-----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, NRYch2Hoj8mmHLMn/0VFUHmtCjazC1x3aGiTG+W8n0Ft8AkWAwzu5Ksc34dz3QL4 WbAGCYD2mBCMSIRTXCn0Zg== 0000927356-00-000737.txt : 20000509 0000927356-00-000737.hdr.sgml : 20000509 ACCESSION NUMBER: 0000927356-00-000737 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 DATE AS OF CHANGE: 20000508 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CARBON ENERGY CORP CENTRAL INDEX KEY: 0001096019 STANDARD INDUSTRIAL CLASSIFICATION: 1311 IRS NUMBER: 841515097 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-15639 FILM NUMBER: 595648 BUSINESS ADDRESS: STREET 1: 1700 BROADWAY SUITE 1150 CITY: DENVER STATE: CO ZIP: 80290-1101 MAIL ADDRESS: STREET 1: 1700 BROADWAY SUITE 1150 CITY: DENVER STATE: CO ZIP: 80290-1101 10-K405 1 FORM 10-K405 SECURITIES AND EXCHANGE COMMISSION Washington D.C. 20549 FORM 10-K Annual Report Pursuant to Section 13 or 15(d) Of the Securities Exchange Act of 1934 For the Fiscal Year Ended Commission File Number December 31, 1999 1-15639 CARBON ENERGY CORPORATION (Exact name of Registrant as specified in it Charter) Colorado 84-1515097 (State of Incorporation) (I.R.S. Employer Identification No.) 1700 Broadway, Suite 1150 80290 Denver, Colorado (Zip Code) (Address of principal executive offices) Registrants telephone number, including area code: (303) 863-1555 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of Exchange on which registered Common Stock, (no par value) American Stock Exchange 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, 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. [X] The aggregate market value of the voting stock excluding shares held by persons who may be considered affiliates of the registrant as of March 27, 2000 is $5,863,426. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of March 30, 2000. Outstanding at Class March 30, 2000 ----- -------------- Common Stock, no par value 6,042,826 shares The Company's Proxy Statement for the 2000 Annual Meeting of Shareholders is incorporated by Reference into Part III None PART I Item 1. Business General ------- Carbon Energy Corporation (the "Company" or "Carbon") was incorporated on September 14, 1999 under the Colorado Business Corporation Act. The Company's business is comprised of the assets and properties of Bonneville Fuels Corporation ("BFC"), which were acquired on October 29, 1999 in a stock purchase, and the assets and properties of CEC Resources Ltd. ("CEC") of which Carbon currently owns approximately 97% of its outstanding shares. As the parent company, Carbon provides management and other services to BFC and CEC. The total cash purchase price after adjustments for BFC's assets was $23,581,000. On August 11, 1999, CEC entered into a stock purchase agreement with Bonneville Pacific Corporation ("BPC"), parent company of BFC, which provided for the purchase by CEC from BPC of all outstanding shares of BFC for $23,858,000 in cash and the assumption of certain liabilities, subject to certain adjustments. The purchase of BFC stock under the stock purchase agreement was completed by Carbon rather than CEC. Rights and obligation of CEC under the stock purchase agreement were assigned to Carbon. Yorktown Energy Partners III, L.P. ("Yorktown") purchased 4,500,000 shares of Carbon for $24,750,000. The funds from this purchase were used to acquire the BFC shares under the stock purchase agreement and pay expenses incurred in connection with the purchase and related transactions. Carbon is an independent oil and gas company engaged in the exploration, development, and production of natural gas and crude oil. At December 31, 1999, the Company had $ 39.3 million of total assets and 32.4 billion cubic feet equivalent ("Bcfe") of proved reserves. Oil is converted to natural gas at a ratio of six Mcf of natural gas to one barrel of oil. The reserves had an estimated pretax present value, discounted at 10%, of $25.9 million based on unescalated prices and costs at December 31, 1999. Of these proved reserves, approximately 96% on a Mcfe basis are gas and approximately 85% of the reserves are categorized as proved developed. Prior to October 29, 1999 all of the properties and activities described below were acquired or conducted by the prior management of BFC. Carbon's activities at December 31, 1999, were concentrated in the Piceance and Uintah Basins in Colorado and Utah, the San Juan Basin in New Mexico, the Permian Basin in New Mexico and Texas, and southwestern Kansas. At December 31, 1999, the Company owned working interests in approximately 293 oil and gas wells, of which approximately 187 are operated by the Company. Daily average production during 1999 was 12,200 Mcfe per day for the Company and its predecessor, BFC. CEC, which became a 97% owned subsidiary of Carbon in February, 2000, had 18.6 Bfce of proved reserves at December 31, 1999. The reserves of CEC at December 31, 1999 had an estimated pre-tax present value, discounted at 10%, of Cdn $27.5 million based on unescalated prices and costs in Canadian dollars at December 31, 1999. CEC engages in the exploration, development and production of crude oil and natural gas and acquires and develops leaseholds and other interests in oil and gas properties, primarily in the Provinces of Alberta and Saskatchewan in Canada. Exchange Offer for CEC Shares ----------------------------- On January 21, 2000, Carbon commenced an exchange offer for shares of CEC. The exchange offer was one of the last steps in transactions to combine BFC and CEC. In the exchange offer, Carbon offered to exchange one share of Carbon for each share of CEC. CEC's Board of Directors recommended that CEC's shareholders accept the offer and directors and executive officers of CEC announced that they intended to accept the exchange offer. On February 18, 2000, Carbon announced that the Company had completed its offer to exchange Carbon shares for shares of CEC. Of the 1,521,000 outstanding shares of CEC, over 97% of the shares were exchanged. Concurrent with the completion of the exchange offer, the American Stock Exchange ("AMEX") commenced proceedings to delist the common stock of CEC (trading symbol CGS). On February 28, 2000, the Securities and Exchange Commission approved the delisting of CEC's common stock from the AMEX. -1- Carbon began trading its shares on the American Stock Exchange on February 24, 2000 under the trading symbol CRB. Business Strategy ----------------- Our business strategy is to grow through exploitation of existing oil and gas properties by development of proved undeveloped reserves; acquisitions of complementary working interests in existing and adjacent properties; and optimization of gathering, compression and processing facilities. We will also conduct oil and gas exploration activities with the potential to add significant reserves and production and evaluate acquisition and merger opportunities in existing and future core areas. Our activities will be conducted in the United States primarily through BFC and in Canada through CEC. Employees and Offices --------------------- On December 31, 1999, the Company had 25 employees. None of these employees are represented by a labor union. The Company's executive offices are located at 1700 Broadway, Suite 1150, Denver, Colorado 80290, and its telephone number is (303) 863-1555. ITEM 2. PROPERTIES Piceance and Uintah Basins The Company operated at December 31, 1999, 131 wells and owned working interests in 148 wells in the Piceance Basin in Colorado and the Uintah Basin in Utah. Carbon and its predecessor, BFC, participated in the drilling and completion of one gas well in these basins during 1999 and additional drilling locations have been identified for further analysis and possible future drilling. The Company has leasehold rights in approximately 151,000 gross and 106,000 net acres of which approximately 110,500 gross and 78,000 net acres are undeveloped. San Juan Basin The Company operated at December 31, 1999, 41 wells and owns working interests in 42 wells in the San Juan Basin. Carbon its predecessor, BFC, participated in the drilling and completion of two gas wells in 1999. The Company has lease rights in approximately 5,000 gross and 4,500 net acres, of which approximately 2000 gross and 1,500 net acres are undeveloped. Permian Basin The Company owned working interests in 76 wells in the Permian Basin and operates 11 of these wells. During 1999, the Company and its predecessor, BFC, participated in the drilling of seven wells, of which five were completed as gas wells and two were completed as oil wells. The Company has lease rights in approximately 14,500 gross and 10,000 net acres, of which 5,000 gross and 3,500 net acres are undeveloped. -2- Southwestern Kansas The main exploratory efforts of Carbon are concentrated in southwestern Kansas. The Company owns working interests in 28 wells and operates four wells in this area. During 1999, the Company and its predecessor, BFC, participated in the drilling of three wells, of which two were completed as gas wells and one abandoned as a dry hole. The Company is conducting regional geologic and geophysical work to identify additional drilling prospects and is also currently acquiring acreage covering the most attractive prospects. The Company has lease rights in approximately 29,000 gross and 25,000 net acres of which 26,500 gross and 24,500 net acres are undeveloped. Proved Reserves --------------- The table below sets forth the estimated quantities of year end net proved reserves and the present values attributable to those reserves for the Company at December 31, 1999 and for BFC, the Company's predecessor, at December 31, 1998 and 1997. The estimates were prepared by Ryder Scott Company, an independent reservoir engineering firm.
Estimated Proved Reserves -------------------------------------------------------------------- December 31, -------------------------------------------------------------------- 1999 1998 1997 ------------------------- ------------------- ------------------- (dollars in thousands, except sales price data) Estimated Proved Reserves Natural gas (Mmcf) 31,012 25,855 23,140 Oil and condensate (MBbl) 228 166 298 Total (Mcfe) 32,380 26,851 24,928 Proved developed reserves (Mcfe) 27,504 26,851 24,411 Natural gas price as of December 31 ($/Mcf) 2.05 1.84 1.81 Oil price as of December 31 ($/Bbl) 24.41 10.69 16.91 Standardized measure of discounted net cash flows before income taxes (1) 25,894 20,495 19,629
- - - ------------------------------------------------------------------------------- (1) The standardized measure of discounted net cash flows prepared by the Company and its predecessor, BFC, represents the present value of estimated future net revenues before income taxes, discounted at 10%. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms or primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. At December 31, 1999, Carbon had approximately 26.2 Bcf of proved developed gas reserves representing 85% of Carbon's total proved gas reserves and 212,000 barrels of proved developed oil and natural gas liquid reserves representing 93% of the Company's total proved oil reserves. Approximately 7.1 Bcf of the 26.2 Bcf of proved developed natural gas reserves are primarily reserves for wells which have been completed and were awaiting connection to a gas pipeline as of year end, provided such pipeline connection does not require significant investment. Also included are reserves behind the casing in existing wells and recompletion of those zones will be required to place them in production. -3- Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. At December 31, 1999 Carbon's proved undeveloped reserves were approximately 4.8 Bcf of gas, or 15% of its total proved natural gas reserves, and 16,000 barrels of oil and natural gas liquids. These reserves are primarily attributable to undrilled locations offsetting production in various fields. Price declines decrease reserve values by lowering the future net revenues attributable to the reserves and reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. A significant decline in prices of oil or natural gas could have a material adverse effect on the Company's financial condition and results of operations. Future prices received from production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections. The present values shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is specified by the Securities and Exchange Commission, is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties operated by the Company and its predecessor, BFC, expenses exclude the Company's share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including among other things general and administrative costs and interest expense. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results of drilling, testing and production may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties the Company owns decline as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the proved reserves will decline as reserves are produced. -4- Production ---------- The following table sets forth annual net production for each of the three years ended December 31, 1999, for the Company and its predecessor, BFC. For 1999, the production includes the activities of the Company (consolidated inclusive of BFC) for November and December 1999 and Carbon's predecessor, BFC, for the period January through October 1999. Production figures for 1997 and 1998 are for the Company's predecessor, BFC. Net production includes volumes related to a production payment used to pay a related note. Volumes attributable to this activity were 223,786 Mcf in 1999, 249,571 Mcf in 1998 and 277,542 Mcf in 1997. Year ended December 31, ---------------------------------------------- 1999 1998 1997 -------------- -------------- -------------- Gas - Mmcf 4,074 3,272 2,908 Oil - Bbls 64,000 65,000 63,000 -5- Average price and cost per unit of production for the past three years are as follows (gas prices are inclusive of hedging results): Year ended December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------- ----------- Average sales price per Bbl of oil $17.44 $13.26 $19.48 Average sales price per Mcf of gas $2.07 $1.78 $1.79 Average production cost per Mcfe $0.77 $0.89 $0.85 We operate most of the wells in which we own interests and also hold working interests in some wells operated by third parties. Gas sales are generally made pursuant to gas purchase contracts with unrelated third parties. Our gas sales are subject to price adjustment provisions of the gas purchase contracts as well as general economic and political conditions affecting the production and price of natural gas. Producing Wells The following table sets forth the producing wells in which the Company owned a working interest at December 31, 1999. Wells are classified as oil or natural gas wells according to their predominant production stream. Productive Wells (1) -------------------------------------------------- Gas Wells Oil Wells ----------------------- ------------------------ Gross Net Gross Net ---------- ---------- ----------- ---------- Permian Basin 62 12 14 5 Piceance and Uintah Basins 142 125 6 5 San Juan Basin 39 23 2 2 Southwestern Kansas 14 5 14 4 ---------- ---------- ----------- ---------- Total 257 165 36 16 ========== ========== =========== ========== - - - ------------------------------------------------------------------------------- (1) Each well completed to more than one producing zone is counted as a single well. The Company has royalty interests in certain wells that are not included in this table. -6- Drilling Activities The Company engages in exploratory and development drilling on its own and in association with other oil and gas companies. The table below sets forth information regarding the Company's and its predecessor, BFC's, drilling activity for the last three years. For 1999, the table presents the drilling activities of the Company (consolidated inclusive of BFC) for November and December 1999 and Carbon's predecessor, BFC, for the period January through October 1999. Drilling activity for 1997 and 1998 are for the Company's predecessor, BFC.
Wells Drilled ----------------------------------------------------------------------------- Year Ended December 31, ----------------------------------------------------------------------------- 1999 1998 1997 -------------------------- ----------------------- ----------------------- Gross Net Gross Net Gross Net ---------- -------------- ---------- ----------- ---------- ----------- Development Natural gas 3 1.79 3 0.49 1 1.00 Oil 2 0.14 2 0.14 1 1.00 Non-Productive - - 3 2.25 - - ---------- -------------- ---------- ----------- ---------- ----------- Total 5 1.93 8 2.88 2 2.00 ========== ============== ========== =========== ========== =========== Exploratory Natural gas 7 4.23 1 0.26 - - Oil - - 1 1.00 - - Non-Productive 1 1.00 2 0.70 9 5.24 ---------- -------------- ---------- ----------- ---------- ----------- Total 8 5.23 4 1.96 9 5.24 ========== ============== ========== =========== ========== ===========
The following table sets forth the leasehold acreage held by the Company at December 31, 1999. Undeveloped acreage is acreage held under lease permit, contract or option that is not in a spacing unit for a producing well, including leasehold interests identified for development or exploratory drilling. Developed acreage is acreage assigned to producing wells.
Developed Acreage Undeveloped Acreage ------------------------------- ------------------------------- Gross Net Gross Net --------------- -------------- -------------- --------------- Permian Basin 9,690 6,695 4,995 3,467 Piceance and Uintah Basins 40,358 28,184 110,436 77,859 San Juan Basin - New Mexico 3,280 3,129 1,920 1,280 Southwestern Kansas 2,560 640 26,552 24,517 --------------- -------------- -------------- --------------- Total 55,888 38,648 143,903 107,123 =============== ============== ============== ===============
-7- Marketing --------- The Company markets all of its own natural gas and oil production from wells that it operates. Natural Gas As of December 31, 1999, the Company did not have any of its production committed to fixed price contracts nor is the Company committed to any firm transportation agreements. The Company has established a Risk Management Committee to oversee its production hedging. It is the policy of the Company that the Risk Management Committee approves all production hedging transactions. As of December 31, 1999, the Company has entered into financial transactions to hedge approximately 3,860,000 million MMBtu through 2001 at an average fixed price of $2.39 per MMBtu, (See Item 7A "Quantitative and Qualitative Disclosures About Market Risk"). Oil Oil production is generally sold to refiners, marketers and other purchasers who truck oil to local refineries or pipelines. The price is based upon a local market posting for oil which generally approximates a West Texas Intermediate posting, and is adjusted upward to reflect demand and quality. As of December 31, 1999, the Company had entered into financial transactions to hedge approximately 48,000 barrels of oil through December 2000 at an average fixed price of $22.35 per barrel (See Item 7A "Quantitative and Qualitative Disclosures About Market Risk"). Competition ----------- The oil and natural gas industry is highly competitive. The Company encounters competition from other oil and natural gas companies in all of its operations, including the acquisition of producing properties and exploration and development prospects. Major oil and gas companies and independent producers are active bidders for undeveloped acreage and desirable oil and gas properties as well as for the equipment and labor to operate such properties. Many competitors have financial resources greater than those of the Company. The ability of the Company to increase reserves in the future will be dependent on its ability to acquire desirable producing properties and prospects for future development and exploration. Title to Properties ------------------- Title to the Company's properties is subject to royalty, overriding royalty, carried, net profits, working and similar interests customary in the oil and gas industry. The Company's properties may also be subject to liens incident to operating agreements, as well as other encumbrances, easements and restrictions. As is customary in the industry in the case of undeveloped properties, only a perfunctory investigation as to ownership is conducted at the time of acquisition. Prior to the commencement of drilling operations, a title examination is performed and curative work is performed with respect to material title defects. The methods of title examination adopted by the Company are reasonably calculated in the opinion of management, to insure that production from its properties, if obtained, will be readily salable for the account of the Company. -8- Government Regulation --------------------- The Company's operations are regulated at the federal, state and local levels. Natural gas and oil exploration, development, production and marketing activities are subject to various laws and regulations and are periodically changed for a variety of political, economical and other reasons. The burden of the regulations increases the cost of doing business and may decrease flexibility by limiting the quantity of hydrocarbons the Company may produce and sell. The Company conducts certain operations on federal oil and gas leases, which the Mineral Management Service ("MMS") administers. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders. State statues govern exploration and production operations, conservation of oil and natural gas resources, protection of the correlative rights of natural gas and oil owners and environmental standards. State commissions establish rules and reclamation of sites, plugging bonds, reporting and other matters. Increasingly, a number of city and county governments have enacted natural gas and oil regulations which have increased the involvement of local governments in the permitting of natural gas and oil operations, and impart additional restrictions or conditions on the conduct of operators to mitigate the impact of operations on the surrounding community. These local restrictions have the potential to delay and increase the cost of natural gas and oil operations. The Company's natural gas sales are affected by regulation of intrastate and interstate transportation. In recent years the Federal Energy Regulatory Commission ("FERC") has issued a series of orders that has increased competition in the sale, purchase, marketing and transportation of natural gas which have helped natural gas become more responsive to changing market conditions. The Company believes that these changes have generally improved the Company's access to transportation and has enhanced the marketability of its natural gas production. To date the Company believes it has not experienced any material adverse effects as a result of these FERC orders; however the Company cannot predict what new regulations may be adopted by FERC and other regulatory authorities and the effect, if any, subsequent regulations may have on the Company. Environmental Regulation ------------------------ The Company, as a lessee and operator of natural gas and oil properties, is subject to various federal, state and local laws and regulations that provide for restriction and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facility sites and access be abandoned and reclaimed to the satisfaction of federal or state authorities, as applicable. A breach of such regulations may result in the imposition of fines and penalties, the suspension of operations and potential civil liability. The Company has made, and will continue to make, expenditures in its efforts to comply with environmental regulations which it believes is a necessary business cost in the oil and gas industry. The Company believes it is in compliance with applicable environmental laws and regulations in effect and that compliance will not have a material effect on capital expenditures or the Company's competitive position in the industry. In connection with the Company's acquisition of BFC, environmental assessments were performed resulting in no identified material noncompliance or clean-up liabilities requiring action in the immediate future; however environmental assessments were not performed on all of the Company's properties. The Company believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. No assurance can be given as to future capital expenditures which may be required for compliance with prospective environmental regulations. -9- Operating Hazards ----------------- The oil and gas business involves a variety of operating risks including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, gas leaks, ruptures and discharge of toxic substances. The occurrence of any of these events might result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and natural resources and investigation and penalties and suspension of operations. The Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that any such insurance that is obtained will be adequate to cover all losses or exposure for liability. Furthermore, the Company cannot predict whether such insurance will continue to be available at premium levels that justify its purchase. Item 3. Legal Proceedings There are no legal proceedings pending or, to our knowledge, threatened against us. Item 4. Submission of Matters to a Vote of Security Holders None. -10- PART II Item 5. Market for Registrants Common Equity and Related Stockholder Matters On February 24, 2000, the Company's shares began trading on the American Stock Exchange under the trading symbol CRB. On March 27, 2000, the closing price for the Company's common stock was 5 7/8 per share and there were 6,042,826 shares outstanding. At February 29, 2000, there were approximately 38 holders of record of the Company's common stock. The Company has not paid any cash dividends on its common stock and does not contemplate the payment of cash dividends since it plans to use available earnings for its drilling, development and acquisition programs. Payment of future cash dividends would also be dependent on earnings, financial requirements and other factors. As of September 15, 1999, Carbon sold 100 shares of its common stock to Yorktown Energy Partners III, L.P. ("Yorktown Energy Partners") at $5.50 in cash per share for an aggregate price of $550. On October 28, 1999, Carbon sold (1) 4,427,537 shares of its common stock to Yorktown Energy Partners at $5.50 in cash per share for an aggregate price of $24,351,453 and (2) 72,363 shares of its common stock to Yorktown Partners, LLC as agent for several investors, each of whom is believed by Carbon to be an accredited investor as defined in Regulation D of the Securities and Exchange Commission, at $5.50 in cash per share for an aggregate price of $397,996. On October 28, 1999, Carbon also sold 10,000 shares of its common stock to David H. Kennedy, a director of Carbon, at $5.50 in cash per share for an aggregate price of $55,000. As of January 31, 2000, Carbon sold 10,000 shares of its common stock to Cortlandt S. Dietler, a director, at $5.50 in cash per share for an aggregate price of $55,000. These transactions did not involve any underwriters, and there were no underwriting discounts or commissions. Carbon has relied on exemptions from securities registrations for these transactions. The relevant exemptions include Section 4(2) of the Securities Act of 1933, Rule 506 of Regulation D and Section 4(6) of the Securities Act of 1933. Carbon believes that all these purchasers were accredited investors. Item 6. Selected Financial Data The table below sets forth selected historical financial and operating data for the Company and its predecessor, BFC, as of or for each of the years in the five-year period ended December 31, 1999. For 1999, the table presents the activities of the Company (consolidated inclusive of BFC) for November and December 1999 (the Company's operating activities prior to November 1, 1999 were minimal) and Carbon's predecessor, BFC, for the period January through October 1999, and twelve months 1999 pro forma operating and cash flow data that combines these activities. The twelve month figures as of or for the year ended December 31, 1995 - 1998 are for Carbon's predecessor, BFC. Future results may differ substantially from historical results because of changes in oil and natural gas prices, production increases or declines and other factors. This information should be read in conjunction with the financial statements and notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations," presented elsewhere herein. -11-
Pro Forma As of or As of or For the for the for the 12 months two months ten months Ended Ended Ended December 31, December 31 October 31, -------------------- ------------------- -------------------- 1999 1999 1999 -------------------- ------------------- -------------------- (in thousands) Operating Data: Revenues $ 22,829 $ 2,803 $ 20,026 Net Earnings (loss) 147 (491) 638 Cash Flow Data: Cash provided by (used in) operating activities $ (713) $ 999 $ (1,712) Cash used in investing activities (28,841) (24,110) (4,731) Cash provided by (used in) financing activities 28,056 24,106 3,950 Balance Sheet Data: Total assets $ 39,298 $ 22,912 Working capital 232 1,954 Long-term debt 9,100 9,800 Stockholder's equity(1) 24,315 9,701 As of or for the Year Ended December 31, ---------------------------------------------------------------- 1998 1997 1996 1995 -------------- -------------- -------------- --------------- Operating Data: Revenues $ 21,092 $ 16,539 $ 15,067 $ 12,675 Net Earnings (loss) (2,191) 732 4,060 172 Cash Flow Data: Cash provided by (used in) operating activities $ 4,696 $ 3,193 $ 4,136 $ 3,016 Cash used in investing activities (5,948) (4,442) (1,025) (859) Cash provided by (used in) financing activities 3,450 1,019 (2,760) (2,090) Balance Sheet Data: Total assets $ 22,840 $ 16,054 $ 14,524 $ 13,177 Working capital 562 1,491 1,725 628 Long-term debt 5,850 2,400 1,700 4,760 Stockholder's equity(1) 9,063 9,591 8,859 6,774 (1) - - - -----------
(1) Includes debt to former parent company (BPC) of $3,737 in 1995 which was converted to equity in 1996. -12- Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The financial statements and related notes thereto included elsewhere herein are those of the Company, and its predecessor, BFC. The following discussion should be read in conjunction with the financial statements and notes thereto. Results of Operations - Comparison of 1999 results to 1998 ---------------------------------------------------------- The following table shows comparative revenue, sales volumes, average sales prices, expenses and the percentage change between periods for the twelve months ended December 31, 1999 and 1998. For 1999, the table presents the activities of the Company (consolidated inclusive of BFC) for November and December 1999 (the Company's operating activities prior to November 1, 1999 were minimal) and Carbon's predecessor, BFC, for the period January through October 1999 and twelve months 1999 pro forma data that combines these activities. The percentage change compares the pro forma data to 1998 results. The comparative results discussion that follows also compares the pro forma data to 1998 results. The twelve month figures for the year ended December 31, 1998 are for Carbon's predecessor, BFC.
Twelve Two Ten Twelve Months Months Months Months Ended Ended Ended Ended Twelve December 31, December 31, October 31, December 31, Months --------------- -------------- --------------- -------------- Percentage 1999 1999 1999 1998 Change --------------- -------------- --------------- -------------- ------------- (Pro forma) (Dollars in thousands, except prices and per Mcfe information) Revenues: Natural gas $ 8,429 $ 1,504 $ 6,925 $ 5,896 43% Oil 1,128 233 895 862 31% --------------- -------------- --------------- -------------- Total 9,557 1,737 7,820 6,758 Sales: Natural gas (MMcf) 4,074 569 3,505 3,272 25% Oil (Bbl) 64,000 9,000 55,000 65,000 -2% Average price received: Natural gas (Mcf) $ 2.07 $ 2.64 $ 1.98 $ 1.78 16% Oil (Bbl) 17.44 25.29 16.13 13.26 32% Production costs 3,457 597 2,860 3,254 6% Average production costs/Mcfe $ 0.78 $ 0.96 $ 0.75 $ 0.89 -12% Gas and electrical marketing revenue $ 12,619 $ 1,032 $ 11,587 $ 13,941 -9% Gas and electrical marketing expense 12,530 1,028 11,502 13,811 -9% General and administrative, net 2,559 939 1,620 1,655 55% Depreciation, depletion and amortization 2,720 628 2,092 2,086 30% Impairment expense 60 - 60 1,858 -97% Exploration expense 800 - 800 556 44% Interest expense, net 556 102 454 238 134%
-13- Oil and Gas Revenues Natural gas revenues for 1999 increased 43% compared to 1998 primarily due to a 25% increase in sales volumes and a 16% increase in sales prices. The increase in sales volumes were primarily due to successful drilling and recompletion results in various basins, particularly in western Kansas and in the Permian Basin of New Mexico, partially offset by production declines on existing properties. Oil revenues for 1999 increased 31% compared to 1998 due to a 32% increase in sales prices. Average daily natural gas and oil production for 1999 was approximately 11,162 Mcf of gas per day and 175 barrels of oil per day, an increase of 22% on a Mcfe basis from the same period in 1998. Oil and Gas Production Costs Oil and gas production costs consist of lease operating expense and severance taxes. Oil and gas production costs for 1999 and 1998 were $.77 and $.89, respectively, per Mcfe. The production costs of $.89 per Mcfe in 1998 included an accrual of $250,000 for the estimated liability under a well connection reimbursement agreement. The 1998 production costs per Mcfe would have been $.82 per Mcfe without these well connection costs. Gas and Electrical Marketing Gas and electrical marketing revenue and expense declined 9% in 1999 compared to 1998. General and Administrative Expenses G&A expenses relate to the direct costs of the Company which do not originate from either its operation of properties or the providing of services and are presented net of amounts billed to unrelated third parties. G&A expenses increased by $904,000 in 1999 compared to 1998. This increase is primarily due to one time charges approximating $1,025,000 due primarily to severance payments incurred as a result of the acquisition of BFC by the Company. During 1998, the Company's predecessor, BFC, increased staffing due to anticipated increases in drilling activity. In 1999 charges related to this increased staffing were in effect for the entire year resulting in comparative salary increases of approximately $400,000. In 1998, BFC accrued $425,000 for an employee retention bonus as the management of BFC and its former parent, BPC, deemed it prudent that BFC remain fully staffed as BPC emerged from bankruptcy. Depreciation, Depletion, Amortization and Impairment Expense Depreciation, depletion and amortization ("DD&A") of oil and gas assets are determined based upon the units of production method. This expense is typically dependent upon historical capitalized costs incurred to find, develop and recover oil and gas reserves; however, the Company's prospective DD&A rate will be determined primarily by the purchase price the Company allocated to oil and gas properties in connection with its acquisition of BFC and the proved reserves the Company acquired in the BFC acquisition. Through October 1999, the DD&A rate for the Company's predecessor, BFC, was $.55 per Mcfe compared to $.57 in 1998. As a result of the Company's acquisition of BFC and the resultant purchase accounting treatment, the current DD&A rate increased to $.99 per Mcfe. -14- Impairment losses were $60,000 in 1999 compared to $1,858,000 in 1998. Impairments taken in 1998 are as follows: South Humble City Field (SE New Mexico) - $931,000; Taiga Mountain (Western Colorado) - $713,000; Other - $214,000. The major assumptions used for determining impairment losses were as follows: Prices used were year-end 1998 prices for gas; $15.00/Bbl for oil; estimates of declining production were based on estimates by independent third party engineers; estimated operating cost and severance taxes were based on past experience. Impairment losses in 1998 were generally calculated by comparing the cost basis of proved properties with the undiscounted cash flows based on unescalated pricing. If the unamortized cost on a property was higher than the net undiscounted cash flow projected, the property was deemed to be possibly impaired. A further test was done at this point to determine the amount (if any) to impair. A subsequent test compared unamortized cost to the estimated fair market value. This test looked at the price of the commodity used in the initial test, and assessed whether it was representative of fair market value. Both tests described above used estimates by independent third party engineers to determine estimates of declining production. Additional considerations included in-house assessments of reserves attributable to a property. After the above tests, if a property was still deemed to require an impairment allowance, impairment was taken to reduce the carrying value to the estimated fair value. Technical reasons for impairments taken in 1998 are pressure declines in the reservoir for the South Humble City Field and unsuccessful offset drilling which indicated a smaller reservoir than originally forecast for the Taiga Mountain Field. Reserve categories used in the impairment test include all categories of proven reserves. There were no categories of reserves used other than proved (i.e. no probable or possible). Effective as of the date of the acquisition of BFC, the Company utilizes the full cost method of accounting and will be subject to full cost ceiling provisions applicable in assessing impairment of the full cost pool. Exploration Expense Through October 1999, exploration expense was recorded by the Company's predecessor, BFC, under the successful efforts method of accounting and consists primarily of unsuccessful drilling and geological and geophysical ("G&G") costs. Exploration expense in 1999 was $800,000 compared to $556,000 in 1998. The amount related to unsuccessful drilling was $304,000 in 1999 compared to $84,000 in 1998, while G&G costs increased to $496,000 compared to $390,000 in 1998 because of increased exploration activities. Effective as of the date of the acquisition of BFC, Carbon utilizes the full cost method of accounting. Under this method, all exploration costs associated with continuing efforts to acquire or review prospects and outside geological and seismic consulting work will be capitalized. Interest Expense Interest expense was $556,000 in 1999 compared to $238,000 in 1998. The increase in 1999 is primarily due to increased borrowings for drilling and development activity. Income Taxes The Company and its predecessor, BFC, accounts for income taxes under the liability method which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using actual -15- tax rates in effect for the year in which the differences are expected to reverse. The operations of the Company's predecessor, BFC were included in BPC's consolidated tax return through October 29, 1999. Income taxes were allocated to BFC as if BFC was a separate taxpayer. Results of Operations - Comparison of 1998 results to 1997. ----------------------------------------------------------- The following table shows comparative revenue, sales volumes, average sales prices, expenses and the percentage change between periods for the twelve months ended December 31, 1998 and 1997. These twelve month figures are for the Company's predecessor, BFC.
Twelve Months Ended December 31, ------------------------------------------------ 1998 1997 % Change ----------------- -------------- ------------ (Dollars in thousands, except prices and per Mcfe information) Revenues: Natural gas $ 5,896 $ 5,202 13% Oil 862 1,227 -30% -------------- -------------- Total 6,758 6,429 Sales: Natural gas (MMcf) 3,272 2,908 13% Oil (Bbl) 65,000 63,000 3% Average price received: Natural gas (Mcf) $ 1.78 $ 1.79 -1% Oil (Bbl) 13.26 19.48 -32% Production costs 3,254 2,779 17% Average production costs/Mcfe $ 0.89 $ 0.85 5% Gas and electrical marketing revenue $ 13,941 $ 9,641 45% Gas and electrical marketing expense 13,811 9,050 53% General and administrative, net 1,655 590 181% Depreciation, depletion and amortization 2,086 1,942 7% Impairment expense 1,858 312 496% Exploration expense 556 772 -28% Interest expense, net 238 83 187%
Oil and Natural Gas Revenues Natural gas revenues for 1998 increased 13% compared to 1997 primarily due to a 13% increase in sales volumes. Oil revenue for 1998 decreased 30% compared to 1997 primarily due to a 32% decrease in sales prices. The increases in sales volumes were primarily due to successful drilling and recompletion activity, partially offset by production declines on previously existing properties. -16- Oil and Gas Production Costs Oil and gas production costs consist of lease operating expense and severance taxes. Oil and gas production costs for 1998 and 1997 were $.89 and $.85 respectively, per Mcfe. The 1998 production costs of $.89 per Mcfe included an accrual of $250,000 for the estimated liability under a well connection reimbursement agreement. The 1998 production costs per Mcfe would have been $.82 per Mcfe without these well connection costs. Gas and Electrical Marketing Gas and electrical marketing revenue increased 45% in 1998 compared to 1997 while gas and electrical marketing expense increased 53% in 1998 compared to 1997. Certain high margin contracts expired early in 1997. The related margins were not present during most of 1997, nor in 1998. General and Administrative Expenses G&A expenses relate to the direct costs of BFC which do not originate from either its operation of properties or the providing of services and are presented net of amounts billed to unrelated third parties. G&A expenses increased by $1,065,000 in 1998 compared to 1997. In 1998, BFC accrued $425,000 for an employee retention bonus. The remainder of the increase is primarily due to costs associated with additional staffing related to anticipated increases in drilling activity. Depreciation, Depletion, Amortization and Impairment Expense DD&A of oil and gas assets are determined based upon the units of production method. This expense is primarily dependent upon historical capitalized costs incurred to find, develop and recover oil and gas reserves. For 1998 the depletion rate was $.57 per Mcfe compared to $.59 per Mcfe in 1997. Impairment losses were $1,858,000 in 1998 compared to $312,000 in 1997. Impairments taken in 1998 are as follows: South Humble City Field (SE New Mexico) - $931,000; Taiga Mountain (Western Colorado) - $713,000; Other - $214,000. The major assumptions used for determining impairment losses were as follows: Prices used were year-end 1998 prices for gas; $15.00/Bbl for oil; estimates of declining production were based on estimates by independent third party engineers; estimated operating cost and severance taxes were based on past experience. Impairment losses in 1998 were generally calculated by comparing the cost basis of proved properties with the undiscounted cash flows based on unescalated pricing. If the unamortized cost on a property was higher that the net undiscounted cash flow projected, the property was deemed to be possibly impaired. A further test was done at this point to determine the amount (if any) to impair. A subsequent test compared unamortized cost to the estimated fair market value. This test looked at the price of the commodity used in the initial test, and assessed whether it was representative of fair market value. Both tests described above used estimates by independent third party engineers to determine estimates of declining production. Additional considerations included in-house assessments of reserves attributable to a property. After the above tests, if a property was still deemed to require an impairment allowance, impairment was taken to reduce the carrying value to the estimated fair value. Technical reasons for impairments taken in 1998 are pressure declines in the reservoir for the South Humble City Field and unsuccessful offset drilling which indicated a smaller reservoir than originally forecast for the Taiga Mountain Field. -17- The primary factor causing the impairments in 1997 was the reevaluation of certain undeveloped leases. Reserve categories used in the impairment test include all categories of proven reserves. There were no categories of reserves used other than proved (i.e. no probable or possible). Exploration Expense Exploration expense was recorded under the successful efforts method of accounting and consists primarily of unsuccessful drilling costs and G&G costs. Exploration expense in 1998 was $556,000 compared to $772,000 in 1997. The amount related to unsuccessful drilling was $84,000 in 1998 compared to $599,000 in 1997, while G&G costs increased in 1998 to $390,000 compared to $89,000 in 1997 because of increased exploration activities. Interest Expense Interest expense was $238,000 in 1998 compared to $83,000 in 1997. The increase in 1998 is primarily due to increased borrowings for drilling and development activity and because of lower prices received from oil and gas sales. Income Taxes The Company and its predecessor, BFC, accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The operations of the Company's predecessor, BFC, were included in BPC's consolidated tax return. Income taxes were allocated to BFC as if BFC was a separate taxpayer. Effects of Changing Prices The U.S. economy experienced considerable inflation during the late 1970's and early 1980's but in recent years inflation has been fairly stable at relatively low levels. The Company, along with most other business enterprises, was then and will be affected in the future by any recurrence of such inflation. Changing prices, or a change in the dollar's purchasing power, distorts the traditional measures of financial performance which are generally expressed in terms of the actual number of dollars exchanged and do not take into account changes in the purchasing power of the monetary unit. This results in the reporting of many transactions over an extended period as though the dollars received or expended were of common value, which does not accurately portray financial performance. Inflation, as well as a recessionary period, can cause significant swings in the interest rates that companies pay on bank borrowings. These factors are anticipated to continue to affect the Company's operations both positively and negatively for the foreseeable future. Oil and gas prices fluctuate over time as a function of market economies. Refer to the price change tables in the discussions "Oil and Gas Operations Comparisons for 1999, 1998 and 1997" for information on product price fluctuation over the past three years. These tables depict the effect of changing prices on the revenue stream of the Company and its predecessor, BFC. Operating expenses have been relatively stable but are a critical component of profitability since they represent a larger percentage of revenues when lower product prices prevail. Competition in the industry can significantly affect the cost of acquiring leases, although in recent years this factor has been less important as more operators have withdrawn from active exploration programs. -18- Liquidity and Capital Resources ------------------------------- At December 31, 1999, the Company had $39.3 million of assets. Total capitalization was $33.4 million, consisting of 73% of stockholder's equity and 27% of debt. In October, 1999, the Company sold 4,500,000 shares of common stock to Yorktown for $24,750,000 of which $23,581,000 was used to purchased the stock of BFC in October 1999. The remaining proceeds have been used to fund working capital. The Company has a credit facility with U.S. Bank National Association. The purpose of the loan is to provide financing for the acquisition of oil and gas reserves and for normal operating requirements. The facility is collateralized by certain oil and gas properties of the Company and is scheduled to convert to a term note on July 1, 2001. The term loan is scheduled to have a maturity of either the economic half life of the Company's remaining reserves on the date of conversion, or July 1, 2006, whichever is earlier. The borrowing base is based upon the lender's evaluation of the Company's proved oil and gas reserves, generally determined semi-annually. The future minimum principal payment under the term loan will be dependent upon the bank's evaluation of the Company's reserves at that time. The borrowing base was $16.4 million at December 31, 1999 with interest at a variable rate that approximated 8.2% at December 31, 1999. At December 31, 1999, outstanding borrowings were $9,100,000. In addition, the Company has issued letters of credit totaling $2.0 million which further reduces the amount available for borrowing under the base. The credit agreement contains various covenants which prohibit or limit the Company's ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties or merge with another entity. The Company is also required to maintain certain financial ratios. The Company's predecessor, BFC, has periodically negotiated extensions and additions to the loan, however, there is no assurance the Company were be able to do so in the future. For the twelve months ended December 31, 1999, pro forma net cash used by operating activities for the Company, and its predecessor, BFC, was $713,000 compared to net cash provided by operating activities of $4,696,000 in 1998. The decrease was primarily due to changes in operating assets and liabilities. Pro forma cash used in investing activities was $28,841,000 in 1999 compared to $5,948,000 in 1998. Pro forma net cash provided by financing activities was $28,056,000 for 1999 compared to $3,450,000 in 1998. Changes in comparative investing and financing cash flows were due primarily to the Company's acquisition of BFC. The principle source of the Company's funds are cash flows from operating activities and available borrowings under the Company's existing credit facility. At December 31, 1999, there were no significant commitments for capital expenditures. The Company anticipates that capital expenditures, exclusive of acquisitions (if any) will approximate $5.0 million in 2000. The Company expects to be able to fund its development and exploration programs for the next twelve months from cash generated by operations and existing bank financing. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. Year 2000 Compliance -------------------- The conversion from calendar year 1999 to 2000 occurred without any disruption in the Company's operations and information systems nor has the Company been made aware of any Year 2000 issues occurring at third parties with which Carbon has relations. The Company will continue to monitor any Year 2000 issues, both internally and with third parties of business importance to the Company such as its natural gas purchasers, gathering system and plant operators, downstream pipeline operators, equipment and service providers, operators of its oil and gas properties, financial institutions and vendors providing payroll and medical benefits and services. The Company believes that the most serious effect to the Company would be delays in receiving payments for oil and gas sold to its purchasers which could have a material adverse effect upon the results of operations and financial conditions of the Company. This monitoring will be ongoing and encompassed in normal operations. -19- Disclosures Regarding Forward-Looking Statements ------------------------------------------------ This Annual Report on Form 10-K includes "forward-looking statements". All statements other than statements of historical facts included in the Annual Report on Form 10-K are forward-looking statements. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and natural gas, business strategies, expansion and growth of the Company's operations, cash flow and anticipated liquidity, prospect development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. Although the Company believes that the expectations reflected in the forward-looking statements and the assumptions upon which such forward-looking statements are based are reasonable, it can give no assurance that such expectations and assumptions will prove to be correct. Factors that could cause actual results to differ materially ("Cautionary Statements") are described, in among other places in the Marketing, Competition, and Government Regulation sections in this Form 10-K and under "Management's Discussion and Analysis of Financial Condition and Results of Operations." These factors include, but are not limited to general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company of persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Quantitative and Qualitative Disclosures about Market Risk ---------------------------------------------------------- Interest Rate Risk Market risk is estimated as the potential change in fair value resulting from an immediate hypothetical change in interest rates. The sensitivity analysis presents the change in fair value of these instruments and changes in the Company's earnings and cash flows assuming an immediate one percent change in floating interest rates. As the Company presently only has floating rate debt, interest rate changes would not affect the fair value of these instruments but would impact future earnings and cash flows assuming all other factors are held constant. The carrying amount of the Company's floating rate debt approximates its fair value. At December 31, 1999 and December 31, 1998, the Company and its predecessor, BFC, had floating rate debt of $9,100,000 and $5,850,000, respectively. Assuming constant debt levels, earnings and cash flow impacts for the next twelve month period from December 31, 1999 and December 31, 1998 due to a one percent change in interest rates would be approximately $91,000 and $58,500, respectively, before taxes. Foreign Currency Risk To date the Company's cash flows have been in U.S. dollars only, negating the need to hedge against any foreign currency risks. Commodity Price Risk Oil and gas commodity markets are influenced by global as well as regional supply and demand. Worldwide political events can also impact commodity prices. The Company uses certain financial instruments in an attempt to manage commodity price risk. The Company attempts to manage these risks by minimizing its -20- commodity price exposure through the use of derivative contracts as described in Note 8 to the December 31, 1999 financial statements of Carbon and in Note 8 to the October 31, 1999 financial statements of BFC. These tools include, but are not limited to: commodity futures and option contracts; fixed-price swaps; basis swaps; and term sales contracts. Gains and losses on these contracts are deferred and recognized in income as an adjustment to oil and gas sales revenue during the period in which the physical product to which the contract relates to is actually sold. The following tables summarize the Company's derivative financial instrument position on its natural gas and oil production as of December 31, 1999. Weighted Average Fixed price Year MMBTUs per MMBTU - - - -------------- ------------- ---------------- 2000 2,317,500 $ 2.42 2001 1,543,000 $ 2.36 ------------- 3,860,500 ============= Weighted Average Fixed price Year Barrels per Barrel - - - -------------- ------------- ---------------- 2000 48,000 $ 22.35 As of December 31, 1999, the Company would have been required to pay $733,000 to exit these contracts and all related hedging obligations. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -21- Carbon Energy Corporation Consolidated Financial Statements -22- INDEX TO FINANCIAL STATEMENTS PAGE ---- Report of Independent Public Accountants......................................24 Consolidated Balance Sheet - December 31, 1999................................25 Consolidated Statement of Operations - For the Period from Inception (September 14, 1999) through December 31, 1999...........................26 Consolidated Statement of Stockholder's Equity - For the Period from Inception (September 14, 1999) through December 31, 1999.................27 Consolidated Statement of Cash Flows - For the Period from Inception (September 14, 1999) through December 31, 1999...........................28 Notes to Consolidated Financial Statements....................................29 -23- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Carbon Energy Corporation: We have audited the accompanying consolidated balance sheet of Carbon Energy Corporation (a Colorado corporation) and subsidiary as of December 31, 1999, and the related consolidated statements of operations, stockholder's equity and cash flows for the period from inception (September 14, 1999) through December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. 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 audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carbon Energy Corporation and subsidiary as of December 31, 1999, and the results of their operations and their cash flows for the period from inception (September 14, 1999) through December 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Denver, Colorado, March 28, 2000 -24- CARBON ENERGY CORPORATION CONSOLIDATED BALANCE SHEET
December 31, 1999 -------------- ASSETS ------ Current assets: Cash $ 995,000 Current portion of employee trust 881,000 Accounts receivable, trade 2,286,000 Accounts receivable, other 69,000 Amounts due from broker 1,250,000 Prepaid expenses and other 107,000 -------------- Total current assets 5,588,000 -------------- Property and equipment, at cost: Oil and gas properties, using the full cost method of accounting: Unproved properties 7,879,000 Proved properties 25,020,000 Furniture and equipment 214,000 -------------- 33,113,000 Less accumulated depreciation, depletion and amortization (627,000) -------------- Property and equipment, net 32,486,000 -------------- Other Assets: Deferred acquisition costs 310,000 Deposits and other 245,000 Employee trust 669,000 -------------- Total other assets 1,224,000 -------------- $ 39,298,000 ============== Total Assets LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ Current liabilities: Accounts payable and accrued expenses $ 4,391,000 Accrued production taxes payable 367,000 Undistributed revenue 598,000 -------------- Total current liabilites 5,356,000 -------------- Long-term debt 9,100,000 Other long-term liabilites 527,000 ------------ Total long-term liabilities 9,627,000 Commitments and contingencies (Note 5) - Stockholders' equity: Preferred stock, no par value: 10,000,000 shares authorized, none outstanding - Common stock, no par value: 20,000,000 shares authorized, issued, and 4,510,000 shares outstanding 24,806,000 Accumulated deficit (491,000) ------------- Total stockholders' equity 24,315,000 ------------- Total liabilities and stockholders' equity $ 39,298,000 =============
The accompanying notes are an integral part of these consolidated financial statements. -25- CARBON ENERGY CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS For the Period from Inception (September 14, 1999) through December 31, 1999 ---------------------- Revenues: Oil and gas sales $ 1,737,000 Gas marketing and transportation 1,032,000 Other 34,000 --------------------- 2,803,000 --------------------- Expenses: Oil and gas production costs 597,000 Gas marketing and transportation costs 1,028,000 Depreciation, depletion and amortization expense 628,000 General and administrative expense, net 939,000 Interest expense, net 102,000 --------------------- 3,294,000 --------------------- Net loss $ (491,000) ===================== Earings per share Basic and diluted $ (0.12) Average number of common shares outstanding (in thousands): Basic and diluted 4,056 The accompanying notes are an integral part of these consoldiated financial statements. -26- CARBON ENERGY CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY For the Period from Inception (September 14, 1999) through December 31, 1999
Common Stock --------------------------------- Accumulated Shares Amount Deficit Total -------------- ---------------- ----------------- ------------------- Balances, September 14, 1999 - $ - $ - $ - Issuance of common stock 4,510,000 24,806,000 24,806,000 Net loss - (491,000) (491,000) -------------- ---------------- ----------------- ------------------- Balances, December 31, 1999 4,510,000 $ 24,806,000 $ (491,000) $ 24,315,000 ============== ================ ================= ===================
The accompanying notes are an integral part of these consolidated financial statements. -27- CARBON ENERGY CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS
For the Period from Inception (September 14, 1999) through December 31, 1999 --------------------- Cash flows from operating activities: Net loss $ (491,000) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization expense 628,000 Changes in operating assets and liabilities: Decrease (increase) in: Accounts receivable, trade 203,000 Amounts due from broker 269,000 Employee trust 17,000 Prepaid expenses and other 38,000 Other assets (337,000) Increase (decrease) in: Accounts payable and accrued expenses 711,000 Undistributed revenue (39,000) --------------------- Net cash provided by operating activities 999,000 Cash flows from investing activities: Acquisition of Bonneville Fuels Corporation (23,521,000) Capital expenditures for oil and gas properties (589,000) --------------------- Net cash used in investing activities (24,110,000) Cash flows from financing activities: Proceeds from note payable 400,000 Principal payments on note payable (1,100,000) Proceeds from issuance of common stock 24,806,000 --------------------- Net cash provided by financing activities 24,106,000 --------------------- Net increase in cash 995,000 Cash, beginning of year --------------------- Cash, end of year $ 995,000 ===================== Supplemental cash flow information: Cash paid for interest $ 121,400 ===================== The accompanying notes are an integral part of these consolidated financial statements.
-28- CARBON ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Nature of Operations and Significant Accounting Policies: -------------------------------------------------------- Nature of Operation - Carbon Energy Corporation (Carbon) was incorporated ------------------- under the laws of the State of Colorado on September 14, 1999. Carbon is an independent oil and gas company engaged in the acquisition, exploration, development, gathering, production and marketing of natural gas and crude oil through Bonneville Fuels Corporation (BFC), its wholly owned subsidiary. BFC also purchases and resells electricity. BFC was acquired by Carbon on October 29, 1999. The acquisition was accounted for as a purchase as more fully described in Note 2. BFC was formed in April of 1987, and owns two active subsidiaries; Bonneville Fuels Management Corporation (BFM Corp.) and Colorado Gathering Corporation (CGC), and two inactive subsidiaries; Bonneville Fuels Marketing Corporation (BFMC) and Bonneville Fuels Operating Corporation (BFO). Collectively, Carbon, BFC and BFC's subsidiaries are referred to as the Company. Principles of Consolidation - The consolidated financial statements include --------------------------- the accounts of Carbon and its consolidated subsidiary. Significant intercompany transactions and balances are eliminated. Cash Equivalents - The Company considers all highly liquid instruments with ---------------- original maturities of three months or less when purchased to be cash equivalents. Amounts Due From Broker- This account generally represents net cash margin ----------------------- deposits held by a brokerage firm for the Company's futures accounts. Property and Equipment - The Company follows the full cost method of ---------------------- accounting for its oil and gas properties, all of which are located in the continental United States. Under this method of accounting, all costs incurred in the acquisition, exploration and development of properties (including cost of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) are capitalized. Capitalized costs are depleted using the units of production method based on proved reserves of oil and gas. For purposes of this calculation, oil and gas reserves are converted to a common unit of measure on the basis of six thousand cubic feet of gas to one barrel of oil. A reserve is provided for the estimated future cost of site restoration, dismantlement and abandonment activities as a component of depletion. Investments in unproved properties are recorded at the lower of cost or fair market value and are not depleted pending the determination of the existence of proved reserves. Pursuant to full cost accounting rules, capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using a 10% discount factor and unescalated oil and gas prices as of the end of the period; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the cost being amortized, if any; less (4) related income tax effects. The costs reflected in the accompanying financial statements do not exceed this limitation. Proceeds from disposal of interests in oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustment would significantly alter the rate of depletion. Buildings, transportation and other equipment are depreciated on the straight-line method with lives ranging from 3 to 7 years. -29- Employee Trust - The employee trust represents amounts which will be used to -------------- satisfy obligations to persons who have been, or will be, terminated as a result of the Company's acquisition of BFC (see Notes 2 and 4). The current portion of the employee trust is expected to be disbursed by December 31, 2000. Undistributed Revenue - Represents amounts due to other owners of jointly --------------------- owned oil and gas properties for their share of revenue from the properties. Revenue Recognition - The Company follows the sales method of accounting for ------------------- natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Company is entitled based on its interests in the properties, creating gas imbalances. Revenue is deferred and a liability is recorded for those properties where the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Company records sales and related cost of sales on gas and electricity marketing transactions using the accrual method of accounting (i.e., the transaction is recorded when the commodity is purchased and/or delivered). The Company's gas marketing contracts are generally month-to-month and provide that the Company will sell gas to end users which is produced from the Company's properties and/or acquired from third parties. Income Taxes - The Company accounts for income taxes under the liability ------------ method which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Hedging Transactions - The Company periodically enters into commodity -------------------- futures and option contracts, fixed price swaps and basis swaps as hedges of commodity prices associated with the production of oil and gas and with the purchase of natural gas in order to mitigate the risk of market price fluctuations. Pursuant to Company guidelines, the Company is to engage in these activities only as a hedging mechanism against price volatility associated with pre- existing or anticipated gas or crude oil sales in order to protect profit margins. Changes in the market value of futures, forwards, and swap contracts are not recognized until the related production occurs or until the related gas purchase takes place. Realized losses from any positions which are closed early are deferred and recorded as an asset or liability in the accompanying balance sheet, until the related production, purchase or sale takes place. In the event energy financial instruments do not qualify for hedge accounting, the difference between the current market value and the original contract value would be currently recognized in the statement of operations. Gains and losses incurred on these contracts are included in oil and gas revenue or in gas marketing costs in the accompanying statement of operations. 30 Upon the acquisition of BFC (see Note 2), the Company assumed open hedge contracts held by BFC that when marked to market reflected an obligation of $1,733,000. This obligation was recognized as a part of the purchase price of BFC. The corresponding obligation was recorded as a liability. At December 31, 1999, this obligation was $1,508,000. The obligations related to hedge positions which will mature within the year 2000 are included as current liabilities, while the obligations maturing in 2001 are presented as other long-term liabilities. The following tables summarize the Company's derivative financial instrument position on its natural gas and oil production as of December 31, 1999: Weighted Average Fixed price Year MMBTUs per MMBTU - - - -------------- ------------- ---------------- 2000 2,317,500 $ 2.42 2001 1,543,000 $ 2.36 ------------- 3,860,500 ============= Weighted Average Fixed price Year Barrels per Barrel - - - -------------- ------------- ---------------- 2000 48,000 $ 22.35 As of December 31, 1999, the Company would have been required to pay $733,000 to exit these contracts and all related hedging obligations. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). The Company is required to adopt SFAS No. 133 as of January 1, 2001, but may implement it as of the beginning of any fiscal quarter prior to that date. SFAS No. 133 cannot be applied retroactively. The Company has not yet quantified the impacts of adopting SFAS No. 133 or determined the timing or methods of adoption. However, SFAS No. 133 could increase the volatility of the Company's earnings and comprehensive income. Earnings (Loss) Per Share. Basic earnings per share is computed by dividing ------------------------- income or (loss) available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if the Company's outstanding stock options were exercised (calculated using the treasury stock method). The consolidated statement of operations for 1999 reflects only basic earnings per share because the Company was in a loss position and all common stock equivalents are anti-dilutive. Accounting Estimates - The preparation of financial statements in conformity -------------------- with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these financial statements and the accompanying notes. The actual results could differ from those estimates. 2. Purchase of Bonneville Fuels Corporation: ----------------------------------------- On October 29, 1999, Carbon completed the acquisition of 100% of the stock of BFC. The purchase price of $38,714,000 was composed of the following: Current liabilities assumed $ 3,411,000 Open hedges assumed 1,733,000 31 Long-term debt assumed 9,800,000 Professional fees 189,000 Cash paid 23,581,000 ------------------- $ 38,714,000 =================== 3. Long-term debt: -------------- The Company has an asset-based line-of-credit with a bank which provides for borrowing up to the borrowing base (as defined). The borrowing base was $16,400,000 at December 31, 1999. At December 31, 1999, outstanding borrowings were $9,100,000. The Company has issued letters of credit totaling $2,000,000, which further reduces the amount available for borrowing under the base. This facility is collateralized by certain oil and gas properties of the Company and is scheduled to convert to a term note on July 1, 2001. This term loan is scheduled to have a maturity of either the economic half life of the Company's remaining reserves on the date of conversion, or July 1, 2006, whichever is earlier. The facility bears interest at prime or (at the Company's option) LIBOR plus 1.75%. This rate approximated 8.2% at December 31, 1999. The borrowing base is based upon the lender's evaluation of the Company's proved oil and gas reserves, generally determined semi-annually. Scheduled maturities of indebtedness for the next five years are as follows: Year Maturities --------- ----------------- (in thousands) 2000 $ -- 2001 1,166 2002 2,684 2003 2,095 2004 1,843 The credit agreement contains various covenants which prohibit or limit the Company's ability to pay dividends, purchase treasury shares, incur indebtedness, sell properties or merge with another entity. The Company is also required to maintain certain financial ratios. The Company also has an accounts receivable-based credit facility which includes a revolving line-of-credit with the bank which provides for borrowings and letters of credit up to $500,000. There were no outstanding borrowings under this facility at December 31, 1999, however, there was a letter of credit issued in the amount of $40,000, which reduces the amount available under this line. This facility bears interest at prime (8.5% at December 31, 1999). This facility is collateralized by certain trade receivables of the Company and has a maturity date of July 1, 2001. 4. Salary Continuation Plan: ------------------------ In 1999, BFC established a Salary Continuation Plan (the "Plan"). The Plan provides for continuation of salary and health, dental disability, and life insurance benefits for a certain period of time based on employment contracts or length of service, if the employee is terminated within 2 years following the effective date of BFC's acquisition by Carbon. The maximum amount which could be disbursed under the Plan is $1,546,000. The employees will be required to pay any increased premiums for the insurance benefits and the Plan insurance commitment is capped at the above amount. Terminations as of December 31, 1999 will require payments under the Plan of $438,000. Costs associated with these terminations were expensed by BFC prior to the acquisition and accrued at December 31, 1999. 32 At December 31, 1999, contracts with various employees have resulted in the actual payment or agreement to pay an additional $513,000 from the trust. These payments were expensed in 1999. The Company has deposited the maximum amount in a employee trust cash account. This trust is restricted from disbursing funds except for the payment of benefits or upon the insolvency of the Company. The amount the Company is obligated to pay in 2000 due to the above mentioned terminations and contracts is recorded as a current asset. All remaining amounts are recorded as long-term assets. The trustee fees were minimal for the period ending December 31, 1999. 5. Commitments: ----------- Office Lease - The Company leases office space under a lease which ------------ terminates on March 31, 2000. Total rental expense under this lease was approximately $25,000 for the two months ended December 31, 1999. With the acquisition of BFC, the Company assumed the obligations of BFC's office lease. In conjunction with the acquisition of CEC Resources (see Note 10), the Company also had an existing office lease obligation prior to the acquisition of BFC. The Company entered an agreement to buyout the remaining term of the BFC lease for $100,000. The Company has entered into a new lease agreement, effective on April 1, 2000, which provides for total minimum rental commitments as follows: 2000 $ 182,000 2001 197,000 2002 203,000 2003 208,000 2004 212,000 Thereafter 53,000 ------------------ $ 1,055,000 ================== 33 6. Stock Options and Award Plans: ----------------------------- In 1999, the Company adopted a stock option plan to afford an opportunity for stock ownership to selected employees, directors and consultants of the Company and its subsidiaries. All salaried employees of the Company and its subsidiaries who are responsible for the conduct and management of its business or who are involved in the endeavors significant to its success are eligible to receive both incentive stock options and nonqualified stock options. Directors and consultants who are not employees of the Company or its subsidiaries but who are involved in endeavors significant to its success are eligible to receive non-qualified stock options, but not incentive stock options under the plan. The option price for the incentive stock options granted under the plan are not to be less than 100% of the fair market value of the shares subject to the option. The option price for the nonqualified stock options granted under the plan are not to be less than 85% of the fair market value of the shares subject to the options. The aggregate number of shares of common stock which may be issued under options granted pursuant to the plan may not exceed 700,000 shares. The specific terms of grant and exercise are determined by the Company's Board of Directors unless and until such time as the Board of Directors delegates the administration of the plan to a committee. The options vest over a three-year period and expire ten years from the date of grant. A summary of the status of the Company's stock option plan as of December 31, 1999 and changes during 1999 is presented below: 1999 ---------------------------- Weighted Average Exercise Shares Price ------------ ----------- Outstanding at beginning of period - Granted 115,000 $ 5.50 Exercised - Forfeited - ------------ Shares under option at end of year 115,000 ============ Options exercisable at year-end - Shares available for future grant at year-end 585,000 Weighted-average fair value of options granted during the year $ 1.28 The following table summarizes information about the Company's stock options outstanding at December 31, 1999.
Options Outstanding Options Exercisable - - - -------------------------------------------------------------------------------- --------------------------------------------- Options Weighted-Avg. Options Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg. Exercise Price at Year-end Contractual Life Exercise Price at Year-end Exercise Price - - - ----------------- ---------------- ------------------- ----------------- ---------------- ------------------ $5.50 115,000 9.83 years $5.50 - -
34 The Company applies APB Opinion No. 25 "Accounting for Stock Issued to Employees" and related interpretations in accounting for these plans. Under APB Opinion No. 25 no compensation costs are recognized for option grants that are equal to or greater than the market price at the time of the grant. If compensation costs for this plan had been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," the Company's net loss and loss per share would have been reduced as follows: For the Period from Inception (September 14, 1999) through December 31, 1999 ----------------------- Net loss: As reported ($491) Pro forma ($504) Loss per share: As reported ($.12) Pro forma (S.12) The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: dividend yield of 0%; expected volatility of 24%; risk-free interest rate of 5.97% and expected live of 5 years. In 1999, the Company adopted a restricted stock plan to afford an opportunity for stock ownership to selected employees, directors and consultants of the Company and its subsidiaries. The aggregate number of shares of common stock which may be issued under the plan may not exceed 300,000 shares. In 1999 40,000 shares of restricted shares of common stock were granted. The shares vest ratably over 36 months. 7. Income Taxes: ------------- Deferred tax assets are comprised of the following: As of December 31, 1999 -------------- (in thousands) Net operting loss carryforward $ 297 Oil, gas and other property basis difference (195) Other 90 -------------- Total deferred tax assets 192 Less valuation allowence (192) -------------- Net deferral tax assets $ - ============== 8. Concentrations of Credit Risk and Price Risk Management: -------------------------------------------------------- Concentrations of Credit Risk - Substantially all of the Company's accounts ----------------------------- receivable at December 31, 1999 result from crude oil and natural gas sales and/or joint interest billings to companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, since these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owners, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on trade receivables by the Company have been insignificant. 9. Fair Value of Financial Instruments: ------------------------------------ The Company's on-balance sheet financial instruments consist of cash, cash equivalents, accounts receivable, inventories, accounts payable, other accrued liabilities and long-term debt. Except for long-term debt, the 35 carrying amounts of such financial instruments approximate fair value due to their short maturities. At December 31, 1999, the fair market value of long-term debt was not materially different from its carrying amount. The Company's off-balance sheet financial instruments consist of derivative instruments which are intended to manage commodity price risks (see Note 8) 10. Subsequent Event: ----------------- On January 21, 2000, Carbon commenced an exchange offer for shares of CEC Resources Ltd. (CEC) whereby Carbon offered to exchange one share of Carbon common stock for each share of CEC common stock. The exchange offer was one of the last steps in transactions to combine BFC and CEC. On February 18, 2000, Carbon announced that the Company had completed its offer to exchange Carbon shares for shares of CEC. Of the 1,521,400 outstanding shares of CEC, over 97% of the shares were exchanged. On February 24, 2000 Carbon announced that trading of its shares on the American Stock Exchange (AMEX) had begun under the trading symbol CRB and that the AMEX had commenced proceedings to delist the common stock of CEC (trading symbol CGS). On February 28, 2000, the Securities and Exchange Commission approved the delisting of CEC's common stock from the AMEX. 11. Oil and Gas Activities (Unaudited) ---------------------------------- Costs Incurred in Property Acquisition, Exploration and Development Activities (in thousands) For the Period from Inception (September 14, 1999) through December 31, 1999 ----------------------- Acquisition of properties: Proved properties $ 24,535 Unproved properties 7,879 Exploration 347 Development 84 ----------------------- Total costs incurred $ 32,845 ======================= The Company anticpates that substantially all unevaluated costs will be classified as evaluated costs within five years. 36 Capitalized Costs Related to Oil and Gas Producing Activities (in thousands) December 31, 1999 ----------------- Capitalized costs: Unproved properties not being amortized $ 7,879 Properties being amortized: Productive and nonproductive 24,970 Gas transportation system 50 ----------------- Costs being amortized 25,020 Total capitalized costs 32,899 Less: Accumulated DD&A (617) ----------------- Net capitalized costs $ 32,282 ================= Estimated Oil and Gas Reserve Quantities (Unaudited) The table below sets forth the estimated quantities of year end proved reserves at December 31, 1999. The estimates were prepared by Ryder Scott Company, an independent reservoir engineering firm. Analysis of Changes in Proved Oil and Gas Reserves Oil Natural Gas --------- --------------- (MBbl) (MMcf) Balance, September 14, 1999 - - Revisions to previous estimates 2 250 Purchase of minerals in place 235 31,331 Production (9) (569) ---------- --------------- Balance, December 31, 1999 228 31,012 ========== =============== Proved developed reserves: December 31, 1999 212 26,232 Standardized Measure The Standardized Measure schedule is presented below pursuant to the disclosure requirements of the Securities and Exchange Commission and Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (SFAS No. 69). 37 Carbon Energy Corporation Notes to Consolidated Financial Statements Oil prices of $24.41 per barrel and gas prices of $2.05 per Mcf at December 31, 1999 were used in the estimation of the Company's reserves and future net cash flows. The standardized measure is intended to provide a standard of comparable measurement of the Company's estimated proved oil and gas reserves based on economic and operating conditions existing as of December 31, 1999. Pursuant to SFAS No. 69, future oil and gas revenues are calculated by applying to the proved oil and gas reserves the oil and gas prices at December 31, 1999 relating to such reserves. Future price changes are considered only to the extent provided by contractual arrangement in existence at year-end. Production and development costs are based upon costs at each year-end. Future income taxes are computed by applying statutory tax rates as of the year end with recognition of tax basis, net operating loss carryforwards and other statutory deductions. Discounted amounts are based on a 10% annual discount rate. Changes in the demand for oil and gas, price changes and other factors make such estimates inherently imprecise and subject to revision. Standardized Measure of Discounted Future Net Cash Flows Relating to Estimated Proved Oil and Gas Reserves (thousands of dollars) December 31, 1999 ----------------- Future oil and gas revenue $ 68,542 Future production costs (19,473) Future development costs (5,916) Future income taxes (772) ----------------- Future net cash flows 42,381 Discount at 10% (16,952) ----------------- Standardized measure of discounted future net cash flows $ 25,429 ================= ______________ (1) The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative expenses. For both standardized measure and ceiling test purposes the Company estimates future income taxes using the "short-cut" method. -38- Carbon Energy Corporation Notes to Consolidated Financial Statements Changes in Standardized Measure of Discounted Future Net Cash Flows from Estimated Proved Oil and Gas Reserves (thousands of dollars) For the Period from Inception (September 14, 1999) through December 31, 1999 ---------------------- Standardized measure-inception (September 14, 1999) $ - Sales and transfers of oil and gas produced, net of production costs (1,140) Net changes in prices and production costs (7,248) Purchase of reserves in place 34,136 Revisions of previous quantity estimates 23 Accretion of discount 341 Other (683) ---------------------- Net increase 25,429 ---------------------- Standardized measure-end of year $ 25,429 ====================== -39- Bonneville Fuels Corporation and Subsidiaries Consolidated Financial Statements -40- INDEX TO FINANCIAL STATEMENTS
PAGE ---- Independent Auditor's Report ....................................................... 42 Consolidated Balance Sheets - October 31, 1999 and December 31, 1998 ............... 43 Consolidated Statements of Operations - For the Period From January 1, 1999 through October 31, 1999 and the Years Ended December 31, 1998 and 1997 ....... 44 Consolidated Statement of Stockholder's Equity - For the Period From January 1, 1997 through October 31, 1999 ...................................................... 45 Consolidated Statements of Cash Flows - For the Period From January 1, 1999 through October 31, 1999 and the Years Ended December 31, 1998 and 1997 ....... 46 Notes to Consolidated Financial Statements ......................................... 47
-41- INDEPENDENT AUDITOR'S REPORT Board of Directors Bonneville Fuels Corporation Denver, Colorado We have audited the accompanying consolidated balance sheets of Bonneville Fuels Corporation and subsidiaries as of October 31, 1999 and December 31, 1998 and the related consolidated statements of operations, stockholder's equity, and cash flows for the period from January 1, 1999 through October 31, 1999 and the years ended December 31, 1998 and 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 referred to above present fairly, in all material respects, the financial position of Bonneville Fuels Corporation and subsidiaries as of October 31, 1999 and December 31, 1998, and the results of their operations and their cash flows for the 10-month period ended October 31, 1999 and the years ended December 31, 1998 and 1997, in conformity with generally accepted accounting principles. Hein + Associates LLP March 1, 2000 -42- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
October 31, December 31, ----------------------- -------------------- 1999 1998 ----------------------- -------------------- ASSETS ------ Current assets: Cash $ 249,000 $ 2,742,000 Restricted cash in Rabbi Trust 898,000 - Accounts receivable, trade 2,499,000 4,972,000 Accounts receivable, other 69,000 8,000 Amounts due from broker 1,519,000 534,000 Prepaid expenses and other 131,000 233,000 ------------ ------------ Total current assets 5,365,000 8,489,000 ------------ ------------ Property and equipment, at cost: Oil and gas properties, using the successful efforts method: Unproved properties 3,025,000 2,745,000 Proved properties 34,128,000 29,679,000 Furniture and equipment 499,000 497,000 ------------ ------------ 37,652,000 32,921,000 Less accumulated depreciation, depletion and amortization (21,022,000) (18,891,000) ------------ ------------ Property and equipment, net 16,630,000 14,030,000 ------------ ------------ Other Assets: Deposits and other 240,000 276,000 Rabbi Trust 648,000 - Deferred loan costs, net 29,000 45,000 ------------ ------------ Total other assets 917,000 321,000 ------------ ------------ ------------ ------------ Total assets $ 22,912,000 $ 22,840,000 ============ ============ LIABILITIES AND STOCKHOLDER'S EQUITY ------------------------------------ Current liabilities: Accounts payable and accrued expenses $ 2,490,000 $ 7,116,000 Accrued production taxes payable 284,000 335,000 Undistributed revenue 637,000 476,000 ------------ ------------ Total current liabilities 3,411,000 7,927,000 ------------ ------------ Commitments and contingencies (notes 2, 4, 6 and 8) - - Long-term debt 9,800,000 5,850,000 Stockholder's equity: Common stock, $.01 par value; 1,000 shares authorized, issued, and outstanding - - Additional paid in capital 3,475,000 3,475,000 Retained earnings 6,226,000 5,588,000 ------------ ------------ Total stockholder's equity 9,701,000 9,063,000 ------------ ------------ ------------ ------------ Total liabilities and stockholder's equity $ 22,912,000 $ 22,840,000 ============ ============
See accompanying notes to these consolidated financial statements. -43- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
For the Ten Months Ended For the Years Ended October 31, December 31, ------------------ ---------------------------------------- 1999 1998 1997 ------------------ ------------------- ------------------- Revenues: Oil and gas sales $ 7,820,000 $ 6,758,000 $ 6,429,000 Gas marketing and transportation 9,805,000 12,610,000 9,135,000 Electricity sales 1,782,000 1,331,000 506,000 Other 619,000 393,000 469,000 ------------------ ------------------- ------------------- 20,026,000 21,092,000 16,539,000 ------------------ ------------------- ------------------- Expenses: Oil and gas production costs 2,860,000 3,254,000 2,779,000 Gas marketing and transportation 9,773,000 12,674,000 8,553,000 Cost of electricity 1,729,000 1,137,000 497,000 Depreciation, depletion and amortization expense 2,092,000 2,086,000 1,942,000 Exploration expense 800,000 556,000 772,000 Impairment expense 60,000 1,858,000 312,000 General and administrative expense 1,620,000 1,655,000 590,000 Interest expense 454,000 238,000 83,000 ------------------ ------------------- ------------------- 19,388,000 23,458,000 15,528,000 ------------------ ------------------- ------------------- Income (Loss) Before Taxes 638,000 (2,366,000) 1,011,000 Tax Expense (Benefit): Current - (225,000) 279,000 Deferred - 50,000 - ------------------ ------------------- ------------------- Net Income (Loss) $ 638,000 $ (2,191,000) $ 732,000 ================== =================== ===================
See accompanying notes to these consolidated financial statements. -44- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY For the Period from January 1, 1997 Through October 31, 1999
Common Stock Additional --------------------------- Paid-in Retained Shares Par Value Capital Earnings Total ---------- --------------- ----------- ----------- ------------ Balances, January 1, 1997 1,000 $ - $ 1,812,000 $ 7,047,000 $ 8,859,000 Net income - - - 732,000 732,000 ----------- -------------- ----------- ----------- ----------- Balances, December 31, 1997 1,000 - 1,812,000 7,779,000 9,591,000 Intercompany payables converted to equity by parent - - 1,663,000 - 1,663,000 Net loss - - - (2,191,000) (2,191,000) ----------- -------------- ----------- ----------- ----------- Balances, December 31, 1998 1,000 - 3,475,000 5,588,000 9,063,000 Net income - - - 638,000 638,000 ----------- -------------- ----------- ----------- ----------- Balances, October 31, 1999 1,000 $ - $ 3,475,000 $ 6,226,000 $ 9,701,000 =========== ============== =========== =========== ===========
See accompanying notes to these consolidated financial statements. -45- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Ten Months Ended For the Year Ended October 31, December 31, ----------- ------------------------------- 1999 1998 1997 ----------- ----------- ------------ Cash flows from operating activities: Net Income (loss) $ 638,000 $(2,191,000) $ 732,000 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Deferred taxes - 50,000 - Depreciation, depletion and amortization expense 2,071,000 2,067,000 1,942,000 Impairment of property and equipment 60,000 1,858,000 312,000 Amortization of loan costs 16,000 19,000 19,000 Changes in operating assets and liabilities: Decrease (increase) in: Accounts receivable, trade 2,404,000 (2,154,000) (21,000) Amount due from broker (985,000) (471,000) 152,000 Prepaid expenses and other 110,000 (50,000) (36,000) Rabbi Trust (1,546,000) - - Other assets 36,000 41,000 (26,000) Increase (decrease in): Accounts payable and accrued expenses (4,626,000) 5,646,000 59,000 Accrued production taxes payable (51,000) 78,000 (77,000) Undistributed revenues 161,000 28,000 (194,000) Deferred gain and other liabilities - - 52,000 Taxes payable to parent - (225,000) 279,000 ----------- ----------- ----------- Net cash provided (used) by operating activities (1,712,000) 4,696,000 3,193,000 ----------- ----------- ----------- Cash flows from investing activities: Capital expenditures for oil and gas properties (4,731,000) (5,948,000) (4,442,000) ----------- ----------- ----------- Net cash used in investing activities (4,731,000) (5,948,000) (4,442,000) Cash flows from financing activities: Proceeds from note payable 6,675,000 4,650,000 3,600,000 Payments on note payable (2,725,000) (1,200,000) (2,900,000) Production payment received - - 319,000 ----------- ----------- ----------- Net cash provided by financing activities 3,950,000 3,450,000 1,019,000 ----------- ----------- ----------- Net increase (decrease) in cash and equivalents (2,493,000) 2,198,000 (230,000) Cash, beginning of year 2,742,000 544,000 774,000 ----------- ----------- ----------- Cash, end of year $ 249,000 $ 2,742,000 $ 544,000 =========== =========== =========== Supplemental disclosures of cash flow information: Cash paid for interest $ 453,000 $ 236,000 $ 83,000 =========== =========== =========== Noncash investing and financing activities-intercompany payable contributed to capital by parent $ - $ 1,663,000 - =========== =========== ===========
See accompanying notes to these consolidated financial statements. -46- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Nature of Operations and Significant Accounting Policies: -------------------------------------------------------- Nature of Operation - Bonneville Fuels Corporation (BFC), which was a ------------------- wholly-owned subsidiary of Bonneville Pacific Corporation (BPC), was incorporated in the State of Colorado in April 1987 and began doing business in June 1987. The Company owns four subsidiaries, Bonneville Fuels Marketing Corporation (BFMC), Bonneville Fuels Management Corporation (BFM Corp.), Bonneville Fuels Operating Corporation (BFO), and Colorado Gathering Corporation (CGC). Collectively, these entities are referred to as the Company. The Company's principal operations include exploration for and production of oil and gas reserves, marketing of natural gas, and gathering of natural gas. The Company from time to time also purchases and resells electricity. The Company was acquired by Carbon Energy Corporation (Carbon) on October 29, 1999 for approximately $23,858,000. The accompanying financial statements do not include the purchase price adjustments that will be recorded by Carbon. Principles of Consolidation - The consolidated financial statements include --------------------------- the accounts of BFC and its four wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in the accompanying consolidated financial statements. The Company consolidates its pro rata share of oil and gas ventures in these consolidated financial statements. Cash Equivalents - The Company considers all highly liquid debt instruments ---------------- purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash in Rabbi Trust - Restricted cash in Rabbi Trust represents ------------------------------ payments to be made within the next year to severed employees. Gas Marketing - The Company's marketing contracts are generally month-to- ------------- month or up to eighteen months, and provide that the Company will sell gas to end users which is produced from the Company's properties and acquired from third parties. Amounts Due From Broker- This account generally represents net cash margin ----------------------- deposits held by a brokerage firm for the Company's trading accounts. Oil and Gas Producing Activities - The Company follows the "successful -------------------------------- efforts" method of accounting for its oil and gas properties, all of which are located in the continental United States. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Depreciation and depletion of capitalized costs for producing oil and gas properties is computed using the units-of-production method based upon proved reserves for each field. In 1997, the Company began to accrue for future plugging, abandonment, and remediation using the negative salvage value method whereby costs are expensed through additional depletion expense over the remaining economic lives of the wells. Management's estimate of the total future costs to plug, abandon, and remediate the Company's share of all existing wells, including those currently shut in is approximately $3,500,000 net -47- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS of salvage values. The total cumulative amount accrued as additional depletion for plugging and abandonment is $612,000 at October 31, 1999. The Company follows Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for Impairment of Long-Lived Assets". This statement limits net capitalized costs of proved oil and gas properties to the aggregate undiscounted future net revenues related to each field. If the net capitalized costs exceed the limitation, impairment is provided to reduce the carrying value of the properties in the field to estimated actual value. The impairment is included as a reduction of gross oil and gas properties in the accompanying balance sheet. For the 10 months ended October 31, 1999 and the years ended December 31, 1998 and 1997 the Company recorded impairments of $60,000, $1,858,000 and $312,000, respectively. Factors causing the impairment of oil and gas properties were the decline in oil prices worldwide and the re-assessment of reserve valves on certain producing properties in 1998 and re-assessment of reserves values on a drilling venture in 1999. The primary factor causing the impairments in 1997 was the reevaluation of certain undeveloped leases. Gains and losses are generally recognized upon the sale of interests in proved oil and gas properties based on the portion of the property sold. For sales of partial interests in unproved properties, the Company treats the proceeds as a recovery of costs with no gain recognized until all costs have been recovered. Revenue Recognition - The Company recognizes revenue for oil and gas ------------------- production upon delivery of the commodity to the purchaser. The Company records sales and related cost of sales on gas and electricity marketing transactions using the accrual method of accounting (i.e., the transaction is recorded when the commodity is purchased and/or delivered). Undistributed Revenue - Represents amounts due to other owners of jointly --------------------- owned oil and gas properties for their revenue from the properties. Energy Marketing Arrangements - In 1998, BFC entered into an agreement to ----------------------------- manage certain natural gas contracts of an unrelated entity. This agreement was terminated on April 30, 1999. For some contracts, BFC takes title to the gas purchased to service these contracts prior to the sale under the contracts. For these contracts, BFC records all revenue, expenses, receivables and payables associated with the contracts. In contracts where title is not taken, BFC records only the margin associated with the transaction. Other Property and Equipment - Depreciation of other property and equipment ---------------------------- is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 25 years) of the respective assets. The cost of normal maintenance and repairs is charged to operating expenses as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts, and any gains or losses are reflected in current operations. Deferred Loan Costs - Costs associated with the Company's note payable have ------------------- been deferred and are being amortized using the effective interest method over the original term of the note. Gas Balancing - The Company uses the sales method of accounting for amounts ------------- received from natural gas sales resulting from production credited to the Company in excess of its revenue interest share. Under this method, all proceeds from production credited to the Company are recorded as revenue until such time as the -48- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Company has produced its share of related estimated remaining reserves. Thereafter, additional amounts received are recorded as a liability. Income Taxes - The Company accounts for income taxes under the liability ------------ method which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. BPC includes the Company's operations in its consolidated tax return. Income taxes are allocated by BPC as if the Company were a separate taxpayer. Accounting for Hedged Transactions - The Company periodically enters into ---------------------------------- futures, forwards, and swap contracts as hedges of commodity prices associated with the production of oil and gas and with the purchase and sale of natural gas in order to mitigate the risk of market price fluctuations. Changes in the market value of futures, forwards, and swap contracts are not recognized until the related production occurs or until the related gas purchase or sale takes place. Realized losses from any positions which were closed early are deferred and recorded as an asset or liability in the accompanying balance sheet, until the related production, purchase or sale takes place. Gains and losses incurred on these contracts are included in oil and gas revenue or in gas marketing costs in the accompanying statements of operations. Accounting Estimates - The preparation of financial statements in conformity -------------------- with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these financial statements and the accompanying notes. The actual results could differ from those estimates. Impact of Recently Issued Accounting Pronouncements (Unaudited) - In June --------------------------------------------------------------- 1998, the Financial Accounting Standards Board issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This pronouncement is effective for fiscal quarters of fiscal years beginning after June 15, 2000. SFAS No. 133 requires companies to report all derivatives at fair value as either assets or liabilities and bases the accounting treatment of the derivatives on the reasons an entity holds the instrument. The Company is currently reviewing the effects SFAS No. 133 will have on the financial statements in relation to the Company's hedging activities. -49- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. Parent Company Bankruptcy and Related Transactions: -------------------------------------------------- In 1991, BPC filed a petition for re-organization under Chapter 11 of the U.S. Bankruptcy Code. In 1998, BFC emerged from bankruptcy. In 1998, BPC approved the conversion of $1,633,000 in taxes payable to equity. There are no significant expenses incurred by Bonneville Pacific Corporation on behalf of Bonneville Fuels Corporation, nor by Bonneville Fuels Corporation on behalf of Bonneville Pacific Corporation. 3. Long-term Debt: -------------- The Company has an asset-based line-of-credit with a bank which provides for borrowing up to the borrowing base (as defined). The borrowing base was $16,900,000 at October 31, 1999. At October 31, 1999, outstanding borrowings amounted to $9,800,000. The Company has issued letters of credit totaling $2,167,000, which further reduces the amount available for borrowing under the base. This facility is collateralized by certain oil and gas properties of the Company and is scheduled to convert to a term note on July 1, 2001. This term loan is scheduled to have a maturity of either the economic half life of the Company's remaining reserves on the date of conversion, or July 1, 2006, whichever is earlier. The facility bears interest at prime (8.5% at October 31, 1999). The borrowing base is based upon the lender's evaluation of BFC's proved oil and gas reserves, generally determined semi-annually. The future minimum principal payments under the term note will be dependent upon the bank's evaluation of the Company's reserves at that time. The Company also has an accounts receivable-based credit facility which includes a revolving line-of-credit with the bank which provides for borrowings and letters of credit up to $1,500,000. There were no outstanding borrowings under this facility at October 31, 1999, however, there was a letter of credit issued in the amount of $40,000, which reduces the amount available under this line. This facility bears interest at prime (8.5% at October 31, 1999). This facility is collateralized by certain trade receivables of BFC and has a maturity date of July 1, 2001. The credit agreement contains various covenants which prohibit or limit the Company's ability to pay dividends, purchase treasury shares, incur indebtedness, repay debt to the Parent, sell properties or merge with another entity. The Company is also required to maintain certain financial ratios. The bank waived the non-merger covenants in connection with the acquisition by Carbon. 4. Salary Continuation Plan: ------------------------ In 1999, the Company established a Salary Continuation Plan (the "Plan"). The Plan provides for continuation of salary and health, dental disability, and life insurance benefits for a certain period of time based on employment contracts or length of service, if the employee is terminated within 2 years following the effective date of the Company's acquisition by Carbon. The maximum amount which could be disbursed under the Plan is $1,546,000. The employees will be required to pay any increased premiums for the insurance benefits and the Plan insurance commitment is capped at the above amount. -50- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Terminations as of October 31, 1999 will require payment out of the Rabbi Trust in the amount of $438,000. Cost associated with these terminations has been expensed in the current period, and accrued for as of October 31, 1999. No additional terminations are expected as of October 31, 1999. Subsequent to October 31, 1999, contracts with various employees has resulted in the actual payment or agreement to pay an additional $460,000 from the trust within the next 12 months. These payments will be expensed subsequent to October 31, 1999. The Company has deposited the maximum amount noted above in a Rabbi Trust cash account. This Trust is restricted from disbursing funds except for the payment of benefits or upon the insolvency of the Company. The amounts to be paid in 2000 are recorded as a current asset. All remaining amounts are recorded as a long-term asset. The trustee fees were not material for the period ending October 31, 1999. 5. Exploration Expense: ------------------- Exploration expense consists of the following:
For the Ten Months Ended For the Year Ended October 31, December 31, ------------------- ----------------- ------------------ 1999 1998 1997 ------------------- ----------------- ------------------ Annual rental payments on unproved properties $ 20,000 $ 82,000 $ 84,000 Geological and geophysical cost 476,000 390,000 89,000 Dry hold costs and abandonments 304,000 84,000 599,000 ------------------- ----------------- ------------------ $ 800,000 $ 556,000 $ 772,000 =================== ================= ==================
6. Commitments: ----------- Office Lease - The Company leases office space under a noncancellable ------------ operating lease. Total rental expense was approximately $123,000, $139,000 and $58,000 for the 10 months ended October 31, 1999 and for the years ended December 31, 1998 and 1997, respectively. The Company has a lease agreement which provides for total minimum rental commitments of: Remaining 1999 $ 24,000 2000 152,000 2001 158,000 2002 164,000 2003 28,000 ------------ $ 526,000 ============ -51- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Well Connection Reimbursement - The Company entered into a contract with an ----------------------------- unrelated party in 1997 to connect certain wells to sales pipelines. The Company is obligated to reimburse the unrelated party for the difference between the gathering fees generated by these wells and the cost of connection. The accompanying financial statements contain an accrual of $250,000, representing management's current estimate of the potential liability under this agreement. 7. Income Taxes: ------------ The components of the net deferred tax assets are as follows:
As of As of October 31, December 31, --------------- ---------------- 1999 1998 --------------- ---------------- Excess of tax basis over book basis of oil and gas properties $ 3,153,000 $ 1,873,000 Deferred tax assets 3,153,000 1,873,000 Less valuation allowance (3,153,000) (1,873,000) ----------- ----------- Net deferred tax assets $ - $ - =========== ===========
The effective tax rate of the Company differed from the Federal statutory rate primarily due to changes in the valuation allowance on the deferred tax assets. 8. Concentrations of Credit Risk and Price Risk Management: ------------------------------------------------------- Concentrations of Credit Risk - Substantially all of the Company's accounts ----------------------------- receivable at October 31, 1999 result from crude oil and natural gas sales and/or joint interest billings to companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, since these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on trade receivables by the Company have been insignificant. The Company's revenues are predominantly derived from the sale of natural gas and management estimates that over 85% of the value of the Company's properties is derived from natural gas reserves. Energy Financial Instruments - BFC uses energy financial instruments and ---------------------------- long-term user contracts to minimize its risk of price changes in the spot and fixed price natural gas and crude oil markets. Energy risk management products used include commodity futures and options contracts, fixed-price swaps, and basis swaps. Pursuant to company guidelines BFC is to engage in these activities only as a hedging mechanism against price volatility associated with pre-existing or anticipated gas or crude oil sales in order to protect profit margins. As of October 31, 1999, BFC has financial contracts which hedge a total of 4.1 Bcf (billion cubic feet) of production through December 31, 2001. -52- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The difference between the current market value of the hedging contracts and the original market value of the hedging contracts was an unfavorable $1,733,000 as of October 31, 1999. These amounts are not reflected in the accompanying financial statements. In the event energy financial instruments do not qualify for hedge accounting, the difference between the current market value and the original contract value would be currently recognized in the statement of operations. In the event that the energy financial instruments are terminated prior to the delivery of the item being hedged, the gains and losses at the time of the termination are deferred until the period of physical delivery. Such deferrals were immaterial at October 31, 1999. 9. Financial Instruments: --------------------- SFAS Nos. 107 and 127 requires certain entities to disclose the fair value of certain financial instruments in their financial statements. Accordingly, management's best estimate is that the carrying amount of cash, receivables, notes payable, accounts payable, undistributed revenue, and accrued expenses approximates fair value of these instruments. See Note 8 for a discussion regarding the fair value of energy financial instruments. -53- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. Unaudited Supplemental Oil and Gas Reserve Information: ------------------------------------------------------ Estimated Reserve Oil and Gas Quantities The table below sets forth the estimated quantities of year end proved reserves at October 31, 1999 and December 31, 1998 and 1997. The estimates were prepared by Ryder Scott Company, and independent reservoir engineering firm. Proved Oil and Gas Reserves Oil Natural Gas ------- -------- (MBbl) (MMcf) December 31, 1996 227 26,512 Revisions to previous estimates 3 (1,569) Extensions and discoveries 32 427 Purchase of minerals in place 99 916 Production (63) (3,146) ------- ------- December 31, 1997 298 23,140 Revisions to previous estimates (101) 976 Extensions and discoveries 34 5,011 Purchase of minerals in place 0 0 Production (65) (3,272) ------- ------- December 31, 1998 166 25,855 Revisions to previous estimates 46 2,044 Extensions and discoveries 78 6,937 Purchase of minerals in place 0 0 Production (55) (3,505) ------- ------- October 31, 1999 235 31,331 Proved developed reserves: December 31, 1997 298 22,623 December 31, 1998 166 25,855 October 31, 1999 221 26,801 -54- BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Standardized Measure The Standardized Measure schedule is presented below pursuant to the disclosure requirements of the Securities and Exchange Commission and Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (SFAS 69). Future cash flows are calculated using year-end oil and gas prices and operating expenses, and are discounted using a 10% discount factor. Oil and gas prices at October 31, 1999 and December 31, 1998 and 1997 of $19.68 $10.69 and $16.91 respectively, per barrel of oil and $2.50, $1.84 and $1.81 respectively, per Mcf of gas were used in the estimation of Carbon's reserves and future net cash flows. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expense has not been provided based on the availability of net operating loss carry forwards and other deductions available to the parent of the Company. The standardized measure is intended to provide a standard of comparable measurement of Carbon's estimated proved oil and gas reserves based on economic and operating conditions existing as of October 31, 1999, and December 31, 1998 and 1997. Pursuant to SFAS 69, future oil and gas revenues are calculated by applying to the proved oil and gas reserves the oil and gas prices at the end of each reporting period relating to such reserves. Future price changes are considered only to the extent provided by contractual arrangement in existence at the report date. Production and development costs are based upon costs at the report date. Discounted amounts are based on a 10% annual discount rate. Changes in the demand for oil and gas, price changes and other factors make such estimates inherently imprecise and subject to revision. Standardized Measure of Discounted Future Net Cash Flows Relating to Estimated Proved Oil and Gas Reserves (thousands of dollars)
October 31, December 31, December 31, 1999 1998 1997 ----------------- ----------------- ----------------- Future oil and gas revenue $82,818 $49,428 $46,859 Future production and development costs (26,490) (18,507) (18,155) ----------------- ----------------- ----------------- Future net cash flows 56,328 30,921 28,704 Discount @ 10% (22,192) (10,426) (9,075) ----------------- ----------------- ----------------- Standardized measure of discounted future net cash flows $34,136 $20,495 $19,629 ================= ================= =================
-55- Change in Standardized Measure of Discounted Future Net Cash Flows from Estimated Proved Oil and Gas Reserves (thousands of dollars)
October 31, December 31, December 31, 1999 1998 1997 ---------------------- ----------------- ------------------ Standardized measure-beginning of period $20,495 $19,629 $40,011 Sales and transfers of oil and gas produced, net of production costs (4,960) (3,754) (3,650) Net changes in prices and production costs 10,834 (999) (20,485) Extensions, discoveries and other additions 4,576 4,699 756 Purchase of reserves in place 0 147 1,610 Revisions of future development costs (310) 87 1,069 Revisions of previous quantity estimates 2,818 279 (1,098) Accretion of discount 1,708 1,963 4,001 Other (1,025) (1,556) (2,585) ---------------------- ----------------- ------------------ Net increase (decrease) 13,641 866 (20,382) ---------------------- ----------------- ------------------ Standardized measure-end of period $34,136 $20,495 $19,629 ====================== ================= ==================
Costs Incurred in Property Acquisition, Exploration and Development Activities (in thousands)
Ten months ended Year ended Year ended October 31, December 31, December 31, 1999 1998 1997 ----------------------- ----------------- ----------------- Acquisition of properties: Proved properties - $ 95 $ 2,230 Unproved properties 248 473 - Exploration 3,088 1,932 599 Development 1,371 3,784 1,812 ----------------------- ----------------- ----------------- Total costs incurred $ 4,707 $ 6,284 $ 4,641 ======================= ================= =================
-56- Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
October 31, December 31, 1999 1998 ----------------- ----------------- Capitalized costs: Unproven properties not being amortized $ 3,025 $ 2,745 Properties being amortized: Productive and nonproductive 33,970 29,521 Gas transportation system 158 158 ----------------- ----------------- Costs being amortized 34,128 29,679 Total capitalized costs 37,153 32,424 Less: Accumulated DD&A (21,022) (18,891) ----------------- ----------------- Net capitalized costs $ $ 16,131 $ 13,533 ================= =================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. -57- 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 Relationships and Related Transactions. For Part III, the information set forth in the Company's definitive Proxy Statement for the Company's 2000 Annual Meeting of Shareholders, to be filed, is incorporated by reference into this Report. -58- PART IV ------- ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) (1) Financial Statements: See indexes to Financial Statements of Carbon and BFC in Item 8. Schedules are omitted because of the absence of the conditions under which they are required or because the information is included in the financial statements or notes to the financial statements. (b) Reports on Form 8-K: The following report was filed by the Company on Form 8-K during the quarter ended December 31, 1999: None. (c) Exhibits:
Exhibit Number Description of Exhibit - - - ------------ ---------------------------------------------------------------------------------------------- 3.1 Articles of Incorporation of Carbon Energy Corporation, incorporated by reference to Exhibit 2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 3.2 Bylaws of Carbon Energy Corporation, incorporated by reference to Exhibit 3 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.1 1999 Stock Option Plan, incorporated by reference to Exhibit 10.1 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.2 1999 Restricted Stock Plan, incorporated by reference to Exhibit 10.2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.3 Exchange and Financing Agreement dated October 14, 1999 among Carbon Energy Corporation, CEC Resources Ltd. and Yorktown Energy Partners III, L.P., incorporated by reference to Exhibit 10.3 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.4 Stock Purchase Agreement dated August 11, 1999 between Bonneville Pacific Corporation and CEC Resources Ltd., incorporated by reference to Exhibit 10.4 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.5 Form of Indemnification Agreement between Carbon Energy Corporation and its officers and directors, incorporated by reference to Exhibit 10.5 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.6 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation and Patrick R. McDonald, incorporated by reference to Exhibit 10.6 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.7 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation and Kevin D. Struzeski, incorporated by reference to Exhibit 10.7 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
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10.8 Amended and Restated Credit Agreement dated as of May 31, 1994 among Bonneville Fuels Corporation, Bonneville Fuels Marketing Corporation, Colorado Gathering Corporation, Bonneville Fuels Operating Corporation and Bonneville Fuels Management Corporation ("Borrowers") and First Interstate Bank of Denver, N.A. ("Lender"); Revolving Note for $20,000,000 dated May 31, 1994 from Borrowers to Lender; Promissory Note for $1,000,000 from Borrowers to Lender dated May 31, 1994; Term Note for $20,000,000 from Borrowers to Lender dated May 31, 1994; as amended by Note Modification Agreement dated April 1, 1995, among Borrowers and Lender; Amendment to Credit Agreement dated as of April 1, 1995 among Borrowers and Lender; Note Modification Agreement dated May 1, 1996 among Borrowers and Lender; Second Amendment to Credit Agreement dated as of April 1, 1996 among Borrowers and Lender; Loan Transfer Agreement dated as of September 18, 1996 among Borrowers, Wells Fargo Bank (Colorado), N.A. formerly known as First Interstate Bank of Denver, N.A., and Colorado National Bank ("CNB"); Third Amendment of Amended and Restated Credit Agreement dated as of September 18, 1996 among Borrowers and CNB; Fourth Amendment of Amended and Restated Credit Agreement dated as of May 15, 1998 among Borrowers and CNB; and Fifth Amendment of Amended and Restated Credit Agreement dated as of June 1, 1999 among Borrowers and CNB, all incorporated by reference to Exhibit 10.8 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 24 Power of Attorney. 27 Financial Data Schedule.
-60- 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. Date: March 30, 2000. CARBON ENERGY CORPORATION By: /s/ Patrick R. McDonald ------------------------------------ Patrick R. McDonald, President By: /s/ Kevin D. Struzeski ------------------------------------ Kevin D. Struzeski, Treasurer and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons of the Registrant and in the capacities and on the dates indicated:
Date Name and Title Signature - - - ---- -------------- --------- March 30, 2000 Cortlandt S. Dietler, ) Director ) ) /s/ Patrick R. McDonald ) ------------------------------------------ March 30, 2000 David H. Kennedy, ) Patrick R. McDonald, for himself and Director ) as Attorney-in-Fact for the named ) directors who together constitute all March 30, 2000 Bryan H. Lawrence, ) of the members of Registrant's Board Director ) of Directors ) March 30, 2000 Peter A. Leidel, ) Director ) ) March 30, 2000 Patrick R. McDonald, ) Director ) ) March 30, 2000 Harry A. Trueblood, Jr., ) Director ) ) ) ) )
-61- Exhibit Index
Exhibit Number Description of Exhibit - - - ------ ---------------------- 3.1 Articles of Incorporation of Carbon Energy Corporation, incorporated by reference to Exhibit 2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 3.2 Bylaws of Carbon Energy Corporation, incorporated by reference to Exhibit 3 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.1 1999 Stock Option Plan, incorporated by reference to Exhibit 10.1 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.2 1999 Restricted Stock Plan, incorporated by reference to Exhibit 10.2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.3 Exchange and Financing Agreement dated October 14, 1999 among Carbon Energy Corporation, CEC Resources Ltd. and Yorktown Energy Partners III, L.P., incorporated by reference to Exhibit 10.3 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.4 Stock Purchase Agreement dated August 11, 1999 between Bonneville Pacific Corporation and CEC Resources Ltd., incorporated by reference to Exhibit 10.4 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.5 Form of Indemnification Agreement between Carbon Energy Corporation and its officers and directors, incorporated by reference to Exhibit 10.5 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.6 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation and Patrick R. McDonald, incorporated by reference to Exhibit 10.6 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.7 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation and Kevin D. Struzeski, incorporated by reference to Exhibit 10.7 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 10.8 Amended and Restated Credit Agreement dated as of May 31, 1994 among Bonneville Fuels Corporation, Bonneville Fuels Marketing Corporation, Colorado Gathering Corporation, Bonneville Fuels Operating Corporation and Bonneville Fuels Management Corporation ("Borrowers") and First Interstate Bank of Denver, N.A. ("Lender"); Revolving Note for $20,000,000 dated May 31, 1994 from Borrowers to Lender; Promissory Note for $1,000,000 from Borrowers to Lender dated May 31, 1994; Term Note for $20,000,000 from Borrowers to Lender dated May 31, 1994; as amended by Note Modification Agreement dated April 1, 1995, among Borrowers and Lender; Amendment to Credit Agreement dated as of April 1, 1995 among Borrowers and Lender; Note Modification Agreement dated May 1, 1996 among Borrowers and Lender; Second Amendment to Credit Agreement dated as of April 1, 1996 among Borrowers and Lender; Loan Transfer Agreement dated as of September 18, 1996 among Borrowers, Wells Fargo Bank (Colorado), N.A. formerly known as First Interstate Bank of Denver, N.A., and Colorado National Bank ("CNB"); Third Amendment of Amended and Restated Credit Agreement dated as of September 18, 1996 among Borrowers and CNB; Fourth Amendment of Amended and Restated Credit Agreement dated as of May 15, 1998 among Borrowers and CNB; and Fifth Amendment of Amended and Restated Credit Agreement dated
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as of June 1, 1999 among Borrowers and CNB, all incorporated by reference to Exhibit 10.8 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000. 24 Power of Attorney. 27 Financial Data Schedule.
-63- EX-24 2 POWER OF ATTORNEY EXHIBIT 24 POWER OF ATTORNEY Each of the undersigned directors and/or officers of Carbon Energy Corporation (the "Company") hereby authorizes Patrick R. McDonald and Kevin D. Struzeski, and each of them, as their true and lawful attorneys-in-fact and agents (1) to sign in the name of the undersigned and file with the Securities and Exchange Commission the Company's annual report on Form 10-K, for the fiscal year ended December 31, 1999, and any amendments to such annual report; and (2) to take any and all actions necessary or required in connection with such annual report to comply with the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Securities and Exchange Commission promulgated thereunder.
Signature Title Date - - - --------- ----- ---- /s/ Patrick R. McDonald Director and President ______________ - - - --------------------------------------- Patrick R. McDonald /s/ Kevin D. Struzeski Treasurer and Chief Financial ______________ - - - --------------------------------------- Officer Kevin D. Struzeski /s/ Cortlandt S. Dietler Director ______________ - - - --------------------------------------- Cortlandt S. Dietler /s/ David H. Kennedy Director ______________ - - - --------------------------------------- David H. Kennedy /s/ Bryan H. Lawrence Director ______________ - - - --------------------------------------- Bryan H. Lawrence /s/ Peter A. Leidel Director March 27, 2000 - - - --------------------------------------- Peter A. Leidel /s/ Harry A. Trueblood, Jr. Director March 27, 2000 - - - --------------------------------------- Harry A. Trueblood, Jr.
EX-27 3 FINANCIAL DATA SCHEDULE
5 OTHER DEC-31-1999 SEP-14-1999 DEC-31-1999 995,000 0 2,355,000 0 0 5,588,000 33,113,000 (627,000) 39,298,000 5,356,000 0 0 0 24,806,000 0 39,298,000 2,769,000 34,000 1,625,000 3,192,000 0 0 102,000 (491,000) 0 0 0 0 0 (491,000) (.12) (.12)
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