices for the same period. 24 On March 17, 1997, the NYMEX closing price for the near month for oil and natural gas was $20.92 per barrel and $1.91 per Mcf, respectively. Pursuant to the loan agreements with Diamond's former primary lender, Diamond entered into an agreement with a refining and marketing company to sell a fixed number of barrels attributable to its share of production of liquid hydrocarbons from certain formerly secured properties at a price of $15.25 per barrel. The effect of this contract was to lower the Company's 1995 and 1996 oil revenues by approximately $1.0 million ($.32 per barrel) and $123,000 ($.04 per barrel), respectively. The commitment under this agreement was fulfilled during February 1996. In an effort to reduce the effects of the volatility of the price of oil and natural gas on the Company's operations, management has adopted a policy of hedging oil and natural gas prices, on a portion of the Company's production, through the use of commodity futures, options, and swap agreements whenever market prices are in excess of the prices anticipated in the Company's operating budget and profit plan. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. All hedging is accomplished pursuant to exchange-traded contract or master swap agreements based upon standard forms. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. Credit risk related to hedging activities, which is minimal, is managed by requiring minimum credit standards for courterparties, periodic settlements and mark-to-market valuations. The Company has not historically been required to provide any significant amount of collateral in connection with its hedging activities. The Company has hedged 735,000 barrels at a weighted average NYMEX price of $19.13 for the year ending December 31, 1997 under various swap agreements entered into as of December 31, 1996. As of December 31, 1996, the Company had open positions for sold call options covering 25,000 Bbls of oil per month at an option price of $20.00 per Bbl for the period from January to August 1997. Under the standard form swap and option agreements, in use by the Company, the Company's revenues will be limited when the NYMEX prices exceeds the strike price. The total potential reduction in revenues is equal to the difference between the swap prices and the NYMEX price for the production month hedged multiplied by the number of barrels swapped. To the extent this amount exceeds the credit limit established by the counterparty, the Company may be required to utilize cash to fund a margin account. The Company has not historically had to fund a margin account. During the year ended December 31, 1995 the Company's oil revenues were increased by $298,000 as a result of hedging transactions. During the periods ended February 16, 1996 and December 31, 1996 the Company's oil revenues were decreased by $14,000 and $3.1 million, respectively, as a result of hedging transactions. In connection with two swaps beginning January 1, 1997 covering 10,000 barrels per month and 15,000 barrels per month at a strike price of $19.41 and $19.00, respectively, which expire June 30, 1997 and December 31, 1997, respectively, the Company granted the counterparty a one day option at the expiration of the swap to extend the swap under the same terms for an additional twelve months. 25 LIQUIDITY AND CAPITAL RESOURCES At December 31, 1996, the Company had cash and cash equivalents aggregating approximately $8.0 million and working capital of approximately $6.9 million. Cash provided by operating activities for the year ended December 31, 1996 increased to approximately $38.3 million compared to $24.3 million for the comparable period in 1995 due primarily to an increase in oil production and an oil price increase partially offset by an increase in interest expense. An increase in accrued interest accounts for $3.0 million of the increase in cash provided by operating activities. Excluding the impact of the Merger, cash flows used in investing activities decreased from $43.0 million for the year ended December 31, 1995 to $14.1 million for the comparable period in 1996, as a result of a higher level of additions to property and equipment in 1995. Investing activities in 1996 also include the impact of the purchase of Coda by JEDI. Cash flows provided by financing activities increased to $159.3 million for the year ended December 31, 1996 from $16.9 million for the comparable period in 1995, primarily due to financing transactions related to the Merger. See " --The Merger" below. The Company has two principal operating sources of cash: (i) net oil and gas sales from its oil and gas properties and (ii) net margins earned from gas gathering and processing operations. The Company expects to continue its efforts to acquire additional oil and gas properties. Future acquisitions, if any, would necessitate, in most cases, borrowing additional funds under the Company's credit facility. The ability to borrow such funds is dependent upon the Company's borrowing base from time to time and the effect upon the borrowing base of the properties to be acquired. The Company from time to time solicits bids for selected portions of its existing oil and natural gas properties which it believes are no longer suitable for its business strategy. Sales of properties in the past three years have not been material and no substantial sales of oil and gas properties are currently under negotiation. Coda is continuing to study alternatives for maximizing the value of its investment in Taurus. The Company has development drilling programs designed for all its major operating areas. The Company has a revised capital spending budget of between $15 million and $20 million in 1997, excluding property acquisitions, but is not contractually committed to expend these funds. In addition, the Company is continuing to evaluate oil and natural gas properties for future acquisitions. Historically, the Company has used the public equity market (i) to raise cash to fund acquisitions or repay indebtedness incurred for acquisitions and (ii) as a medium of exchange for other companies' capital stock or assets in connection with acquisitions. As a result of being 95% owned by JEDI (on a fully diluted basis), the Company does not expect to utilize the public equity market to finance acquisitions in the near term. Accordingly, any material expenditures in connection with acquisitions would require borrowing under the Company's credit facility or from other sources. There can be no assurance that such funds will be available to the Company. Furthermore, the Company's ability to borrow in the future is subject to restrictions imposed by the Company's credit facility and the indenture governing the Notes (the "Indenture") as more fully described below. 26 The Merger On February 16, 1996, the Company completed the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda was allocated to the assets and liabilities acquired using estimated fair values. As a result, the Company's 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. Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with the Management Group providing for a continuing role of management in the Company after the Merger. The sources and uses of funds related to financing the Merger were as follows:
SOURCES OF FUNDS (in millions) Credit Agreement $ 95.0 JEDI Debt(l) 100.0 15% Cumulative Preferred Stock issued to JEDI 20.0 Common Stock issued to JEDI 90.0 ------ Total $305.0 ======
USES OF FUNDS (in millions) Payments to Coda stockholders, warrantholders and optionholders $176.2 Repayment of former credit facility and other indebtedness 122.7 Merger costs and other expenses 6.1 ------ Total $305.0 ======
(1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. The Company incurred substantial indebtedness in connection with the Merger and is highly leveraged. As of December 31, 1996, the Company had total indebtedness of approximately $175.1 million and common stockholders' equity of approximately $41.7 million. Based upon the Company's current level of operations and anticipated growth, management of the Company believes that available cash, together with available borrowings under the Company's credit facility will be adequate to meet the Company's anticipated future requirements for capital expenditures and scheduled payments of principal of, and interest on, its indebtedness, including the Notes. There can be no assurance that such anticipated growth will be realized, that the Company's business will generate sufficient cash flow from operations or that future borrowings will be available in an amount sufficient to enable the Company to service its indebtedness, including the Notes, or make necessary capital expenditures. In addition, the Company anticipates that it is likely to find it necessary to 27 refinance a portion of the principal amount of the Notes at or prior to their maturity. However, there can be no assurance that the Company will be able to obtain financing to complete a refinancing of the Notes. Credit Agreement Effective February 16, 1996, the Company entered into a credit agreement with NationsBank of Texas, N.A. ("NationsBank"), as lender and as agent, and additional lenders named therein (the "Credit Agreement"). The Credit Agreement is guaranteed by all of Coda's subsidiaries and provides for a revolving credit facility in an amount up to $250.0 million. The borrowing base is subject to redetermination: (i) semiannually, (ii) upon the sale of Taurus and (iii) upon issuance of public subordinated debt in an amount greater than $100.0 million. The lenders under the Credit Agreement waived their right to redetermine the borrowing base with respect to the issuance of the Notes. The borrowing base was redetermined effective July 1, 1996 and remained at $115.0 million. The next scheduled redetermination is April 1, 1997. At December 31, 1996, $64.5 million was outstanding under the Credit Agreement and $50.5 million was available for borrowing thereunder. The Credit Agreement is unsecured. The Company has provided the lenders with first lien deeds of trust on its oil and natural gas assets which will not become effective, and the lenders have agreed not to file, unless (i) 80% of any outstanding borrowings in excess of the borrowing base is not repaid within a 90 day period, (ii) cash collateral securing a hedge transaction exceeds 20% of the borrowing base or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. So long as no default (as defined in the Credit Agreement) is continuing, the Company has the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base. The Company must also pay a commitment fee of between 0.375% to 0.425% on the unused portion of the credit facility. The Credit Agreement contains various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, restrictions on investments, a requirement to maintain positive working capital, and restrictions on dividends and stock repurchases. The Credit Agreement also contains requirements that JEDI or certain affiliates of JEDI must continue to own a majority of the outstanding equity of Coda and must have the ability to elect the majority of the Board of Directors and that certain members of management maintain specified levels of equity ownership in Coda and continue their employment with the Company. The Credit Agreement matures on February 16, 2001. On August 1, 1996, the Company entered into the First Amendment to Credit Agreement (the "First Amendment") which in general reduced the Company's interest rate. The first amendment provides the Company the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, 28 (ii) the CD Rate plus 1% to 1 1/2% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1% to 1 1/2% based upon the ratio of outstanding debt to the available borrowing base. The Company must also pay a commitment fee of between 0.30% to 0.425% on the unused portion of the credit facility. 10 1/2% Senior Subordinated Notes On March 18, 1996, the Company completed the sale of $110 million principal amount of the Notes. The proceeds of the Notes were used to fully repay the JEDI debt assumed in the Merger and to partially repay bank debt. The Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of the Company, are subordinated in right of payment to all Senior Debt (as defined in the Indenture) of Coda, and are senior in right of payment to all future subordinated debt of the Company. The claims of the holders of the Notes are subordinated to Senior Debt, which, as of December 31, 1996, was $65.1 million. Coda's payment obligations under the Notes are fully, unconditionally and jointly and severally guaranteed on a senior subordinated basis by all of Coda's current subsidiaries (the "Guarantors") and future Restricted Subsidiaries (as defined in the Indenture). Such guarantees are subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. All of Coda's current subsidiaries are wholly owned. There are currently no contractual restrictions on distributions from the Guarantors to Coda. The Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its Restricted Subsidiaries to incur additional indebtedness and issue Disqualified Stock (as defined in the Indenture), pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of Coda and engage in mergers and consolidations. The Notes are not redeemable at Coda's option prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes are redeemable, at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggregate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity. In the event of a Change of Control (as defined in the Indenture), holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 29 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of repurchase. The Indenture requires that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase. 15% Cumulative Preferred Stock Coda's Restated Certificate of Incorporation authorizes the issuance of up to 40,000 shares of Preferred Stock. In conjunction with the Merger, Coda issued 20,000 shares of Preferred Stock to JEDI for $20.0 million in cash. Shares of Preferred Stock in excess of such 20,000 shares shall be issuable only for the purpose of paying dividends on the Preferred Stock. The holders of each share of Preferred Stock are entitled to receive, when and as declared by the Board of Directors, cumulative preferential dividends, at the rate of $150.00 per share per annum. The payment of Preferred Stock dividends in cash is restricted by the Credit Agreement and the Indenture. As of December 31, 1996, the Preferred Stock had accumulated approximately $2.7 million in preferred dividends which had not been declared by the Board of Directors. As long as any shares of Preferred Stock are outstanding, no dividends whatsoever, whether paid in cash, stock or otherwise (except for dividends paid in shares of common stock, either in the form of a stock split or stock dividend), may be paid or declared, nor may any distribution be made, on any common stock of Coda to the holders of such stock, unless certain conditions are met. Coda's Restated Certificate of Incorporation requires that Coda redeem all the issued and outstanding shares of Preferred Stock at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption, if Coda has sufficient funds legally available for such redemption and if such redemption would not violate or conflict with any loan agreement, credit agreement, note agreement, indenture or other agreement relating to indebtedness to which Coda is a party, on or before the fifth business day after the earliest to occur of the following: (i) the closing of the sale by Coda of Taurus and (ii) a Trigger Event, as such term is defined in the Stockholders Agreement (see Certain Transactions--Stockholders Agreement). The Preferred Stock may be redeemed by Coda at its option, as a whole or in part, to the extent Coda shall have funds legally available for such redemption, at any time or from time to time at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption. Such redemption, whether required or optional, is restricted by the Credit Agreement and the Indenture. Enron 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. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging financing to non- affiliated participants in the 30 oil and natural gas industry who are or may become 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. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ------------------------------------------- The financial statements required by this Item are included as part of Item 14 hereof. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND --------------------------------------------------------------- FINANCIAL DISCLOSURE -------------------- None PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT -------------------------------------------------- Item 11. EXECUTIVE COMPENSATION ---------------------- Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT -------------------------------------------------------------- Item 13. CERTAIN TRANSACTIONS -------------------- The information required by Part III of this report was filed March 31, 1997 under Form 10K/A No. 1. 31 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K ---------------------------------------------------------------- (a) The following are filed as a part of this Annual Report on Form 10-K: 1. Financial Statements Page -------------------- ---- Report of independent auditors F-1 Consolidated balance sheets at December 31, 1995, and December 31, 1996 F-2 Consolidated statements of operations for the years ended December 31, 1994 and 1995, 47 days ended February 16, 1996 and 319 days ended December 31, 1996 F-3 Consolidated statements of cash flows for the years ended December 31, 1994 and 1995, 47 days ended February 16, 1996 and 319 days ended December 31, 1996 F-4 Consolidated statements of stockholders' equity of the years ended December 31, 1994 and 1995, 47 days ended February 16, 1996 and 319 days ended December 31, 1996 F-5 Notes to consolidated financial statements F-6 - F-31 2. Financial Statement Schedules - None All schedules have been omitted because the required information is either inapplicable, insignificant or included in the consolidated financial statements and notes thereto. 3. Exhibits -------- 2.1 Agreement and Plan of Merger, by and among Coda, Joint Energy Development Investments Limited Partnership and Coda Acquisition, Inc. dated as of October 30, 1995 filed as Exhibit 2.1 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 2.2 Agreement of Coda to provide schedules to the Agreement and Plan of Merger (Exhibit 2.1) omitted pursuant to Item 6.01 (b)(2) of Regulation S-K filed as Exhibit 2.2 to Coda's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1995, and incorporated by reference herein. 32 2.3 Amendment to Agreement and Plan of Merger dated as of December 22, 1995 filed as Exhibit 2.1 to Coda's Current Report on Form 8-K dated December 22, 1995, and incorporated by reference herein. 2.4 Second Amendment to Agreement and Plan of Merger dated as of January 10, 1996 filed as Exhibit 2.1 to Coda's Current Report on Form 8-K dated January 10, 1996, and incorporated by reference herein. 2.5 Agreement of Coda to provide schedules and exhibits to Second Amendment to Agreement and Plan of Merger (Exhibit 2.4) and to provide schedules to Amendment No. 1 to Subscription Agreement (Exhibit 10.13) and Amendment No. 1 to Stockholders Agreement (Exhibit 10.14) filed as Exhibit 99.4 to Coda's Current Report on Form 8-K dated January 10, 1996, and incorporated by reference herein. 3.1 Restated Certificate of Incorporation of Coda filed as Exhibit 3.1 to the Company's Registration Statement on Form S-4 filed April 9, 1996 (Registration No 333-2375, the "1996 Form S-4") and incorporated by reference herein. 3.2 Amended and Restated Bylaws of Coda filed as Exhibit 3.2 to the 1996 Form S-4 and incorporated by reference herein. 3.3 Certificate of Incorporation of Diamond Energy Operating Company, as amended, filed as Exhibit 3.3 to the 1996 Form S-4 and incorporated by reference herein. 3.4 Bylaws of Diamond Energy Operating Company, as amended, filed as Exhibit 3.4 to the 1996 Form S-4 and incorporated by reference herein. 3.5 Articles of Incorporation of Taurus Energy Corp., as amended, filed as Exhibit 3.5 to the 1996 Form S-4 and incorporated by reference herein. 3.6 Bylaws of Taurus Energy Corp., as amended, filed as Exhibit 3.6 to the 1996 Form S-4 and incorporated by reference herein. 3.7 Articles of Incorporation of Electra Resources, Inc. filed as Exhibit 3.7 to the 1996 Form S-4 and incorporated by reference herein. 3.8 Bylaws of Electra Resources, Inc. filed as Exhibit 3.8 to the 1996 Form S-4 and incorporated by reference herein. 4.1 Indenture, dated as of March 18, 1996, among Coda, the Guarantors and Texas Commerce Bank National Association, as trustee, relating to $110,000,000 aggregate principal amount of 10 1/2% Series A and Series B Senior Subordinated Notes due 2006 filed as Exhibit 4.1 to the 1996 Form S-4 and incorporated by reference herein. 33 4.2 Registration Rights Agreement, dated as of March 18, 1996, among Coda, the Guarantors and the Initial Purchasers filed as Exhibit 4.2 to the 1996 Form S-4 and incorporated by reference herein. 4.3 Purchase Agreement, dated as of March 12, 1996, among Coda, the Guarantors and the Initial Purchasers filed as Exhibit 4.3 to the 1996 Form S-4 and incorporated by reference herein. 4.4 Credit Agreement, dated February 14, 1996, among the Company, NationsBank of Texas, N.A., individually and as agent ("NationsBank"), and additional lenders named therein, filed as Exhibit 4.5 to the 1996 Form S-4 and incorporated by reference herein. 4.5 Promissory Note dated February 14, 1996, in the original principal amount of $87,500,000.00, executed by Coda, payable to NationsBank of Texas, N.A. filed as Exhibit 4.6 to the 1996 Form S-4 and incorporated by reference herein. 4.6 Promissory Note dated February 14, 1996, in the original principal amount of $37,500,000.00, executed by Coda, payable to Bank One, Texas, N.A. filed as Exhibit 4.7 to the 1996 Form S-4 and incorporated by reference herein. 4.7 Promissory Note dated February 14, 1996, in the original principal amount of $75,000,000.00, executed by Coda, payable to Texas Commerce Bank National Association filed as Exhibit 4.8 to the 1996 Form S-4 and incorporated by reference herein. 4.8 Promissory Note dated February 14, 1996, in the original principal amount of $50,000,000.00, executed by Coda, payable to the First National Bank of Boston filed as Exhibit 4.9 to the 1996 Form S-4 and incorporated by reference herein. 4.9 Specimen Certificate of Series A 10 1/2% Senior Subordinated Notes due 2006 (the "Private Notes") (included in Exhibit 4.1 hereto), filed as Exhibit 4.10 to the 1996 Form S-4 and incorporated by reference herein. 4.10 Specimen Certificate of Series B 10 1/2% Senior Subordinated Notes due 2006 (the "Exchange Notes") (included in Exhibit 4.1 hereto), filed as Exhibit 4.11 to the 1996 Form S-4 and incorporated by reference herein. 4.11 First Supplement to Indenture dated as of April 25, 1996 filed as Exhibit 4.12 the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1996 (the "June 1996 10-Q") and incorporated by reference herein amending the Indenture filed as Exhibit 4.1 above. 34 4.12 First Amendment to Credit Agreement, dated August 1, 1996, among the Company, NationsBank and additional lenders named therein, filed as exhibit 4.13 to the Company's quarterly report on Form 10-Q for the quarterly period ended September 30, 1996 (the "September 1996 10-Q") and incorporated by reference herein amending the Credit Agreement filed as Exhibit 4.5 above. 10.1/(2)/ Form of Indemnification Agreement entered into between Coda and each of its directors and officers filed as Exhibit 10.1 to Coda's Annual Report on Form 10-K for the fiscal year ended December 31, 1994 (the "1994 10-K"), and incorporated by reference herein. 10.2/(2)/ List of directors and officers that have entered into Indemnification Agreements with Coda filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1995, and incorporated by reference herein. 10.3/(2)/ Stockholders Agreement dated October 30, 1995 filed as Exhibit 99.2 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.4/(2)/ Subscription Agreement among Coda Acquisition, Inc. and The Management Investors dated October 30, 1995 filed as Exhibit 99.3 to Coda's Current Report on Form S-K dated October 30, 1995, and incorporated by reference herein. 10.5 Agreement of Coda to provide schedules to Stockholders Agreement (Exhibit 10.7) and to Subscription Agreement (Exhibit 10.8) filed as Exhibit 99.11 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.6/(2)/ Business Opportunity Agreement dated as of October 30, 1995 filed as Exhibit 99.4 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.7/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and Randell A. Bodenhamer filed as Exhibit 99.5 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.8/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and J. William Freeman filed as Exhibit 99.6 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.9/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and Grant W. Henderson filed as Exhibit 99.7 to Coda's Current Report on Form 8-K dated October 30, 1995 and incorporated by reference herein. 35 10.10/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and Jarl P. Johnson filed as Exhibit 99.8 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.11/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and Douglas H. Miller filed as Exhibit 99.9 to Coda's Current Report on Form S-K dated October 30, 1995, and incorporated by reference herein. 10.12/(2)/ Executive Employment Agreement between Coda Acquisition, Inc. and J.W. Spencer, III filed as Exhibit 99.10 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.13/(2)/ Amendment No. 1 to Subscription Agreement dated as of January 10, 1996 filed as Exhibit 99.2 to Coda's Current Report on Form S-K dated January 10, 1996, and incorporated by reference herein. 10.14/(2)/ Amendment No. 1 to Stockholders Agreement dated as of January 10, 1996 filed as Exhibit 99.3 to Coda's Current Report on Form 8-K dated January 10, 1996, and incorporated by reference herein. 10.15 Credit Agreement, dated February 14, 1996, among the Company, NationsBank of Texas, N.A., individually and as agent, and additional lenders named therein filed as Exhibit 4.4 above. 10.16 Promissory Note dated February 14, 1996, in the original principal amount of $87,500,000.00, executed by Coda, payable to NationsBank of Texas, N.A. filed as Exhibit 4.5 above. 10.17 Promissory Note dated February 14, 1996, in the original principal amount of $37,500,000.00, executed by Coda, payable to Bank One, Texas, N.A. filed as Exhibit 4.6 above. 10.18 Promissory Note dated February 14, 1996, in the original principal amount of $75,000,000.00, executed by Coda, payable to Texas Commerce Bank National Association filed as Exhibit 4.7 above. 10.19 Promissory Note dated February 14, 1996, in the original principal amount of $50,000,000.00, executed by Coda, payable to the First National Bank of Boston filed as Exhibit 4.8 above. 10.20/(2)/ Form of Nonstatutory Stock Option Agreement attached and filed as Exhibit A to Exhibit 99.3 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 36 10.21/(2)/ Form of Limited Recourse Promissory Note attached and filed as Exhibit B to Exhibit 99.3 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.22/(2)/ Form of Security Agreement attached and filed as Exhibit C to Exhibit 99.3 to Coda's Current Report on Form 8-K dated October 30, 1995, and incorporated by reference herein. 10.23/(2)/ List of Management Investors who are parties to Nonstatutory Stock Option Agreement (Exhibit 10.20), Limited Recourse Promissory Note (Exhibit 10.21) or Security Agreement (Exhibit 10.22) filed as Exhibit 10.27 to the 1996 Form S-4 and incorporated by reference herein. 10.24 First Amendment to Credit Agreement, dated August 1, 1996, among the Company, NationsBank and additional lenders named therein filed as Exhibit 4.12 above. 10.25/(2)/ Limited Recourse Promissory Note dated July 31, 1996, in the original principal amount of $1,187,500.00 executed by Douglas H. Miller, payable to the Company. Filed as Exhibit 10.30 to the September 1996 10-Q and incorporated by reference herein. 10.26/(2)/ Amendment to Nonstatutory Stock Option Agreement dated July 31, 1996 between the Company and Douglas H. Miller filed as Exhibit 10.31 to the September 1996 10-Q and incorporated by reference herein amending the Nonstatutory Stock Option Agreement filed as Exhibit 10.20 above. 21/(1)/ Subsidiaries of the Company. 24.1/(1)/ The power of attorney of officers and directors of Coda is set forth on the signature page hereof. 27/(1)/ Financial data schedule - -------------------------------- /(1)/ Filed herewith. /(2)/ Identifies management contract or compensation plan. (b) Reports on Form 8-K: None (c) The exhibits referenced in Item 14 (a)(3) are filed herewith or incorporated by reference herein. (d) Not applicable. 37 THE COMPANY WILL PROVIDE A COPY OF ITS FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996, FREE OF CHARGE TO ANY STOCKHOLDER UPON RECEIPT OF A WRITTEN REQUEST CONTAINING THE NAME AND ADDRESS OF THE PERSON SO REQUESTING. A COPY OF THE EXHIBITS TO SUCH FORM 10-K WILL BE PROVIDED UPON PAYMENT OF $.20 PER PAGE TO COVER THE COST OF POSTAGE AND HANDLING. 38 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/ Douglas H. Miller -------------------------------------- Douglas H. Miller Chief Executive Officer DATE: March 27, 1997 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Coda Energy, Inc. (the "Company") hereby constitutes and appoints Grant W. Henderson and Douglas H. Miller or either of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute, and file any and all documents relating to the Company's Form 10-K for the fiscal year ended December 31, 1996, including any and all amendments and supplements thereto, with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as he himself might or could do if personally present, hereby ratifying and confirming all that said attorneys-in- fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done. 39 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 and on the dates indicated. Name Capacities Date ---- ---------- ------- /s/ Douglas H. Miller Chairman of the Board and Chief 3/27/97 - -------------------------------- Executive Officer ------- Douglas H. Miller /s/ Grant W. Henderson President, Chief Financial Officer 3/27/97 - -------------------------------- (Principal Financial and Accounting ------- Grant W. Henderson Officer) and Director /s/ Jarl P. Johnson Vice Chairman of the Board and 3/25/97 - -------------------------------- Chief Operating Officer ------- Jarl P. Johnson /s/ Richard B. Buy Director 3/27/97 - -------------------------------- ------- Richard B. Buy /s/ Timothy J. Detmering Director 3/27/97 - -------------------------------- ------- Timothy J. Detmering /s/ James V. Derrick, Jr. Director 3/26/97 - -------------------------------- ------- James V. Derrick, Jr. /s/ C. John Thompson Director 3/25/97 - -------------------------------- ------- C. John Thompson 40 REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS The Board of Directors and Stockholders Coda Energy, Inc. We have audited the accompanying consolidated balance sheet of Coda Energy, Inc., and subsidiaries (the "Successor") as of December 31, 1996, and the related consolidated statements of operations, cash flows, and stockholders' equity for the 319-day period from February 17, 1996 to December 31, 1996 and the predecessor's consolidated balance sheet as of December 31, 1995 and its related consolidated statements of operations, cash flows, and stockholders' equity as described in Note 1 for each of the two years in the period ended December 31, 1995. These financial statements are the responsibility of the Successor's and the predecessor's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements of the Successor referred to above present fairly, in all material respects, the consolidated financial position of Coda Energy, Inc., and subsidiaries at December 31, 1996, and the consolidated results of their operations and their cash flows for the 319-day period from February 17, 1996 to December 31, 1996, in conformity with generally accepted accounting principles. In our opinion, the consolidated financial statements of the predecessor referred to above present fairly, in all material respects, the consolidated financial position of the predecessor at December 31, 1995, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. ERNST & YOUNG LLP Dallas, Texas February 19, 1997 F-1 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 1995 and 1996 (dollars in thousands)
December 31, ------------------------ 1995 1996 ------------ ---------- Predecessor Successor ------------ ---------- ASSETS ------ Current assets: Cash and cash equivalents $ 4,604 $ 7,994 Accounts receivable - revenue 10,598 14,432 Accounts receivable - joint interest and other 2,463 1,673 Other current assets 2,206 1,046 -------- -------- 19,871 25,145 Oil and gas properties (full cost accounting method): Proved oil and gas properties 226,650 249,693 Unproved oil and gas properties - 1,000 Less accumulated depletion, depreciation, and amortization (56,042) (20,757) -------- -------- Oil and gas properties, net 170,608 229,936 Gas plants and gathering systems, at cost 38,068 34,258 Less accumulated depreciation (4,082) (2,305) -------- -------- Gas plants and gathering systems, net 33,986 31,953 Other properties and assets, net 4,599 8,536 -------- -------- $229,064 $295,570 ======== ======== LIABILITIES AND STOCKHOLDERS EQUITY ------------------------------------ Current liabilities: Current maturities of long-term debt $ 453 $ 120 Accounts payable - trade 7,252 8,934 Accounts payable - revenue and other 3,394 5,210 Accrued interest 342 3,366 Income taxes payable 128 579 -------- -------- 11,569 18,209 Long-term debt, less current maturities 123,907 64,966 10 1/2% senior subordinated notes - 110,000 Deferred income taxes 14,400 37,061 Commitments and contingencies 15% cumulative preferred stock, 40,000 shares of $.01 par value authorized; 20,000 shares issued and outstanding at December 31, 1996; liquidation preference of $22,738 at December 31, 1996, including dividends in arrears - 20,000 Common stockholders' equity of management, subject to put and call rights; 13,611 shares of $.01 par value common stock issued and outstanding - 4,560 Less related notes receivable - (937) -------- -------- - 3,623 -------- -------- Other common stockholders' equity: Common stock, 40 million, $.02 par value, 1 million, $.01 par value, shares authorized at December 31, 1995 and 1996, respectively 22,088,903 and 900,000 shares issued and outstanding at December 31, 1995 and 1996, respectively 442 9 Additional paid-in capital 68,671 89,991 Retained earnings (deficit) 10,075 (48,289) -------- -------- Total other common stockholders' equity 79,188 41,711 -------- -------- $229,064 $295,570 ======== ========
See notes to consolidated financial statements. F-2 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996, and 319 days ended December 31, 1996 (in thousands)
Predecessor Successor -------------------------------- -------------------------- Year ended 47 days 319 days Pro forma December 31, ended ended year ended ----------------- February 16, December 31, December 31, 1994 1995 1996 1996 1996 -------- ------- ------------- ------------- ------------- (unaudited) (unaudited) Revenues: Oil and gas sales $50,683 $60,997 $ 8,079 $ 68,690 $ 76,769 Gas gathering and processing 20,081 35,634 5,322 39,553 44,875 Other income 822 1,207 168 2,139 2,307 ------- ------- ------- -------- -------- 71,586 97,838 13,569 110,382 123,951 Costs and expenses: Oil and gas production 21,646 27,119 3,607 28,560 32,167 Gas gathering and processing 17,357 30,473 4,567 32,825 37,392 Depletion, depreciation, and amortization 16,419 19,715 2,583 24,031 27,412 General and administrative 3,144 2,898 320 2,078 2,398 Business combination 1,829 - - - - Interest 5,281 8,676 1,102 14,555 16,985 Stock option compensation - - 3,199 - - Writedown of oil and gas properties - - - 83,305 - ------- ------- ------- -------- -------- 65,676 88,881 15,378 185,354 116,354 ------- ------- ------- -------- -------- Income (loss) before income taxes 5,910 8,957 (1,809) (74,972) 7,597 Income tax expense (benefit) 2,581 3,202 (511) (26,683) 3,146 ------- ------- ------- -------- -------- Net income (loss) 3,329 5,755 (1,298) (48,289) 4,451 Preferred stock dividend requirements - - - 2,738 3,173 ------- ------- ------- -------- -------- Net income (loss) available for common stockholders $ 3,329 $ 5,755 $(1,298) $(51,027) $ 1,278 ======= ======= ======= ======== ========
See notes to consolidated financial statements. F-3 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996, and 319 days ended December 31, 1996 (in thousands)
Predecessor Successor ---------------------------------- ------------- Year ended 47 days 319 days December 31, ended ended ----------------------- February 16, December 31, 1994 1995 1996 1996 ----------- ---------- ------------ ------------- (unaudited) Cash flows from operating activities: Net income (loss) $ 3,329 $ 5,755 $ (1,298) $ (48,289) Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation, and amortization 16,973 20,256 2,583 24,031 Deferred income tax expense (benefit) 1,567 3,187 (511) (27,254) Stock option compensation - - 3,199 - Writedown of oil and gas properties - - - 83,305 Gain on sale of other assets - - - (701) Other 123 55 6 (14) Effect of changes in: Accounts receivable 589 (3,849) 3,386 (6,430) Other current assets 60 (558) (63) 398 Accounts payable and other current liabilities 346 (545) (4,166) 10,104 -------- -------- ------ --------- Net cash provided by operating activities 22,987 24,301 3,136 35,150 Cash flows from investing activities: Additions to oil and gas properties (49,732) (41,079) (1,717) (13,433) Additions to gas plant and gathering systems and other property (4,130) (8,500) (114) (823) Business combinations, net of $5,740 cash acquired in 1996 (3,250) - - (174,373) Investment in common equity securities - (573) - (2,649) Payments received on amounts due from stockholders - 1,294 130 124 Proceeds from sale of assets 2,515 5,722 110 4,938 Prepaid long-term gas purchases (1,759) - - - Loan to stockholder - - - (738) Other, net (423) 106 - 75 -------- -------- ------ --------- Net cash used in investing activities (56,779) (43,030) (1,591) (186,879) Cash flows from financing activities: Proceeds from sale of common and preferred stock - - - 110,000 Proceeds from subordinated notes - - - 210,000 Repayment of debt and subordinated notes (41,542) (11,551) (19) (256,920) Proceeds from bank borrowings 76,350 30,400 - 97,500 Proceeds from exercise of stock options and warrants 2,370 772 - - Repurchases of common stock (812) (2,125) - - Other, net (140) (637) (390) (857) -------- -------- ------ --------- Net cash provided by (used in) financing activities 36,226 16,859 (409) 159,723 -------- -------- ------ --------- Net increase (decrease) in cash and cash equivalents 2,434 (1,870) 1,136 7,994 Cash and cash equivalents at beginning of period 4,040 6,474 4,604 - -------- -------- ------- --------- Cash and cash equivalents at end of period $ 6,474 $ 4,604 $ 5,740 $ 7,994 ======== ======== ======= ========= Supplemental cash flow information: Interest paid $ 3,788 $ 9,584 $ 1,548 $ 11,152 ======== ======== ======= ========= Income taxes paid $ 300 $ 618 $ - $ 120 ======== ======== ======= =========
See notes to consolidated financial statements. F-4 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY Years ended December 31, 1994 and 1995, 47 days ended February 16, 1996, and 319 days ended December 31, 1996 (in thousands)
Common Stockholders' 15% Cumulative Equity of Management, Preferred Stock Subject to Put and Call Rights Other Common Stockholders' Equity ------------------- -------------------------------- ------------------------------------- Additional Retained Notes paid-in earnings Shares Amount Shares Amount receivable Shares Amount capital (deficit) --------- -------- ---------- -------- ---------- ------ ------ ---------- -------- Predecessor: Balances December 31, 1993 - $ - - S - $ - 19,455 $389 $56,851 $ 991 Shares issued as director compensation - - - - - 7 - 44 - Shares issued upon exercise of stock options and warrants - - - - - 788 16 2,355 - Common stock issued to purchase Taurus Energy Corp. - - - - - 1,500 30 7,265 - Repurchase and cancellation of common stock - - - - - (157) (3) (809) - Common stock issued to acquire reversionary interests in oil and gas properties - -- - - - - 635 13 4,270 - Net income - - - - - - - - 3,329 --- ------- --- ------ ------ ------ ---- ------- ------- Balances December 31, 1994 - - - - - 22,228 445 69,976 4,320 Shares issued as director compensation - - - - - 7 - 45 - Shares issued upon exercise of stock options and warrants - - - - - 225 5 767 - Repurchase and cancellation of common stock - - - - - (371) (8) (2,117) - Net income - - - - - - - - 5,755 --- ------- --- ------ ------ ------ ---- ------- ------- Balances December 31, 1995 - - - - - 22,089 442 68,671 10,075 Stock option compensation (unaudited) - - - - - - - 3,199 - Net loss for the period from January 1, 1996 to February 16, 1996 (unaudited) - - - - - - - - (1,298) --- ------- --- ------ ------ ------ ---- ------- ------- Balances at February 16, 1996 (unaudited) - $ - - $ - $ - 22,089 $442 $71,870 $ 8,777 === ======= === ====== ====== ====== ==== ======= ======= Successor: Transactions related to the merger: Common stock issued to management investors in exchange for common stock, options, warrants, notes receivable and cash - $ - 14 $4,560 $ (937) - $ - $ - $ - Common stock issued to JEDI for cash - - - - - 900 9 89,991 - Preferred stock issued to JEDI for cash 20 20,000 - - - - - - - Net loss for the period from February 17, 1996 through December 31, 1996 - - - - - - - - (48,289) --- ------- --- ------ ------ ------ ---- ------- -------- Balances December 31, 1996 0 $20,000 14 $4,560 $ (937) 900 $ 9 $89,991 $(48,289) === ======= === ====== ====== ====== ==== ======= ========
F-5 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. The Merger ---------- 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 Energy, Inc. ("Coda"), Joint Energy Development 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). Coda together with its subsidiaries prior to and including February 16, 1996 is referred to herein as the Predecessor and after such date as CEI or Successor and collectively, for both periods the Company. 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 sources and uses of funds related to financing the Merger were as follows: Sources of Funds (in millions)
Credit Agreement (See Note 5) $ 95.0 JEDI debt/(1)/ 100.0 15% cumulative preferred stock issued to JEDI 20.0 Common stock issued to JEDI 90.0 ------ Total $305.0 ======
Uses of Funds (in millions)
Payments to Coda stockholders, warrantholder and optionholders $176.2 Repayment of former credit facility and other indebtedness 122.7 Merger costs and other expenses 6.1 ------ Total $305.0 ======
(1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's acquisition 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. F-6 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The allocation of JEDI's purchase price to the assets and liabilities acquired resulted in a significant increase in the carrying value of the oil and gas properties. Based upon the allocation of JEDI's purchase price and estimated proved reserves and product prices in effect at the date of the Merger, the purchase price allocated to oil and gas properties was in excess of the cost center ceiling (see Note 2 - oil and gas properties) by approximately $83.3 million ($53.3 million net of related deferred taxes). The resulting writedown was a non-cash charge and has been included in the results of operations for the 319 days ended December 31, 1996. 2. Summary of significant accounting and reporting policies -------------------------------------------------------- Principles of consolidation and basis of financial statement presentation - ------------------------------------------------------------------------- The consolidated financial statements include the accounts of Coda and its majority owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to amounts reported in prior years to conform with the current presentation. All information contained herein concerning the 47-day period ended February 16, 1996 is unaudited. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Cash and cash equivalents - Cash and cash equivalents include commercial ------------------------- paper or eurodollar investments with major financial institutions with maturities of three months or less when purchased. Accounts receivable - Substantially all accounts receivable arise from sales ------------------- of oil, natural gas, or natural gas liquids or from participants in operated oil and gas wells. Generally, operators of oil and gas properties have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. Most of the receivables are from a broad and diverse group of oil and gas companies and, accordingly, do not generally represent a significant credit risk. Credit losses, which have been insignificant, are provided for in the financial statements and have been within management's expectations. Oil and gas properties - Oil and gas properties are recorded at cost using ---------------------- the full cost method of accounting, as prescribed by the Securities and Exchange Commission (the "SEC"). Under the full cost method, all costs associated with the acquisition, exploration, or development of oil and gas properties are capitalized as part of the full cost pool. Sales, dispositions, and other oil and gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless such disposition would significantly alter the amortization rate. Under rules of the SEC for the full-cost method of accounting, the net carrying value of oil and gas properties is F-7 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS limited to the sum of the present value (10% discount rate) of estimated future net cash flows from proved reserves, based on period-end prices and costs, plus the lower of cost or estimated fair value of unproved properties (the "cost center ceiling"). Depletion, depreciation, and amortization of evaluated oil and gas properties are provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers. Gas plants and gathering systems - Gas plants and gathering systems are -------------------------------- recorded at cost and depreciated on a straight-line basis over the shorter of their estimated useful lives or 15 years. Other properties and assets, net - Other assets include deferred financing -------------------------------- costs, deferred gas contract costs and a receivable from a related party (see Note 13). Such costs are amortized over the life of the related loan agreements and contracts. Amortization of these costs for the 47-day period ended February 16, 1996 and the 319-day period ended December 31, 1996 amounted to $68,000 and $660,000, respectively, which is included in depletion, depreciation, and amortization expense in the accompanying statements of operations. Overhead reimbursement fees - Fees from overhead charges billed to working --------------------------- interest owners, including the Company, of $3,372,000, $5,571,000, $848,000, and $6,011,000 for the years ended December 31, 1994, 1995, and the 47 days ended February 16, 1996 and 319 days ended December 31, 1996, respectively, have been classified as a reduction of general and administrative expenses in the accompanying consolidated statements of operations. Financial instruments - The Company enters into swap agreements to reduce --------------------- the effects of the volatility of the price of crude oil and natural gas on the Company's operations. These agreements involve the receipt of fixed price amounts in exchange for variable payments based on NYMEX prices and specific volumes. The differential to be paid or received is accrued in the month of the related production and recognized as a component of oil and gas revenues. The Company also sells call options on crude oil. The strike price of these agreements exceeds current market prices at the time they are entered into. If the applicable market price exceeds the strike price and option premium, the differential is accrued and recognized as a reduction of oil revenues in the month of the related production. Any remaining deferred option premiums are recognized at the end of the option period. The fair values of the swap agreements and sold call options are not included in the accompanying consolidated balance sheet. See Note 11 for the estimated fair value of these financial instruments. Due to the short maturity, market sensitive interest rates and/or minimal changes in forward interest rates since the date of issuance, the carrying value of the Company's other financial instruments approximates fair value. F-8 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS New accounting pronouncements - In the first quarter of 1996, the Company ----------------------------- adopted the Financial Accounting Standards Board ("FASB") Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("FAS 121"). Adoption of this statement did not have a material effect on the Company's financial statements. The FASB has issued its statement No. 123, "Accounting for Stock Based Compensation" ("FAS 123") which establishes an alternative method of accounting for stock based compensation to the method set forth in Accounting Principles Board Opinion No. 25 ("APB 25"). FAS 123 encourages, but does not require, adoption of a fair value based method of accounting for stock options and similar equity instruments granted to employees. The Company has elected to account for such grants under the provisions of APB No. 25. Pro forma information (unaudited) - The pro forma statement of operations --------------------------------- information was prepared as if the Merger and the sale of the Notes (see Note 6) had occurred on January 1, of each 1995 and 1996. The pro forma information does not purport to represent the results of operations which would have occurred had such transactions been consummated on January 1, 1995 and 1996 or for any future period. The pro forma information was prepared by adjusting the historical periods: (i) to adjust depletion, depreciation, and amortization to reflect JEDI's purchase price allocated to property and equipment, (ii) to adjust interest expense to give effect to the net reduction of approximately $37.0 million under the Company's credit facility, repayment of a note payable to an officer of the Company, and an increase in the interest rate on borrowings under the new credit facility of .25%, (iii) to record interest on the Notes at an interest rate of 10 1/2%, (iv) to record amortization of the issuance cost of the Notes over the term such debt is expected to be outstanding (10 years), (v) to adjust the writedown of oil and gas properties and stock option compensation in 1996 to eliminate these non-recurring charges related to the Merger, (vi) to adjust the provision for income taxes for the change in financial taxable income resulting from the above adjustments, (vii) to record the cumulative dividend requirements of the 15% cumulative preferred stock issued to JEDI.
Pro forma (unaudited, in thousands) Year ended December 31, ------------------------------------ 1995 1996 ----------------- ----------------- Revenues $97,838 $123,951 ------- -------- Net income (loss) available for common stockholders $(7,593) $ 1,278 ------- --------
3. Predecessor merger with Diamond ------------------------------- On September 30, 1994, pursuant to an Agreement and Plan of Merger, the Predecessor acquired all of the issued and outstanding stock of Diamond Energy Operating Company and Diamond A Inc. (collectively, "Diamond"). The Predecessor issued an aggregate of 3,647,715 shares of F-9 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS common stock to the Diamond stockholders. Contemporaneously with the merger, Diamond acquired the overriding royalty and reversionary interests owned by Diamond's primary lender in certain of Diamond's oil and gas properties for $9.0 million cash. Coda provided the funds necessary to complete such acquisition and repay $18.5 million of existing Diamond indebtedness. If the price of oil received from the Diamond properties averages more than $17.65 per barrel for the 48-month period ending September 30, 1998, Diamond's former lender will be paid an additional $1.0 million. In addition, other reversionary interests in oil and gas properties in which Diamond owns an interest were purchased from certain employees, former employees, consultants and a financial advisor to Diamond for 634,519 shares of common stock and approximately $39,000 in cash. The merger with Diamond was accounted for as a pooling of interests. Accordingly, the merger of the equity interests was given retroactive effect in these financial statements for periods prior to the merger to represent the combined financial statements of the previously separate entities. The acquisitions of the reversionary interests were accounted for as purchases effective September 30, 1994. Separate and combined results of the Predecessor and Diamond for periods prior to the merger were as follows (in thousands):
Predecessor Diamond Combined ----------- ------- -------- Nine months ended September 30, 1994 (unaudited): Revenues $37,048 $13,314 $50,362 Net income 194 1,831 2,025
In connection with the merger, the Predecessor incurred approximately $1.8 million of legal, accounting, printing, and other costs related to the combination of the previously separate entities. Under pooling of interests accounting, these costs were expensed in September 1994. 4. Other Predecessor Acquisitions ------------------------------ The Company is continually acquiring oil and gas properties. The significant transactions that have occurred since January 1, 1994, are discussed below. On April 29, 1994, Coda acquired 100% of the issued and outstanding common stock of Taurus Energy Corporation ("Taurus"), a privately held Texas corporation, in exchange for 1,500,000 shares of the Predecessor's common stock, valued at approximately $7.3 million, and $3.25 million cash. The Predecessor 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 located primarily in west central Texas. F-10 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In July 1994, Taurus acquired ownership of the Shackelford gas gathering system and processing plant. Taurus had previously been operating the system and plant under operating leases. Taurus paid $3.8 million for the system and plant, which was funded under the existing credit agreement. 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 during the term of the agreements. In January 1995, Taurus acquired the remaining ownership interest in one of Taurus' gas plants and related facilities for $6.5 million. In December 1994, in two separate transactions, the Predecessor acquired interests in 31 producing oil and gas properties in West Texas from two major oil companies. The acquisition prices were $13.3Emillion and $10.0Emillion, respectively. The acquisitions were accounted for as purchases. In October 1995, the Predecessor acquired from Snyder Oil Company interests in 63 producing oil and gas properties located in West Texas (the "Snyder Properties"). The aggregate purchase price was $17.1 million in cash, of which $16.0 million was financed by borrowings under the existing credit facility. The acquisition was accounted for as a purchase. The following unaudited pro forma data present the consolidated results of operations of the Predecessor for the year ended December 31, 1995, as if the acquisition of the Snyder Properties had occurred on January 1, 1995. The pro forma results of operations are presented for comparative purposes only and are not necessarily indicative of the results that would have been obtained had such acquisitions been consummated as presented. The following data reflect pro forma adjustments for depletion, depreciation, and amortization related to the acquired oil and gas properties; adjustments to interest expense on borrowed funds; and resulting adjustments to income tax expense (in thousands). Pro forma Year ended December 31, 1995 ---------- (unaudited) Revenues $102,997 ======== Net income $6,107 ====== F-11 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Long-term debt -------------- Long-term debt is summarized as follows (in thousands):
December 31, ---------------------- 1995 1996 ----------- --------- Predecessor Successor ----------- --------- NationsBank credit agreements $122,000 $64,500 Note payable to NationsBank 606 486 Senior subordinated debentures 988 - Other 766 100 -------- ------- 124,360 65,086 Less current maturities 453 120 -------- ------- Long-term debt $123,907 $64,966 ======== =======
NationsBank credit agreements - Effective February 16, 1996, CEI entered ----------------------------- into a credit agreement with NationsBank of Texas, N.A. ("NationsBank"), as lender and as agent, and additional lenders named therein (the "Credit Agreement"). The Credit Agreement is guaranteed by all of Coda's subsidiaries and provides for a revolving credit facility in an amount up to $250.0 million. The borrowing base is subject to redetermination: (i) semiannually, (ii) upon the sale of Taurus and (iii) upon issuance of public subordinated debt in an amount greater than $100.0 million. The lenders under the Credit Agreement agreed to waive their right to redetermine the borrowing base with respect to the issuance of the Notes (see Note 6). The borrowing base was redetermined effective July 1, 1996 and remained at $115.0 million. At December 31, 1996, $64.5 million was outstanding under the Credit Agreement and $50.5 million was available for borrowing thereunder. The next redetermination of the borrowing base is scheduled for April 1, 1997. The Credit Agreement is unsecured. CEI has provided the lenders with first lien deeds of trust on its oil and natural gas assets which will not become effective, and the lenders have agreed not to file, unless (i) 80% of any outstanding borrowings in excess of the borrowing base is not repaid within a 90-day period, (ii) cash collateral securing a hedge transaction exceeds 20% of the borrowing base or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. There are no scheduled principal payments due on the Credit Agreement until maturity. So long as no default (as defined in the Credit Agreement) is continuing, CEI has the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base. CEI must also pay a commitment fee of between 0.375% to 0.425% on the unused portion of the credit facility. The Credit Agreement contains various restrictive covenants, including limitations F-12 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS on the granting of liens, restrictions on the issuance of additional debt, restrictions on investments, a requirement to maintain positive working capital, and restrictions on dividends and stock repurchases. The Credit Agreement also contains requirements that JEDI or certain affiliates of JEDI must continue to own a majority of the outstanding equity of Coda and must have the ability to elect the majority of the Board of Directors and that certain members of management maintain specified levels of equity ownership in Coda and continue their employment with the Company. The Credit Agreement matures on February 16, 2001. On August 1, 1996, CEI entered into the First Amendment to Credit Agreement (the "First Amendment") which in general reduced the interest rate. The First Amendment provides CEI the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1% to 1 1/2% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1% to 1 1/2% based upon the ratio of outstanding debt to the available borrowing base. CEI must also pay a commitment fee of between 0.30% to 0.425% on the unused portion of the credit facility. The Predecessor's credit agreement provided that interest rates on borrowings ranged from NationsBank's prime rate to LIBOR plus between 1% and 1 3/8% based on the ratio of outstanding debt to the available borrowing base. The weighted average interest rate on borrowings outstanding under the Credit Agreement was 7.43% and 6.91% for the year ended December 31, 1995 and for the 319-day period ended December 31, 1996, respectively. Note payable to NationsBank - The promissory note requires monthly --------------------------- principal and interest payments to January 2, 1998, with interest at NationsBank's prime rate. Senior subordinated debentures - The 12% Senior Subordinated Debentures ------------------------------ (the "Debentures") are presented net of unamortized issuance discount of $165,000 at December 31, 1995. The effective interest rate on the Debentures is 16.61%. On May 1, 1996, CEI deposited with the trustee of the Debentures funds sufficient to redeem the Debentures at a redemption price of 100.0% of the principal amount of the Debentures plus accrued and unpaid interest thereon, and thereafter interest on the Debentures ceased to accrue. Scheduled maturities of long-term debt (including the Notes discussed in Note 6 below) as of December 31, 1996, are as follows (in thousands):
1997 $ 120 1998 366 1999 100 2000 - 2001 64,500 Thereafter 110,000 -------- $175,086 ========
F-13 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As a result of the long-term debt bearing interest at floating market rates and the minimal change in forward market interest rates from the time CEI completed the sale of the Notes (see Note 6), the carrying value of these financial instruments approximates fair value. 6. 10 1/2% Senior subordinated notes --------------------------------- On March 18, 1996, CEI completed the sale of $110 million principal amount of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The proceeds of the Notes were used to fully repay the JEDI debt assumed in the Merger and to partially repay bank debt. The Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of CEI, are subordinated in right of payment to all Senior Debt (as defined in the Indenture governing the Notes) of Coda, and are senior in right of payment to all future subordinated debt of CEI. The claims of the holders of the Notes are subordinated to Senior Debt, which, as of December 31, 1996, was $65.1 million. The Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its Restricted Subsidiaries (as defined in the Indenture) to incur additional indebtedness and issue Disqualified Stock (as defined in the Indenture), pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of Coda and engage in mergers and consolidations. The Notes are not redeemable by Coda's prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes are redeemable, at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggregate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity. In the event of a Change of Control (as defined in the Indenture), holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of repurchase. The Indenture requires that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase. F-14 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Coda's payment obligations under the Notes are fully, unconditionally and jointly and severally guaranteed on a senior subordinated basis by all of Coda's current subsidiaries and future Restricted Subsidiaries. Such guarantees are subordinated to the guarantees of Senior Debt issued by the Guarantors (as defined in the Indenture) under the Credit Agreement and to other guarantees of Senior Debt issued in the future. All of Coda's current subsidiaries are wholly owned. There are currently no contractual restrictions on distributions from the Guarantors to Coda. Separate financial statements and other disclosures concerning the Guarantors are not presented because management has determined they are not material to investors. The combined condensed financial information of Coda's current subsidiaries, the Guarantors, is as follows:
December 31, ---------------------- 1995 1996 ----------- --------- Predecessor Successor ----------- --------- Current assets $ 5,394 $ 7,745 Oil and gas properties, net 36,469 50,176 Gas plants and gathering systems, net 33,650 31,617 Other properties, net, and other assets 1,713 1,113 ------- ------- Total assets $77,226 $90,651 ======= ======= Current liabilities $ 5,629 $ 8,321 Intercompany payables 50,172 33,551 Deferred income taxes 7,828 16,191 Stockholder's equity 13,597 32,588 ------- ------- Total liabilities and stockholder's equity $77,226 $90,651 ======= =======
F-15 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Predecessor Successor ---------------------------------- ------------- Year ended 47 days 319 days December 31, ended ended -------------------- February 16, December 31, 1994 1995 1996 1996 ------- -------- ----------- ------------ (unaudited) Revenues: Oil and gas sales $17,660 $18,826 $2,529 $25,115 Gas gathering and processing 20,031 35,634 5,322 39,553 Other income 251 244 2 215 ------- ------- ------ ------- 37,942 54,704 7,853 64,883 Costs and expenses: Oil and gas production 4,706 7,023 843 6,718 Gas gathering and processing 17,324 30,473 4,567 32,825 Depletion, depreciation and amortization 6,719 7,776 1,039 9,537 General and administrative 1,158 3,936 435 2,993 Interest 2,628 3,538 460 2,443 Business combination 1,184 - - - Writedown of oil and gas properties - - - 19,159 ------- ------- ------ ------- 33,719 52,746 7,344 73,675 ------- ------- ------ ------- Income (loss) before income taxes 4,223 1,958 509 (8,792) Income tax expense (benefit) 1,813 822 277 (2,898) ------- ------- ------ ------- Net income (loss) $ 2,410 $ 1,136 $ 232 $(5,894) ======= ======= ====== =======
7. Preferred Stock --------------- Under Coda's Restated Certificate of Incorporation, the Board of Directors is authorized to issue up to 40,000 shares of preferred stock, par value $0.01 per share. All 40,000 shares of preferred stock are designated as "15% Cumulative Preferred Stock," (the "Preferred Stock"). The holders of each share of Preferred Stock are entitled to receive, when and as declared by the Board of Directors, cumulative preferential dividends, at the rate of $150.00 per share per annum. There are currently 20,000 shares of Preferred Stock issued and outstanding. Shares of Preferred Stock in excess of such 20,000 shares shall be issuable only for the purpose of paying dividends on the Preferred Stock. As of December 31, 1996, the Preferred Stock had accumulated approximately $2.7 million in preferred dividends which had not been declared by the Board of Directors. F-16 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As long as any shares of Preferred Stock are outstanding, no dividends whatsoever, whether paid in cash, stock or otherwise (except for dividends paid in shares of common stock, either in the form of a stock split or stock dividend), may be paid or declared, nor may any distribution be made, on any common stock to the holders of such stock, unless certain conditions are met. Coda's Restated Certificate of Incorporation requires that Coda redeem all the issued and outstanding shares of Preferred Stock at a redemption of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption, if Coda has sufficient funds legally available for such redemption and if such redemption would not violate or conflict with any loan agreement, credit agreement, note agreement, indenture or other agreement relating to indebtedness to which Coda is a party, on or before the fifth business day after the earliest to occur of the following: (i) the closing of the sale by Coda of Taurus and (ii) a Trigger Event, as such term is defined in the Stockholders Agreement (see Note 13). The Preferred Stock may be redeemed by Coda at its option, as a whole or in part, to the extent Coda shall have funds legally available for such redemption, at any time or from time to time at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption. Such redemption, whether required or optional, is restricted by the Credit Agreement and the Indenture. Upon the complete liquidation, dissolution, or winding up of Coda, whether voluntarily or involuntarily, the holders of Preferred Stock shall be entitled, after payment or provision for payment of the debts and other liabilities of Coda but before any distribution is made to the holders of any common stock, to be paid $1,000 per share plus all accrued and unpaid dividends (including undeclared dividends), and shall not be entitled to any further payment. Except as otherwise provided herein or required by law, the holders of shares of Preferred Stock are not entitled to vote on any matters to be voted on by the stockholders of Coda; provided, however, that so long as any shares of the Preferred Stock are outstanding, Coda shall not, without the written consent or the affirmative vote of holders of at least a majority of the total number of sharers of Preferred Stock then outstanding and voting as a class, (i) amend its Restated Certificate of Incorporation or Bylaws or (ii) authorize the merger (whether or not Coda is a surviving corporation in such merger) of Coda, in each case, if such amendment or merger would alter, change or abolish the powers, preference or rights of the Preferred Stock so as to affect the holders of the Preferred Stock adversely. 8. Common equity ------------- Common stock - At December 31, 1995, the Predecessor had 40.0 million ------------ shares of $0.02 par value common stock authorized with 22.1 million shares issued and outstanding. At December 31, 1996, CEI had 1.0 million shares of $0.01 par value common stock authorized with 13,611 shares F-17 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS issued to management subject to put and call rights (see Note 13. Related Party Transactions - Stockholders Agreement) and 900,000 issued to JEDI for a total of 913,611 common shares issued and outstanding. Stock options and warrants - The Company has stock option plans providing -------------------------- for the granting of stock options to officers and key employees. Compensation expense has not been recognized at the time options are granted because the option price per share represents the market value of the share at the date of grant. The 1986 Non-Qualified Stock Option Plan provided that options may be granted, from time to time, to key employees and directors to purchase a maximum of 180,000 shares of common stock. This plan expired under its own terms during 1996. The 1989 Incentive Stock Option Plan provides that options may be granted, from time to time, to key employees to purchase a maximum of 750,000 shares of common stock. The 1993 Incentive Stock Option Plan permits the granting of options to purchase up to 1,500,000 shares of common stock. Option transactions are summarized below:
Number Option of shares price range --------- ------------- Outstanding at December 31, 1993 899,084 $2.25 - $6.00 Granted 525,785 5.00 - 6.50 Exercised (108,629) 2.25 - 5.75 Forfeited (56,708) 3.50 - 5.75 --------- Outstanding at December 31, 1994 1,259,532 2.25 - 6.50 Granted -- Exercised (100,213) 2.25 - 5.75 Forfeited (42,687) 3.50 - 5.75 --------- Outstanding at December 31, 1995 1,116,632 2.25 - 6.50 Granted -- Exercised -- Canceled and exchanged for CEI option (164,375) 2.25 - 6.00 Forfeited (1,917) 5.63 --------- Outstanding at February 16, 1996 (subsequently terminated - see following discussion) 950,340 2.25 - 6.50 =========
F-18 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table summarizes warrants outstanding at February 16, 1996 exclusive of warrants covering 700,000 shares exchanged for a CEI option:
Exercise Number of price shares under warrants Expiration date per share ------------------------- --------------- --------- 450,000 December 2000 3.13 50,000 April 2002 3.00 100,000 April 2004 4.88 ------- 600,000 -------
As a result of the Merger, all outstanding options and warrants were fully vested and the holders thereof were entitled to receive the difference between $7.75 per share and the exercise price for each share represented by the options and warrants, an aggregate of approximately $5.4 million. Additionally, certain members of the management of the Company exchanged their right to receive payment as it relates to options covering 164,375 shares and warrants covering 700,000 shares with an aggregate value of approximately $3.2 million for an equity participation in CEI (the Replacement Options, Note 13). Such amount was recognized as stock option compensation expense in the 47-day period ended February 16, 1996. This equity participation took the form of options covering 31,989 CEI common shares with an exercise price of $.01, a 10-year term and immediately exercisable. The stock options outstanding at December 31, 1996, were not issued pursuant to any of the stock option plans. A certain number of shares could be reserved for issuance under the stock option plans in future periods; however, management does not presently expect any options to be granted pursuant thereto. See Note 13. The Company has elected to follow APB 25 in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under FAS 123 requires use of option valuation models that were not developed for use in valuing employee stock options. Generally, under APB 25, because the exercise price of the employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. The compensation expense recognized under APB 25 is due to changing the exercise price of the options in connection with the Merger. FAS 123 requires the use of the "minimum value" method for determining the value of employee stock options for nonpublic companies. This method estimates the value of the employee stock option as the excess of the fair value of the stock at the date of grant over the present value of both the exercise price and the expected dividend payments, each discounted at the risk-free rate, over the expected life of the option. FAS 123 generally requires the presentation of pro forma information as if employee stock options had been accounted for under FAS 123. However, due to the recognition of compensation expense under APB 25, at the date of the Merger and the absence of options grants subsequent thereto, the pro forma information would not be materially different from the historical results of operations. F-19 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. Employee benefit plan --------------------- The Company sponsors a 401(k) defined contribution plan. The 401(k) plan is available to all employees who have at least six months of service. The Company matches between 50% and 100% (based on years of service) of an employee's contribution up to 6% of an employee's compensation. For the years ended December 31, 1994 and 1995, the 47 days ended February 16, 1996 and the 319 days ended December 31, 1996, the Company 401(k) expense was $123,000, $252,000, $37,000 and $282,000, respectively, and is included in general and administrative expenses in the accompanying statements of operations. 10. Income taxes ------------ At December 31, 1996, Coda has net operating loss carryforwards ("NOLs") for income tax purposes that expire beginning in 1998. Utilization of the NOLs is severely restricted because of a change in ownership, as defined by the Tax Reform Act of 1986, of Coda, which occurred in March 1990. At December 31, 1996, Coda estimates that approximately $18.0 million of the NOLs is available to offset future taxable income without limitation, while the remainder will become available in the future at the rate of approximately $921,000 per year through 2004. Coda also has available statutory depletion carryforwards of approximately $1,000,000. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax liabilities and assets are as follows (in thousands):
December 31, ----------------------- 1995 1996 ------------ --------- Predecessor Successor ------------ --------- Deferred tax liabilities: Book basis of oil and gas properties in excess of tax basis $11,441 $37,611 Book basis of gas plants and gathering systems in excess of tax basis 6,447 7,633 Other 1,074 1,315 ------- ------- Total deferred tax liabilities 18,962 46,559 Deferred tax assets: Net operating loss carryforwards 8,468 9,323 Other 136 175 Valuation allowance for deferred tax assets (4,042) - ------- ------- Net deferred tax assets 4,562 9,498 ------- ------- Net deferred tax liabilities $14,400 $37,061 ======= =======
F-20 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Significant components of income tax expense attributable to continuing operations are as follows (in thousands):
Predecessor Successor ------------------------------------ ------------ Year ended 47 days 319 days December 31, ended ended -------------------- February 16, December 31, 1994 1995 1996 1996 -------- ---------- ------------- ------------ (unaudited) Current $ 733 $ 15 $ - $ 571 Deferred federal 1,848 3,187 (511) (27,254) ------ ------ ------ -------- $2,581 $3,202 $ (511) $(26,683) ====== ====== ====== ========
The following is a reconciliation, stated as a percentage of pretax income (loss) taxable at the corporate level, of the U.S. statutory federal income tax rate to the Company's effective tax rate:
Predecessor Successor ------------------------------------------- ----------- Year ended 47 days 319 days December 31, ended ended ---------------------------- February 16, December 31, 1994 1995 1996 1996 ------------- ------------- ------------- ----------- (unaudited) U.S. federal statutory rate 34% 34% 34% 34% State taxes 5 2 (1) 2 Non-deductible business combination expenses 5 - - - ---- ---- ---- ---- 44% 36% 33% 36% ==== ==== ==== ====
1. Operations ---------- Nature of Operations The Company is an independent energy company principally engaged in the acquisition and exploitation of producing oil and natural gas properties. The Company seeks to acquire properties whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs, and property development. The Company's producing properties are concentrated in the mid-continent region of the United F-21 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS States. Through a subsidiary, Taurus, the Company also operates natural gas processing and liquid extraction facilities and natural gas gathering systems. Oil and Gas Producing Activities The results of operations from the Company's oil and gas producing activities are as follows (in thousands):
Predecessor Successor ---------------------------------------- ------------- Year ended 47 days 319 days December 31, ended ended ------------------------- February 16, December 31, 1994 1995 1996 1996 ----------- ------------ ------------- ------------- (unaudited) Oil and gas sales $ 50,683 $ 60,997 $ 8,079 $ 68,690 Production costs (21,646) (27,119) (3,607) (28,560) Depletion, depreciation, and amortization (14,853) (16,889) (2,161) (20,757) Writedown of oil and gas properties - - - (83,305) Income tax (expense) benefit at 34% (4,823) (5,776) (786) 22,570 -------- -------- ------- -------- $ 9,361 $ 11,213 $ 1,525 $(41,362) ======== ======== ======= ========
Costs incurred in oil and gas producing activities are as follows (in thousands, except per equivalent barrel amounts):
Predecessor Successor ---------------------------------------- ------------- Year ended 47 days 319 days December 31, ended ended ------------------------- February 16, December 31, 1994 1995 1996 1996 ----------- ------------ ------------- ------------- (unaudited) Property acquisition costs $40,109 $25,363 $ 305 $324,732/(1)/ Development costs 12,450 14,464 1,286 8,608 Exploration costs 206 511 - - Depletion, depreciation, and amortization rate per equivalent barrel 4.25 4.33 4.40 5.89
/(1)/ Includes approximately $320.5 million related to the Merger discussed in Note 1. F-22 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All of the Company's oil and gas revenues are from proved developed properties located in the United States. The Company has capitalized internal costs of $712,000, $748,000, $105,000, and $567,000 for the years ended December 31, 1994, and 1995, the 47 days ended February 16, 1996, and the 319 days ended December 31, 1996, respectively. Such capitalized costs include salaries and related benefits of individuals directly involved in the Company's acquisition, exploration, and development activities based on the percentage of their time devoted to such activities. During the year ended December 31, 1994, sales of oil and gas to two purchasers accounted for 13% and 22% of consolidated gross revenue. During the year ended December 31, 1995, sales of oil and gas to two purchasers accounted for 10% and 18%, respectively, of consolidated gross revenue. During the 47 days ended February 16, 1996, sales of oil and gas to one purchaser accounted for 17% of consolidated gross revenue. During the 319 days ended December 31, 1996, sales of oil and gas to one purchaser accounted for 20% of consolidated gross revenue (an affiliate of Enron - see Note 13). Management believes that the loss of these purchasers would not have a material impact on the Company's consolidated financial condition or results of operations. Oil and Gas Hedging Activities and Commitments 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 whenever such 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. The Company does not hold or issue financial instruments for trading purposes. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. All hedging is accomplished pursuant to exchange-traded contracts or master swap agreements based upon standard forms. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. Credit risk related to hedging activities, which is minimal, is managed by requiring minimum credit standards for counterparties, periodic settlements, and market to market valuations. The Company has not historically been required to provide any significant amount of collateral relating to its hedging activities. At December 31, 1996, the Company had entered into various swap agreements to fix selling prices for crude oil at a weighted average NYMEX price of $19.13 per barrel for 735,000 barrels during 1997, certain of which are with affiliates of JEDI (see Note 13). The Company has also sold call options, which serve to limit the Company's oil price, covering 25,000 barrels of oil per month at an option price of $20.00 per barrel for the period January 1997 to August 1997. In connection with two swaps beginning January 1, 1997 covering 10,000 barrels per month and F-23 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 15,000 barrels per month at a strike price of $19.41 and $19.00, respectively, which expire June 30, 1997 and December 31, 1997, respectively, the Company granted the counterparty a one day option at the expiration of the swap to extend the swap for an additional twelve months. While these contracts have no carrying value in the accompanying balance sheet, their fair value (the estimated amount that would have been paid by the Company to terminate of the swaps) at December 31, 1996 was approximately $4.4 million. A one dollar change in the average NYMEX oil price (which was $25.92 at December 31, 1996) would change the fair value by approximately $1.2 million. During the years ended December 31, 1994 and 1995, the 47 days ended February 16, 1996 and the 319 days ended December 31, 1996, oil and gas sales were reduced by $5,000, increased by $298,000, reduced by $14,000, and reduced by $3.1 million, respectively, as a result of hedging transactions. 12. Commitments and contingencies ----------------------------- CEI does not believe that future costs related to site restoration, dismantlement, and abandonment costs, net of estimated salvage values, will have a significant effect on its results of operations or financial position because the salvage value of equipment and related facilities should approximate or exceed any future expenditures for restoration, dismantlement, or abandonment. The Company has not incurred any net expenditures for costs of this nature during the last three years. The Company is a defendant or co-defendant in minor lawsuits that have arisen in the ordinary course of business. In the lawsuits, management believes, based in part on advice from legal counsel, that the Company has meritorious defense against the claims asserted. Management believes that the ultimate resolution of the lawsuits and claims will not have a material adverse effect on results of operations or financial position. 13. Related party transactions -------------------------- Subscription Agreement CAI entered into a Subscription Agreement dated as of October 30, 1995, as amended by Amendment No. 1 to Subscription Agreement dated as of January 10, 1996, with members of the Management Group (as amended, the "Subscription Agreement") which provided for the acquisition by such persons of CAI common stock and the grant to them of nonqualified stock options to purchase shares of successor common stock (the "Replacement Options") of Coda. Under the Subscription Agreement, each member of the Management Group who acquired CAI common stock paid $100 per share for shares thereof, which is the same price per share paid by JEDI for the remaining shares of CAI common stock. Under the Subscription Agreement, the Management Group acquired CAI common stock immediately prior to the effective time of the F-24 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Merger in exchange for varying combinations of (i) proceeds from limited recourse promissory notes payable to CAI in the aggregate principal amount of $937,300 (the "Promissory Notes"), (ii) Coda common stock, which was valued for this purpose at $7.75 per share, and (iii) cash. The CAI common stock so acquired was not registered under any federal or state securities laws and did not have the benefit of any registration rights, but was subject to the Stockholders Agreement described below. By virtue of the Merger, each share of CAI common stock was converted into one share of Coda common stock. The Promissory Notes are due on February 16, 2001, bear interest at 5.61% per annum, are secured by the common stock purchased with the proceeds thereof and certain rights of the maker under the Stockholders Agreement, and provide that in no event will an individual maker's liability thereunder for any deficiency on his respective Promissory Note (after the sale and disposition of all collateral securing same) exceed 35% of the original principal balance of the Promissory Note. The Subscription Agreement provided that the Specified Options (representing certain options to purchase common stock held by certain members of the Management Group) and Specified Warrants (representing certain warrants to purchase common stock held by certain members of the Management Group) would not be exercised prior to the effective time of the Merger and would, as of the effective time, be canceled without exercise and without payment of consideration. Concurrently, the Management Group entered into Nonstatutory Stock Option Agreements governing the Replacement Options that provided for the right for a period of 10 years from and after the effective time of the Merger to purchase shares of CEI common stock for $0.01 per share. However, the Replacement Options may only be exercised while the holder remains an employee and for a limited period of time thereafter. The number of shares of Coda common stock underlying the Replacement Options each member of the Management Group received is based on the amount of cash the holder would have received if his Specified Options or Specified Warrants had been converted into cash in the Merger on the same basis as other outstanding options and warrants to purchase common stock were converted, divided by the $100 per share purchase price paid by JEDI and the other Management Group members for their shares of CAI common stock. Thus, if the Replacement Options are exercised, the holders will have effectively paid the same purchase price per share as JEDI and the Management Group paid for their shares of common stock of Coda. In connection with the issuance of the Replacement Options, the Company recognized stock option compensation expense of approximately $3.2 million in the 47 days ended February 16, 1996 representing the total amount of cash the holders of the Specified Options and Specified Warrants would have received if such options and warrants had been converted to cash in the Merger. F-25 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Stockholders Agreement CAI, JEDI and the Management Group entered into a Stockholders Agreement dated as of October 30, 1995, as amended by Amendment No. 1 to Stockholders Agreement dated as of January 10, 1996 (as amended, the "Stockholders Agreement"), which provides generally that all parties, including JEDI and the Management Group, (i) have rights of first refusal to acquire additional shares of common stock of Coda that may be issued by Coda and (ii) are restricted from transferring their Coda common stock. Coda has a right to match any third party offer to purchase shares of Coda common stock from any stockholder, and, in the event that Coda does not purchase those shares, the other stockholders may have a right to include a pro rata portion of their Coda common stock in the transaction. The Stockholders Agreement provides that, if the employment of a member of the Management Group terminates for any reason (including death or disability) other than his voluntary termination (except upon retirement at age 65 or older or the expiration of the term of any employment agreement he has with Coda) or his termination by Coda for cause, then Coda shall have a right to purchase such member's shares of Coda common stock (an aggregate of 13,611 shares at December 31, 1996) at a purchase price to be determined from time to time by Coda pursuant to a formula that values the shares on the basis of a comparison of the discretionary cash flow and EBITDA (as defined therein) of the Company and a group of peer companies. The Stockholders Agreement also provides that, if the employment of a member of the Management Group terminates for any reason other than voluntary termination or termination of such member for cause, then such member shall have the right to require Coda to purchase such member's shares of Coda common stock based on the previously described formula. The purchase price under the formula will vary depending on the financial performance of CEI and the group of peer companies. The Stockholders Agreement provides that each member of the Management Group shall have the right (the "Special Management Rights") to receive from JEDI, upon the occurrence of certain events (generally an initial public offering, a business combination with another person or the liquidation of Coda) (each, a "Trigger Event"), an amount, which is payable in cash or additional shares of Coda common stock depending upon the cause of the Trigger Event, designed to result in the Management Group receiving in connection with the Trigger Event one-third of the proceeds, attributable to the shares of Coda common stock purchased by JEDI, above the amount of proceeds necessary for JEDI to achieve an internal annual rate of return on that investment of 15%. The individual member's interest in such Special Management Rights is proportional to such member's ownership of the fully diluted common stock of Coda. The Stockholders Agreement also provides that if the employment of a member of the Management Group terminates, his Special Management Rights shall terminate and, if the termination is other than a voluntary termination or a termination for cause, he may be entitled to receive an amount based on the discretionary cash flow and EBITDA formula discussed above. The Stockholders Agreement further provides that, after the effective time of the Merger, Coda will establish an employee benefit plan for the benefit of its employees who are not members of the Management Group and will contribute to the plan 1,900 shares of Coda common stock. Furthermore, pursuant to the Stockholders Agreement, 4% of the Special Management Rights will be allocated thereto. F-26 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS At September 30, 1996, the discretionary cash flow and EBITDA formula determines a theoretical value for Coda's common stock which indicates JEDI would have earned more than a 15% rate of return on its investments. The information to calculate the discretionary cash flow and EBITDA formula as of December 31, 1996, is not yet available. As determined by the discretionary cash flow and EBITDA formula, the value of the Special Management Rights to the Management Group in the aggregate was approximately $38 million at September 30, 1996. When a Trigger Event becomes probable, the Company will record compensation expense equal to the estimated value of the Special Management Rights at the time of such trigger event, which may be significantly different than the amount as of September 30, 1996. Since the Special Management Rights are an obligation of JEDI, the offsetting credit would be additional paid-in capital. The Stockholders Agreement will terminate and no party thereto will have any further obligations or rights thereunder upon the earliest to occur of (i) the termination of the Merger Agreement in accordance with its terms, (ii) October 30, 2005, (iii) the date on which an initial public offering of Coda common stock or any business transaction involving Coda whereby Coda common stock becomes a publicly traded security is consummated, (iv) the date of the dissolution, liquidation or winding-up of Coda and (v) the date of the delivery to Coda of a written termination notice executed by certain parties to the Stockholders Agreement. Enron Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and CEI. 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 CEI. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging, financing to non-affiliated participants in the oil and natural gas industry who are or may become competitors of CEI. Because of these various conflicting interests, ECT, CEI, 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 CEI in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of CEI. The Business Opportunity Agreement may limit the business opportunities available to CEI. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which CEI will offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, CEI may be unable to pursue it. Certain of Enron's affiliates purchase oil and gas from the Company. Management of the Company had determined that the contracts for sale of oil and gas to Enron affiliates have been entered into on terms no less favorable than those available from third parties after receiving competitive bids from third parties. Enron affiliates paid CEI approximately $24.1 million under F-27 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS such contracts for the 319 days ended December 31, 1996. Such amount is included in oil and gas revenue in the accompanying statement of operations. The Company has entered into two fixed price oil swaps with ECT. One swap covers the period from January 1, 1995 through June 30, 1997 at a strike price of $19.05 covering 15,000 barrels per month. The other covers the period from January 1, 1997 through December 31, 1997 at a strike price of $19.55 covering 10,000 barrels per month. Management of the Company had determined that both swaps were entered into on terms no less favorable than those available from third parties after receiving competitive bids from third parties. CEI paid ECT approximately $539,000 under such contracts for the 319 days ended December 31, 1996. During August 1996, Douglas H. Miller ("Miller"), the Company's Chief Executive Officer and Chairman of the Board of Directors, received $738,000 pursuant to a Limited Recourse Promissory Note in the original principal amount of $1,188,000 (the "Miller Note"). The Miller Note bears interest at 6.74% per annum with final maturity on February 16, 2001, and provides that in no event will Miller's liability thereunder (after the sale and disposition of all collateral securing same) exceed 35% of the original principal balance of the Miller Note. In connection with the execution of the Miller Note, CEI and Miller entered into an amendment of the agreement governing Miller's Replacement Option which prohibits the exercise of the option until all amounts due under the Miller Note have been paid in full. 14. Supplemental oil and gas reserve and standardized measure information --------------------------------------------------------------------- (unaudited) ----------- The Company retains independent engineering firms to provide annual year-end estimates of the Company's future net recoverable oil, gas, and natural gas liquids reserves. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. 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. Reserve 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 F-28 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Estimated Quantities of Proved Reserves (in thousands)
Oil (Bbl) Gas (Mcf) --------- --------- December 31, 1993 30,084 36,196 Purchase of reserves in place 11,038 5,482 Extensions 271 912 Revisions of previous estimates 749 4,107 Production (2,650) (4,982) Sales of reserves in place (285) (1,907) ------ ------- December 31, 1994 39,207 39,808 Purchase of reserves in place 7,324 7,298 Extensions 783 3,173 Revisions of previous estimates (1,011) 1,459 Production (3,165) (4,416) Sales of reserves in place (548) (10,192) ------ ------- December 31, 1995 42,590 37,130 Purchase of reserves in place 64 10 Production (405) (500) Sales of reserves in place (14) (4) ------ ------- February 16, 1996 42,235 36,636 ====== ======= Purchase of reserves in place 43,431 36,862 Extensions 121 4,982 Revisions of previous estimates 2,579 604 Production (2,974) (3,310) Sales of reserves in place (120) (93) ------ ------- December 31, 1996 43,037 39,045 ====== =======
F-29 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Quantities of Proved Developed Reserves (in thousands) Oil (Bbl) Gas (Mcf) --------- --------- December 31, 1993 16,230 30,573 December 31, 1994 20,151 32,890 December 31, 1995 25,877 31,496 February 16, 1996 25,522 31,002 December 31, 1996 33,895 33,255
The following is a summary of a standardized measure of discounted net cash flows related to the Company's proved oil, gas, and natural gas liquids reserves. The information presented is based on a valuation of proved reserves using discounted cash flows based on year-end prices, costs, and economic conditions and a 10% discount rate exclusive of the effect of the oil hedging commitments. The additions to proved reserves from new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of the Company's oil and gas properties, nor should it be considered indicative of any trends. Standardized Measure of Discounted Future Net Cash Flows (in thousands)
Predecessor Successor -------------------------- ------------ December 31, February 16, December 31, 1995 1996 1996 ------------ ------------ ------------ Future cash inflows $860,180 $827,883 $1,208,793 Future production and development costs 366,421 360,511 431,250 Future income taxes 113,775 106,672 206,720 -------- -------- ---------- Future net cash flows 379,984 360,700 570,823 Discount of future net cash flows at 10% per annum 159,242 152,437 242,964 -------- -------- ---------- Discounted future net cash flows after income taxes $220,742 $208,263 $ 327,859 ======== ======== ==========
During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets. This situation has had a destabilizing effect on crude oil's posted prices in the United States, including the posted prices paid by purchasers of the Company's crude oil. The weighted average prices of oil and gas at December 31, 1995, February 16, 1996 and December 31, 1996 used in the above table, were $18.31, $17.92 and $24.88 per Bbl, respectively, and $2.19, $2.01 and $3.53 per Mcf, respectively. F-30 The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):
Predecessor Successor --------------------------------------- ------------- Year ended 47 Days 319 Days December 31, ended ended ------------------------ February 16, December 31, 1994 1995 1996 1996 ------------ ---------- ------------- ------------- Sales and transfers of oil and gas produced, net of production costs $(29,037) $(33,878) $ (4,472) $ (40,130) Net changes in prices and production costs 18,674 37,290 (21,595) 152,369 Extensions and discoveries, net of future development and production costs 3,673 15,932 - 12,338 Development costs during the period 12,656 14,464 1,286 8,608 Revisions of previous quantity estimates 3,579 (19,084) - 48,120 Sales of reserves in place (1,755) (6,323) (70) (365) Purchases of reserves in place 54,672 35,680 389 215,529 Accretion of discount before income taxes 14,098 21,754 4,880 31,438 Net change in income taxes (23,967) (13,709) 7,103 (100,048) -------- -------- -------- --------- Net change $ 52,593 $ 52,126 $(12,479) $ 327,859 ======== ======== ======== =========
F-31 EX-21 2 SUBSIDIARIES Exhibit 21 Coda Energy, Inc. Subsidiaries Name State of Incorporation Ownership % - ---- ---------------------- ----------- Diamond Energy Operating Company Oklahoma 100% Taurus Energy Corp. Texas 100% Electra Resources Inc. Texas 100% EX-27 3 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FINANCIAL STATEMENTS OF CODA ENERGY, INC. FOR THE 319 DAYS ENDED DECEMBER 31, 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 OTHER DEC-31-1996 FEB-17-1996 DEC-31-1996 7,994 0 16,105 0 0 25,145 295,792 23,062 295,570 18,209 174,966 0 20,000 9 45,334 295,570 108,243 110,382 61,385 61,385 0 0 14,555 (74,972) (26,683) (48,289) 0 0 0 (48,289) 0 0
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