10-K405 1 0001.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Act of 1934 For the fiscal year ended December 31, 2000 or [_] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________ to ______________ Commission file Number: 0-15905 BLUE DOLPHIN ENERGY COMPANY (Exact name of registrant as specified in its charter) DELAWARE 73-1268729 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 801 Travis, Suite 2100, Houston, Texas 77002 (Address of principal executive office) (Zip Code) Registrant's telephone number, including area code: (713) 227-7660 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: common stock, $.01 par value (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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 (estimated solely for purposes of this calculation) of the voting stock held by non-affiliates of the registrant as of March 26, 2001, was approximately $14,514,718. As of March 26, 2001, there were outstanding 6,016,718 shares of common stock, par value $.01 per share, of the registrant. DOCUMENTS INCORPORATED BY REFERENCE None PART I ITEM 1. BUSINESS FORWARD LOOKING STATEMENTS. Certain of the statements included below, including those regarding future financial performance or results or that are not historical facts, are "forward-looking" statements as that term is defined in the Section 21E of the Securities Exchange Act of 1934, as amended. The words "expect," "plan," "believe," "anticipate," "project," "estimate," and similar expressions are intended to identify forward-looking statements. Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as "Blue Dolphin" or the "Company") cautions readers that any such statements are not guarantees of future performance or events and such statements involve risks and uncertainties that may cause actual results and outcomes to differ materially from those indicated in forward-looking statements. Some of the important factors that could cause actual results to vary from forward-looking statements are discussed in our Registration Statement on Form S-3 filed with the Securities and Exchange Commission on January 11, 2001 under the caption "Risk Factors." The Risk Factors section of this Registration Statement is incorporated by reference into this report. Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date hereof. The Company undertakes no duty to update these forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by the Company which attempt to advise interested parties of the additional factors which may affect the Company's business, including the disclosures made under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. THE COMPANY The Company conducts its business activities in two primary business segments: (i) oil and gas exploration and production, which includes our developmental-stage upstream projects, and (ii) pipeline operations, which includes our developmental-stage mid-stream projects. The Company's oil and gas exploration and production activities include the exploration, acquisition, development, operation and, when appropriate, disposition of oil and gas properties. The Company focuses its oil and gas acquisitions and exploration activities in the western and central Gulf of Mexico. The Company is a holding company that conducts substantially all of its operations through its subsidiaries. Substantially all of the Company's assets consist of equity in its subsidiaries. The Company's subsidiaries are as follows: . Blue Dolphin Exploration Company, a Delaware corporation, o American Resources, a majority-owned subsidiary of Blue Dolphin Exploration; . Blue Dolphin Pipe Line Company, a Delaware corporation; . Blue Dolphin Services Co., a Texas corporation; . Black Marlin Energy Company, a Delaware corporation; . Buccaneer Pipe Line Co., a Texas corporation; 2 . Mission Energy, Inc., a Delaware corporation; . New Avoca Gas Storage, LLC, a Texas limited liability company in which the Company owns a 25% interest; . Petroport, Inc., a Delaware corporation; and . Drillmar, Inc., a Delaware corporation in which the Company owns a 37.5% interest. o Zephyr Drilling Ltd., a Texas limited partnership in which Drillmar, Inc. owns a 1% interest and is the general partner. The principal executive office of the Company is located at 801 Travis, Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. American Resources maintains an office in New Orleans, Louisiana. Shore based facilities are maintained in Freeport, Texas serving Gulf of Mexico operations. The Company has 20 full-time employees. The Company's common stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") Small Cap Market under the trading symbol "BDCO". The Company's home page address on the world wide web is http://www.blue-dolphin.com. OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES The Company's oil and gas assets are held, and operations conducted, by Blue Dolphin Exploration and American Resources. American Resources is a public entity subject to the reporting requirements of the Securities Exchange Act of 1934, whose common stock is traded on the OTC Bulletin Board under the trading symbol "GASS.OB". The Company's oil and gas assets consist of leasehold interests in properties located offshore in the Gulf of Mexico. The leasehold properties held by the Company are subject to royalty, overriding royalty and interests of others. In the future, the Company's properties may become subject to burdens and encumbrances typical to oil and gas operators, such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances. Certain terms that are commonly used in the oil and gas industry, including terms that define our rights and obligations with respect to each of the Company's properties, are defined in the "Glossary of Certain Oil and Gas Terms" on pages 23, 24 and 25 of this Form 10-K. The following is a description of the Company's major oil and gas exploration and production assets and activities: AMERICAN RESOURCES. On December 2, 1999, Blue Dolphin Exploration acquired a 75% ownership interest in American Resources by purchasing approximately 39.5 million shares of American Resources' common stock. As of December 31, 2000, Blue Dolphin Exploration owned a 77% ownership in American Resources. Concurrently with the sale to Blue Dolphin Exploration, American Resources sold an 80% interest in its oil and gas assets located in the Gulf of Mexico to Fidelity Oil Holdings, Inc. a subsidiary of MDU Resources Group, Inc. The oil and gas properties held by American Resources represent 74% of the discounted present value of estimated future net revenues from proved reserves of the Company as of December 31, 2000. 3 Sales of production from the these properties accounted for 95% of oil and gas sales revenues and 66% of total revenues of the Company for the year ended December 31, 2000. The following table provides proved reserve information for American Resources' oil and gas properties as of December 31, 2000: PROVED RESERVE INFORMATION FROM AMERICAN RESOURCES OFFSHORE, INC. Gas Oil Gas Equivalent (Bbl) (MMcf) (MMcfe) ------ ------ ---------- South Timbalier 148............... 57,064 1,231 1,573 West Cameron 172.................. 1,782 575 586 South Timbalier 211............... 2,413 476 490 Galveston 418..................... 0 446 446 Ship Shoal 150.................... 119,097 185 900 Other............................. 1,817 516 527 ------- ----- ----- Total net proved reserves 182,173 3,429 4,522 ======= ===== ===== SIGNIFICANT FIELDS. As of December 31, 2000, all of American Resources oil and gas properties were located in the outer continental shelf of the Gulf of Mexico and consisted of interests in 32 leases. American Resources' working interest in these leases ranges from 10% to 1%, with an average working interest of approximately 5.5%. Of these leases, 17 are offshore Louisiana and 15 are offshore Texas. Twelve of the leases are currently producing, and 20 are held for future development. Those leases that are not producing are in their primary term. The expiration of the primary terms of the undeveloped leases occurs as follows: 15 in 2001, 4 in 2002, and 1 in 2003. SOUTH TIMBALIER 148. South Timbalier Block 148 is located 30 miles offshore Louisiana in an average water depth of 100 feet and is operated by Newfield Exploration Company. American Resources owns a working interest in the lease on the west half of the block that covers approximately 2,500 acres and working interests in seven producing wells on three production platforms. American Resources' working interest in the wells ranges from 9% to 1%. WEST CAMERON 172. West Cameron Block 172 is located 25 miles offshore Louisiana in an average water depth of 40 feet. American Resources owns a 5.4% working interest that covers approximately 5,000 acres and working interests in four producing wells on this lease, which are operated by Pure Resources, Inc. ("Pure"). SOUTH TIMBALIER 211. South Timbalier Block 211 is located 42 miles offshore Louisiana in an average water depth of 140 feet. American Resources owns a 6.0% working interest in this lease that covers approximately 5,000 acres and working interests in two producing wells on the lease, which are operated by Pure. American Resources owns an overriding royalty interest in one well on the lease that was drilled under a farmout by Spinnaker Exploration Company, LLC, during 1999 and commenced production in the first quarter of 2000. 4 GALVESTON 418. Galveston Block 418 is located 16 miles offshore Texas in an average water depth of 95 feet. The field, operated by The William G. Helis Company, was a discovery in late 2000. American Resources owns a 6% working interest in one well, which has been drilled on this discovery. American Resources expects that production will commence early in the second quarter of 2001, with the well being tied into a facility on Galveston Block 395 which we own a similar working interest in. SHIP SHOAL 150. Ship Shoal Block 150 is located 31 miles offshore Louisiana in an average water depth of 53 feet. American Resources owns a 10% working interest in 4,297 acres in the block, and working interests in two producing wells on the lease operated by Century Exploration Company. American Resources owns an overriding royalty interest in one producing well on the lease. OTHER. Other leases that contain proved reserves are West Cameron Block 368, offshore Louisiana, accounting for 293 Mmcfe; High Island 37, offshore Texas, accounting for 189 Mmcfe; and Galveston 394/395, offshore Texas, accounting for 45 Mmcfe. American Resources sells all of its current oil and gas production through the operators of its properties. The price American Resources is currently receiving is based on current market prices. Previously, forward sales contracts were utilized for a significant portion of its gas production to achieve more predictable cash flow and to reduce the effect of fluctuations in gas prices. THE BUCCANEER FIELD. In November 2000, the Company decided to abandon the Buccaneer Field as a result of the occurrence of unforeseen adverse events. In July 2000, production from the only producing well in the Buccaneer Field, the A-12 well, ceased due to down-hole mechanical problems. Due to the age of the wellbore of this well, it is probable that a new well would be needed to restore production at the Buccaneer Field, at an estimated cost of $2.8 million. In addition, in October 2000, during the annual inspection by the U.S. Minerals Management Service ("MMS") of the two major platform complexes in the Buccaneer Field, the MMS notified the Company that certain repairs to the platforms would be required before the Company could resume operating activities. The Company estimated the cost of these required, unplanned repairs to be in excess of $1.0 million. However, the Company believes that if it elected to resume production from the Buccaneer Field the actual costs would have been approximately $2.6 million, including an estimated $.6 million to repair one of the platform complexes. Thus, the total cost to reestablish production would have increased to an estimated $5.4 million, consisting of $2.6 million in front-end infrastructure costs and $2.8 million in drilling costs. After considering the costs associated with drilling a new well to reestablish production, together with the unplanned cost of repairs to the platforms and the projected rate of production and discounted cash flow from the field, the Company decided to abandon and not reestablish production from the Buccaneer Field. As a result of our decision, our leases on this field terminated in January 2001 pursuant to their terms. The Company owned a 100% working interest in the Buccaneer Field (81.33% net revenue interest). Production from the Buccaneer Field accounted for 5%, 48% and 100% of the total revenues from oil and gas sales of the Company for the years ended December 31, 2000, 1999 and 1998, respectively. See "Proved Oil and Gas Reserves" below. 5 The MMS requires that security be provided for the estimated abandonment obligations associated with the Buccaneer Field. Blue Dolphin Exploration provided the MMS surety bonds in the amount of $1.3 million. Additionally, Blue Dolphin Exploration was required to make a $250,000 annual payment to a sinking fund to cover its end of lease abandonment and site clearance obligations. Blue Dolphin Exploration was required to make payments to the sinking fund until the balance of the sinking fund was $2.4 million, unless changed by the MMS. In October 2000, the MMS notified the Company that they required additional security to ensure that the Company's abandonment obligations associated with the Buccaneer Field will be met. At the request of the MMS, the Company delivered an additional $2.9 million in surety bonds and used the escrowed funds as collateral for the surety bonds. As of December 31, 2000, the escrowed funds totaled approximately $1.5 million. During the first quarter of 2001, the Company plugged and abandoned the remaining 10 wells in Buccaneer Field at a cost of approximately $1.1 million, and expects to fund these costs by utilizing its escrowed funds. The remaining $.4 million in the escrowed funds will be used to partially fund the removal of the platform facilities expected to be removed in late 2001 at an estimated cost of $4.3 million. In addition to conducting traditional oil and gas production operations for itself, the Company operated and maintained oil and gas production facilities for third party producers who utilized the Blue Dolphin Pipeline System for gathering and transportation of their production. The Company had a contract with Apache Corporation to provide operation and maintenance services that terminated in December 2000 as a result of the decision to abandon the Buccaneer Field. During 2000, approximately 3% of the Company's revenues were attributable to its contract with Apache Corporation. Total revenues attributable to the now abandoned Buccaneer Field for production and the Apache contract amounted to approximately 7% of the Company's total revenues in 2000. OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, Blue Dolphin Exploration initiated a program to develop oil and gas exploration prospects in the Gulf of Mexico for sale to third parties. The Company utilizes seismic and other data to evaluate and develop prospects. The Company owns a non-exclusive license to 200 blocks of 3-D seismic data covering 1,152,000 acres in the Western Gulf of Mexico and a substantial inventory of close grid 2-D seismic data. In addition to recovering prospect development costs, Blue Dolphin Exploration seeks to retain a reversionary working interest in each drillable prospect sold. In September 1997, the Company entered into an agreement with Fidelity Oil, Black Hills Exploration and Forcenergy (the "Participants"), whereby in exchange for certain participation rights in prospects generated by the Company, the Participants partially funded the costs associated with the Company's 1997/1998 offshore prospect generation program. The Company was obligated to, among other things, devote its best efforts to initiate, evaluate, document and present drilling prospects to the Participants. This program was suspended in August 1998, as a result of the withdrawal of Forcenergy who filed for bankruptcy. In 1999, the Company placed a 50% interest in the program with Fidelity Oil, whereby in exchange for certain participation rights in prospects generated by the Company, Fidelity Oil paid $100,000 per month of the Company's costs associated with the program. Program costs were reimbursed to the Company as prospects were developed and leases acquired. When leases were acquired a portion of the costs that were previously paid to Fidelity Oil were reimbursed to it based on 6 the level of interest Fidelity retained in each prospect. The available 50% interest in the generated prospects was held for sale on an individual prospect basis. In April 2000, the Company amended the agreement with Fidelity Oil whereby in exchange for the right to acquire up to 100% of the working interest in prospects generated by the Company, Fidelity Oil paid, on a monthly basis, the costs associated with the program, which totaled $1.1 million during 2000. Fidelity Oil also reimbursed the Company for the cost of additional seismic data acquired. The available interests in the prospect inventory are held for sale on an individual prospect basis. Effective December 31, 2000, Fidelity Oil withdrew from the program. The Company is considering several alternatives including, but not limited to, finding new participants, changing the terms of the program to be more attractive to new participants and discontinuing the program. The Company entered into a consulting agreement with Cheyenne Petroleum Co., whereby the Company's remaining prospect generation staff will provide technical consulting services to Cheyenne in the evaluation of prospects for the March 2001 Central Gulf of Mexico federal lease sale. In exchange, Cheyenne will reimburse the Company for personnel costs. This agreement expires June 30, 2001. The Company's leased prospect inventory, which it continues to market, consists of prospects on the following offshore leases: . Mustang Island Area Block 817 . Mustang Island Area Block 839 The Company has reversionary working interests in several offshore leases. Generally, the Company is entitled to its reversionary interest when the other working interest owners receive a return of their investment in operations calculated on a lease wide basis, rather than a well-by-well basis. These leases are: . High Island Area Block A-7 . Galveston Area Block 297 . Matagorda Island Area Block 713 . Galveston Area Block 271 . Galveston Area Block 284 . Galveston Area Block 285 . Matagorda Island Area Block 710 HIGH ISLAND BLOCK A-7 - A gas discovery was made on our High Island A-7 prospect in April 2000. The discovery well, High Island A-7#2, began production in September 2000 at a rate of 34 Mmcf of gas per day and 53 Bbls of condensate per day. A second gas discovery was made with the drilling of the High Island A-7#3 well, with a third well currently being drilled. The Company believes that initial production from the High Island A-7#3 well will begin in the second or third quarter of 2001. Three additional wells have been permitted on High Island A-7. The Company owns an 8.9% working interest after lease-wide pay out is first achieved. Spinnaker Exploration Company is the operator of High Island A-7. OTHER. In connection with the Blue Dolphin Exploration's acquisition of American Resources in December 1999, Blue Dolphin Exploration arranged for Fidelity Oil to acquire an 80% interest in American Resources oil and gas assets located in the Gulf of Mexico for approximately $24.2 million. 7 For the right to participate in the acquisition of these assets, Fidelity Oil has agreed to assign Blue Dolphin Exploration 10% of its working interest in the proved properties acquired from American Resources after it has recovered its investment in these properties. In addition, Fidelity Oil has agreed to assign Blue Dolphin Exploration 15% of its working interest in each property after Fidelity has recovered its investment in exploratory properties on a property by property basis. The Company expects that payout of the proved properties will be achieved in late 2001. The following table summarizes the estimates of Proved Reserves, Proved Developed Reserves, and Proved Undeveloped Reserves (as hereinafter defined), future net revenues and the discounted present value of future net revenues from Proved Reserves before income taxes to the net interest the Company expects to receive from Fidelity Oil from proved properties acquired from American Resources as of December 31, 2000, using the SEC Method (defined below):

Net Oil Net Gas Future Discounted Future Reserves Reserves Net Revenues Net Revenues (1) (Mbbls) (Mmcf) (in thousands) (in thousands) -------- -------- -------------- ----------------- Total Proved Reserves 65.9 1,025 $10,756 $7,972 Total Proved Developed Reserves 65.0 884 $ 9,586 $6,988 Total Proved Undeveloped Reserves 0.9 141 $ 1,170 $ 984

(1) The estimated future net revenues before deductions for income taxes from the Company's Proved Reserves have been determined and discounted at a 10% annual rate in accordance with requirements for reporting oil and gas reserves pursuant the SEC Method. These reserve estimates are excluded from the proved reserve information shown below and in Note 11 - Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. These reserve estimates were prepared based on oil and gas prices in effect at year end, which were $25.45 per Bbl of oil and $9.91 per Mcf of gas at December 31, 2000. Gas prices subsequently have declined substantially since year end. At February 28, 2001, the Company was receiving average gas prices of approximately $5.68 per Mcf. The decrease in gas prices will require Fidelity to sell more oil and gas reserves before its investment is recovered and Blue Dolphin Exploration is assigned this interest. PROVED OIL AND GAS RESERVES. Estimates of proved reserves, future net revenues, and discounted present value of future net revenues to the net interest of the Company have been prepared as of December 31, 2000, by Ryder Scott Company, an independent petroleum engineer. The following table summarizes the estimates of Proved Reserves, Proved Developed Reserves, and Proved Undeveloped Reserves (as hereinafter defined), future net revenues and the discounted present value of future net revenues from Proved Reserves before income taxes to the net interest of the Company in oil and gas properties as of December 31, 2000, using the SEC Method (defined below): 8

PROVED RESERVES INFORMATION As of December 31, 2000 Net Oil Net Gas Future Discounted Future Reserves Reserves Net Revenues Net Revenues (1) (Mbbls) (Mmcf) (in thousands) (in thousands) --------- -------- -------------- ----------------- Total Proved: American Resources (2) 182.1 3,429 $35,068 $27,125 High Island A-7 3.0 1,238 11,378 9,764 ----- ----- ------- ------- Total Proved Reserves 185.1 4,667 $46,446 $36,889 ===== ===== ======= ======= Total Proved Developed Reserves: American Resources (2) 179.8 2,580 $27,756 $21,179 High Island A-7 2.3 554 5,275 4,476 ----- ----- ------- ------- Total Proved Developed Reserves: 182.1 3,134 $33,031 $25,655 ===== ===== ======= ======= Total Proved Undeveloped Reserves: American Resources (2) 2.3 849 $ 7,312 $ 5,946 High Island A-7 0.7 684 6,103 5,288 ----- ----- ------- ------- Total Proved Undeveloped Reserves: 3.0 1,533 $13,415 $11,234 ===== ===== ======= =======

(1) The estimated future net revenues before deductions for income taxes from the Company's Proved Reserves have been determined and discounted at a 10% annual rate in accordance with requirements for reporting oil and gas reserves pursuant to regulations promulgated by the United States Securities and Exchange Commission (the "SEC Method"). (2) As of December 31, 2000 the Company's ownership in American Resources was 77%. The above reflects 100% of American Resources' reserves and future net revenues. 23% of discounted future net revenues associated with total proved reserves, total proved developed reserves and total proved undeveloped reserves of American Resources' properties is $6,238,337, $4,871,280 and $1,367,557, respectively. The quantities of proved gas and oil reserves presented include only those amounts which the Company reasonably expects to recover in the future from known oil and gas reservoirs under existing economic and operating conditions. Therefore, proved reserves are limited to those quantities that are believed to be recoverable commercially at prices and costs, and under regulatory practices and technology existing at the time of the estimate. Accordingly, changes in prices, costs, regulations, technology and other factors could significantly affect the estimates of proved reserves and the discounted present value of future net revenues attributable thereto. 9 The proved reserves summarized in the preceding table are based upon the following estimated capital expenditures in the years indicated:

Estimated Capital Expenditures For Proved Resources For the years ending December 31, (in thousands) 2001 2002 2003 2004 2005 ---- ---- ---- ---- ---- American Resources $ 432 $ 198 $ 88 $ 128 $ 180 High Island Block A-7 467 11 101 13 0 ----- ----- ----- ----- ----- Total $ 899 $ 209 $ 189 $ 141 $ 180 ===== ===== ===== ===== =====

Management will continue to evaluate its capital expenditure program based on, among other things, demand and prices obtainable for the Company's production. The availability of capital resources and the willingness of other working interest owners to participate in development operations may affect the Company's timing for further development, and there can be no assurance that the timing of the development of such reserves will be as currently planned. The discounted present value of estimated future net revenues attributable to proved reserves has been prepared in accordance with the SEC Method after deduction of royalties and other third-party interests, lease operating expenses, and estimated production, development, workover and recompletion costs, but before deduction of income taxes, general and administrative costs, debt service and depletion and amortization. Estimated future net revenues are based on prices of oil and gas in effect at the end of the year without escalation except to the extent contractually committed. The SEC method calculates Future Net Revenues using prices in effect at December 31, 2000. The gas price used was $9.91 per Mcf, compared to $2.15 per Mcf used at December 31, 1999, reflecting a dramatic increase. Lease operating expenses, and production and development costs, were estimated based on such costs in effect at the end of the year, assuming the continuation of existing economic conditions and without adjustment for inflation or other factors. The present value of estimated future net revenues is computed by discounting future net revenues at a rate of 10% per annum. Revenues from wells not currently producing are included at the time they are expected to be placed into production based upon estimates of future development. Workover and recompletion costs are included at the time they are expected to be incurred. Estimates of production and future net revenues cannot be expected to represent accurately the actual production or revenues that may be recognized with respect to oil and gas properties or the actual present market value of such properties. For further information concerning the Company's Proved Reserves, changes in Proved Reserves, estimated future net revenues and costs incurred in the Company's oil and gas activities and the discounted present value of estimated future net revenues from the Company's Proved Reserves, see Note 11 - Supplemental Oil and Gas Information to Consolidated Financial Statements included in Item 8. PRODUCTIVE WELLS AND ACREAGE. The following table sets forth the Company's interest in productive wells and developed and undeveloped acreage as of December 31, 2000: 10

ACREAGE AND WELLS Productive Wells (1) ---------------------------------------- Developed Undeveloped Gross Net Acres (1) Acres (1) ------------------- ------------------ ------------------ ------------------- Oil Gas Oil Gas Gross Net Gross Net --- --- --- --- ----- --- ----- --- American 14 17 0.76 0.92 56,626 3,118 100,876 5,641 Resources (2) High Island 0 1 0 0.09 5,760 517 0 0 Block A-7 -- -- ---- ---- ------ ----- ------- ----- Total 14 18 0.76 1.01 62,386 3,635 100,876 5,641 == == ==== ==== ====== ===== ======= =====

(1) "Productive wells" are producing wells and wells capable of production, and include gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Wells that are completed in more than one producing horizon are counted as one well. "Developed acres" include all acreage as to which proved reserves are attributed, whether or not currently producing, but exclude all producing acreage as to which the Company's interest is limited to royalty, overriding royalty, and other similar interests. "Undeveloped acres" are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains Proved Reserves. "Gross" as it applies to wells or acreage refers to the number of wells or acres in which a working interest is owned, while "net" applies to the sum of the fractional working interests in gross wells or acreage. (2) As of December 31, 2000 the Company's ownership interest in American Resources was 77%. The above reflects 100% of American Resources' acreage and wells. PRODUCTION, PRICE AND COST DATA. The following table sets forth the approximate production volumes and revenues, average sales prices and costs (after deduction of royalties and interests of others) with respect to crude oil, condensate, and gas attributable to the interest of the Company for each of the periods indicated: NET PRODUCTION, PRICE AND COST DATA Year Ended December 31, ----------------------------------- 2000 1999 1998 ---- ---- ---- Gas: Production (Mcf) 911,671 169,329 177,260 Revenue $3,744,566 $393,125 $391,913 Average Mcf per Day 2,490.9 463.9 485.6 Average Sales Price Per Mcf $ 4.11 $ 2.32 $ 2.21 11 Oil: Production (Bbls) 64,707 6,338 1,628 Revenue $1,844,948 $151,974 $ 20,840 Average Bbls per day 176.8 17.4 4.5 Average Sales Price Per Bbl $ 28.51 $ 23.98 $ 12.80 Production Costs (1): Per Mcfe: $ 1.05 $ 4.14 $ 3.30 (1) Production costs, exclusive of workover costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes. DRILLING ACTIVITY. The following table describes the Company's drilling activity for the last three years.

Exploratory Wells Drilled Developmental Wells Drilled ----------------------------------------- --------------------------------------- Productive Dry Productive Dry --------------------- ---------------- ------------------ ----------------- Gross Net Gross Net Gross Net Gross Net --------------------- ---------------- ------------------ ----------------- 2000 American Resources 3 0.09 1 0.07 4 0.19 1 0.05 Other - - - - - - - - 1999 American Resources - - - - - - - - Other - - - - - - - - 1998 Other - - 2 1 - - - -

The Company maintains a professional staff capable of supervising and coordinating the operation and administration of its oil and gas properties and pipeline and other assets. From time to time, major maintenance and engineering design and construction projects are contracted to third-party engineering and service companies. DRILLMAR PROJECT In late 2000, the Company formed Drillmar, Inc., and owns a 37.5% interest. The Company records its investment in Drillmar by using the equity method of accounting. Drillmar has developed a new multi function deepwater well construction and intervention solution offshore drilling process, whereby a semi-submersible drilling tender unit can be placed next to a deepwater floating production platform to assist the drilling and completion of oil and gas wells. Mono hull drilling tender barges were first utilized in the Gulf of Mexico in the 1950's, whereby derrick equipment sets were placed on an offshore platform and operated from the tender barge. Due to significant weather down time, mono hull tender barges were eventually replaced in the Gulf of Mexico by new designs including self-erecting platform rigs and jack-up rigs. In the mid 1990's the first semi-tender was utilized in Malaysia by converting a semi submersible rig. The performance in the South China Sea of semi-tender units was the basis for Drillmar's plan to utilize semi-tenders as a means to significantly reduce cost of deepwater oil and gas development. Until now, the barrier prohibiting the use of semi-tenders in the deepwater was the 12 lack of a mooring solution, which allow the tender to be moored in close proximity to a floating production platform. Drillmar has developed a proprietary mooring solution and has patents pending to protect this technology. The semi-tender solution can also be applied to shallower water projects by providing customers high efficiency through its ability to mobilize and demobilize in less than twenty-four hours. Drillmar acquired a 1% general partner interest in Zephyr Drilling, Ltd., a Texas limited partnership, who acquired a semi-submersible drilling rig. Zephyr acquired the rig for approximately $7.6 million. The Company believes Drillmar's semi-tender drilling solution can improve health, safety and environmental conditions, reduce costs and accelerate production. Drillmar is currently looking for partners for development of the project and retrofitting of the semi-submersible drilling rig. Drillmar is currently preparing to arrange a private equity offering to fund the 2001 operating costs and engineering work. At December 31, 2000, the Company' investment in Drillmar and the partnership consisted of $25,000 cash and the contribution of management and administrative services, estimated at $50,000. PIPELINE OPERATIONS AND ACTIVITIES The Company's pipeline assets are held and operations conducted by Blue Dolphin Pipe Line Company, Mission Energy, Buccaneer Pipe Line and Black Marlin, all wholly-owned subsidiaries of the Company. PURCHASE AND SALE OF PIPELINE INTERESTS. On January 22, 2001, the Company and its partners, MCNIC Pipeline and Processing Company ("MCNIC") and WBI Holding, Inc. ("WBI") sold the Black Marlin Pipeline System and the recently constructed High Island Block A-5 pipeline to Williams Field Services for $9.3 million. The Company owned a 50% interest in the pipelines and received $4.6 million for its interest. In July 2000, the Company acquired a 5/6th ownership interest in the Galveston Area Block 350 pipeline, as described below, from Walter Oil and Gas Corp. for approximately $224,000, net to the Company's interest. WBI acquired the remaining 1/6th interest in this pipeline. BLUE DOLPHIN PIPELINE SYSTEM. The Company, through Blue Dolphin Pipe Line Company, Mission Energy and Buccaneer Pipe Line, owns a 50% undivided interest in the Blue Dolphin Pipeline System (the "Blue Dolphin System"). The Blue Dolphin System includes the Blue Dolphin Pipeline, Buccaneer Pipeline, onshore facilities for condensate and gas separation and dehydration, 85,000 Bbls of above-ground tankage for storage of condensate, a barge loading terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the pipeline system shore facilities, pipeline easements and rights-of-way are located. The Blue Dolphin System gathers and transports gas and condensate from various offshore fields in the Galveston area in the Gulf of Mexico to shore facilities located in Freeport, Texas. After processing, the gas is transported to an end user and a major intrastate pipeline system with further downstream tie-ins to other intrastate and interstate pipeline systems and end users. The Buccaneer Pipeline, an 8" condensate pipeline, transports condensate from the storage tanks to the Company's barge loading terminal on the Intracoastal Waterway near Freeport, Texas for sale to third parties. The Blue Dolphin Pipeline consists of two segments. The offshore segment transports both gas and condensate and is comprised of approximately 36 miles of 20-inch pipeline from the Buccaneer Field platforms in Galveston Area Blocks 288 and 296 to shore and 4 miles to the shore facility at Freeport, 13 Texas. As a result of the removal of the Buccaneer Field platforms, planned in late 2001, the Company is currently installing a new platform in Galveston Area Block 288 to operate and maintain the Blue Dolphin Pipeline System. Additionally, the offshore segment includes 9 field gathering lines totaling approximately 55 miles, connected to the main 20-inch line. This system's onshore segment consists of approximately 2 miles of 16-inch pipeline for transportation of gas from the shore facility to a sales point at a Freeport, Texas chemical plants' complex and intrastate pipeline system tie-in. Various fees are charged to producer/shippers for provision of transportation and shore facility services. Blue Dolphin System gas throughput averaged approximately 15% of capacity during 2000. Current system capacity is approximately 160 MMcf per day of gas and 7,000 Bbls per day of condensate. During 2000, 99% of gas and condensate volumes transported were attributable to production from third party producer/shippers. See Note 10 to Consolidated Financial Statements included in Item 8. BLACK MARLIN PIPELINE SYSTEM. Prior to its sale in January 2001, the Company's wholly-owned subsidiary, Black Marlin. was the owner of the Black Marlin Pipeline System (the "Black Marlin System"). The Black Marlin System included the Black Marlin Pipeline, onshore facilities for condensate and gas separation and dehydration, 3,000 Bbls of above ground tankage for storage of condensate, a truck loading facility for oil and condensate, and five acres of land in Galveston County, Texas where the Black Marlin Pipeline comes ashore and on which are located the pipeline system's shore facilities. Various fees were charged during 2000 to producer/shippers for provision of transportation and shore facility services. Black Marlin System gas throughput averaged approximately 46% and 28% of capacity during 2000 and 1999 respectively. Black Marlin System capacity is approximately 200 MMcf per day of gas and 1,500 Bbls per day of condensate. During 2000 and 1999, all gas and condensate volumes were attributable to production from third party producer/shippers. In July 2000, the Company reached an agreement to provide transportation services for Vastar Resources, Inc. in High Island Area Block A-5 offshore Texas in the Gulf of Mexico. To accommodate this production, the Company constructed a 3.4 mile 12" diameter pipeline from the production platform in High Island Area Block A-5 to the Black Marlin Pipeline. The cost to construct the pipeline was approximately $1.9 million, $.9 million net to the Company's 50% interest in the pipeline. The pipeline was completed in September 2000. OTHER. In July 2000, the Company acquired a 5/6th ownership interest in an 8-inch, 12.78 mile pipeline extending from Galveston Area Block 350 to an interconnect to a transmission pipeline in Galveston Area Block 391 (the "GA350 Pipeline"), approximately 14 miles south of the Company's Blue Dolphin Pipeline for $224,000. The pipeline currently transports approximately 6,000 Mcf of gas per day. The Company also holds a 50% undivided interest in the currently inactive Omega Pipeline, MCNIC holds a one-third (1/3) interest and WBI holds a one-sixth (1/6) interest. The Omega Pipeline originates in West Cameron Block 342 and extends to High Island, East Addition Block A-173, where it was previously connected to the High Island Offshore System ("HIOS"). The line could either be reconnected to HIOS, or a lateral pipeline could be constructed connecting into the Black Marlin Pipeline approximately 14 miles to the west. Reactivation of the Omega Pipeline will be dependent upon future drilling activity in the vicinity and successfully attracting reserves to the system. 14 The economic return to the Company on its pipeline system investments is solely dependent upon the amounts of gas and condensate gathered and transported through the pipeline systems. Competition for provision of gathering and transportation services, similar to those provided by the Company, is intense in the market areas served by the Company. See Competition, Markets and Regulation - Competition below. Since contracts for provision of such services between the Company and third party producer/shippers are generally for a specified time period, there can be no assurance that current or future producer/shippers will not subsequently tie-in to alternative transportation systems or that current rates charged by the Company will be maintained in the future. The Company actively markets gathering and transportation services to prospective third party producer/shippers in the vicinity of its pipeline systems. Future utilization of the pipelines and related facilities will depend upon the success of drilling programs around the pipelines, and attraction, and retention, of producer/shippers to the systems. MIDSTREAM DEVELOPMENT PROJECTS PETROPORT PROJECT The Company's investment in and development of an offshore crude oil terminal is through Petroport. Petroport holds proprietary technology, represented by certain patents issued and or pending, associated with the development and operation of a deepwater crude oil and products port and offshore storage facility. The Petroport deepwater terminal will receive crude oil offshore with deliveries to shore by pipeline. Costs of the offshore terminal complex, the pipeline to shore, onshore facilities and facility licensing are estimated to be $200.0 million. Onshore the Petroport pipeline will connect with an existing onshore storage and distribution network, accessing Texas Gulf coast and Mid-Continent refining centers. As currently planned, the facility will be located 40 miles off the Texas coast in approximately 115 feet of water. The terminal complex will consist of two single point mooring buoys connected to a central pumping platform, with a main export pipeline from the platform to shore facilities in the Freeport, Texas area. At its onshore terminus, the main oil pipeline will access existing onshore storage and a distribution network serving the greater Houston area refiners and the New York Mercantile Exchange crude oil futures settlement hub at Cushing, Oklahoma. The design capacity of the pipeline to shore will be in excess of 1.25 million barrels per day Petroport will be designed to offer an alternative for receipt of large volumes of imported crude oil. The Company believes Petroport's commercial success will be driven primarily by economies of scale derived from use of larger, fully loaded tankers discharging short haul Caribbean Basin cargoes into Petroport, and efficiencies gained by supertankers discharging intermediate and long haul West African, North Sea, and Persian Gulf crudes directly into Petroport versus current use of lightering operations. Petroport will also be available to serve producers in the Gulf of Mexico. It can serve as a major gathering hub and trunkline to shore, with crude received from floating production storage and offloading systems serving deepwater Gulf of Mexico producers. The Company requires but does not have partners to participate in, and bear the development costs of Petroport. The Company is actively soliciting major oil and gas companies that import large volumes of crude oil and various other entities to participate in the ownership and further costs of development. The Company currently estimates that licensing and permitting costs for the offshore port facility will be approximately $6.0 million and expects that its partner or partners in the Petroport project would be responsible for the licensing and permitting costs. The Company plans to seek financing for the 15 costs associated with facility construction, and expects that any such financing would be based on the throughput commitments from prospective users. However, there can be no assurance that the Company will be able to obtain either a partner or the necessary throughput commitments to proceed with the development of Petroport. In the process of evaluating and soliciting prospective users and partners for the Petroport project, the Company has identified a second market for an offshore crude oil port, located off the coast of Port Arthur, Texas. This facility, referred to as the Sabine Seaport, would be designed to fill a niche created by long term arrangements for the supply of short haul Caribbean Basin crudes delivered to congested shallow water port complexes on the east Texas and western Louisiana gulf coasts. This port would target the short haul trade. The Company has completed preliminary conceptual design and costing work, and a general commercial assessment for the project. In addition to the licensing and permitting costs, the Company estimates that the construction costs for the Sabine Seaport will be approximately $200.0 million. The Company does not intend to proceed with the development of the project without a major throughput commitment and financial support of a partner. There can be no assurance that the Company will be able to obtain a throughput commitment or a partner for the project. The Company's efforts to advance its Petroport and Sabine Seaport projects continues to center on development of market support, evidenced by firm throughput commitments to use the facilities when completed. While many of the refiners in the primary market areas are prospective users of the facilities, the Company's efforts have focused on those refiners whose crude supply requirements could result in commitments of at least 150,000 barrels of oil per day. Uncertainties associated with recent and anticipated industry consolidations combined with the extent of displacement of long haul imported barrels by future deepwater Gulf of Mexico production, has resulted in the deferring of throughput commitment decisions by refiners from whom the Company is seeking log-term commitments for the Petroport project. The Company believes firm throughput commitments for both the Petroport and Sabine Seaport projects will materialize. However, there can be no assurance that the Company will receive such commitments which are necessary for the further development of these projects. AVOCA GAS STORAGE PROJECT In November 1999, the Company and WBI Holdings, Inc. ("WBI Holdings") formed New Avoca Gas Storage LLC ("New Avoca"), 25% owned and managed by the Company and 75% owned by WBI Holdings, and acquired the assets of Avoca Gas Storage, Inc. The Company records its investment in New Avoca by using the equity method of accounting. The Avoca salt cavern gas storage project was conceived as a 5 Bcf working gas storage facility located south of Rochester near the town of Avoca, New York. Its design provides for 250 Mmcf per day injection and 500 Mmcf per day withdrawal capacities, with deliveries into the Tennessee Gas Pipeline HC400 24" line and other area transmission lines. The original owner, Avoca Gas Storage, Inc., filed for bankruptcy on July 7, 1997. The assets were subsequently acquired out of bankruptcy by Northeastern Gas Caverns ("Northeastern"). In November 1999, the Company and WBI Holdings acquired the Avoca gas storage assets for $400,000 ($100,000 net to the Company's interest) from Northeastern. Additionally, a contingent payment of $.5 million ($125,000 net to the Company's interest) was due to Northeastern on May 22, 2000. New Avoca made a payment of $50,000 and extended the remaining $450,000 payment to August 22, 2000. In 16 August 2000, Northeastern extended the contingent payment until October 2000 in exchange for increasing the contingent payment by $10,000 to $460,000. The contingent payment would be excused if Northeastern successfully settles a claim associated with Avoca Gas Storage, Inc. (the original owner of the Avoca gas storage assets). In October 2000, Northeastern received a payment on its claim and refunded the $40,000 previously paid by New Avoca. New Avoca can elect to liquidate the project at any time. The existing New Avoca assets include: . Approximately 900 acres of land . Pumps and pipeline for fresh water . Pump house containing 12 pumps (6,400 HP) for the solution mining operation . 9 cavern wells - 4,000' deep . 6 brine disposal wells - 9,000' deep . Storage building with valves, fittings, and miscellaneous parts . Electrical switch gear . Solution mining equipment . Compressor foundations . Electrical Sub-Station To create the salt caverns for storage of gas, fresh water is injected from the surface to dissolve the salt formations below. The brine solution produced by this process must be continuously brought to the surface and then injected into underground disposal wells. The disposal wells must have sufficient porosity and permeability to accept the injected brine at a rate at least consistent with the rate at which brine is being produced during the creation of the salt caverns. The original owners of the Avoca gas storage assets conducted tests to determine the rate that the disposal wells would accept brine. New Avoca believes that the testing procedures used by the original owners of the project to analyze the rate at which the disposal wells could accept brine may have been flawed as a result of the accelerated pace at which the tests were conducted, and therefore yielded test results that were uncertain and did not conclusively support an acceptable rate of brine disposal. The original owners of the Avoca gas storage assets encountered technical and other difficulties as a result of the uncertainty of their test results. Simultaneously, New Avoca is reviewing additional brine disposal options that could be used to accelerate the creation of the salt caverns. During 2000, New Avoca completed an analysis of the project. Based on this analysis and recent technological advances, New Avoca believes the disposal wells will be capable of handling the more moderate rates of brine injection expected to be produced under its proposed construction schedule. From October 2000 through February 10, 2001, New Avoca tested the disposal wells to determine the rate that these wells will accept brine. On February 12, 2001, as a result of mild seismic activity in the area surrounding Avoca, the New York State Department of Environmental Conservation requested that New Avoca stop testing the disposal wells. Presently, New Avoca is evaluating the test results, and New Avoca and the State Department of Environmental Conservation are investigating whether there is any correlation between the seismic activity that occurred in the area and the testing of the disposal wells. Based on the results of the tests and investigation of the seismic activity, New Avoca expects to make a decision to either proceed with or liquidate the project. If liquidated, the Company believes that it can recover its investment in this project. If the decision is made to proceed with the project, New Avoca estimates that it will take between one and one-half to two years to begin operations at partial capacity, and three to four years for the facility to operate at full capacity. However, until the Company has 17 reviewed and analyzed the results from the tests of the disposal wells it will be unable to determine whether to proceed with this project or to establish a definitive schedule or accurately estimate the costs to complete this project if it determines to proceed. CUSTOMERS The Company generates revenues from both of its primary business segments. In 2000, no customer accounted for more than 10% of the Company's total revenues. COMPETITION The oil and gas industry is highly competitive in all segments. Increasingly vigorous competition occurs among oil, gas and other energy sources, and between producers, transporters, and distributors of oil and gas. Competition is particularly intense with respect to the acquisition of desirable producing properties and the marketing of oil and gas production. There is also competition for the acquisition of oil and gas leases suitable for exploration and for the hiring of experienced personnel to manage and operate the Company's assets. Several highly competitive alternative transportation and delivery options exist for current and potential customers of the Company's traditional gas and oil gathering and transportation business as well as for refiners, shippers, marketers and producers of crude oil whom the Company's proposed Petroport and Sabine Seaport facilities would serve. Gas storage customers who would use the proposed Avoca Gas Storage system have alternatives, including depleted reservoir and other salt cavern storage systems. Competition also exists with other industries in supplying the energy and fuel needs of consumers. MARKETS The availability of a ready market for gas and oil, and the prices of such gas and oil, depends upon a number of factors, which are beyond the control of the Company. These include, among other things, the level of domestic production, actions taken by foreign oil and gas producing nations, the availability of pipelines with adequate capacity, the availability of vessels for direct shipment, lightering and transshipment and other means of transportation, the availability and marketing of other competitive fuels, fluctuating and seasonal demand for oil, gas and refined products, and the extent of governmental regulation and taxation (under both present and future legislation) of the production, importation, refining, transportation, pricing, use and allocation of oil, gas, refined products and alternative fuels. Accordingly, in view of the many uncertainties affecting the supply and demand for crude oil, gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the gas and oil produced for sale or prices chargeable for transportation, terminaling and storage services, which the Company provides or may provide in the future. GOVERNMENTAL REGULATION The production, processing, marketing, and transportation of oil and gas, and planned terminaling and storage of crude oil and gas storage by the Company are subject to federal, state and local regulations which can have a significant impact upon the Company's overall operations. FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. The transportation and resale of gas in interstate commerce have been regulated by the Natural Gas Act, the Natural Gas Policy Act and the rules and regulations promulgated by FERC. In the past, the federal government has regulated the prices at which gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which 18 removed all remaining Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting producer sales of gas, effective January 1, 1993. Congress could, however, reenact price controls in the future. The price and terms for access to pipeline transportation is subject to extensive federal regulation. In April 1992, the FERC issued Order No. 636, beginning a series of related orders, which required interstate pipelines to provide open-access transportation on a basis that is equal for all gas suppliers. The FERC has stated that it intends Order No. 636 to foster increased competition within all phases of the gas industry. Order No. 636 affects how buyers and sellers gain access to the necessary transportation facilities and how gas is sold in the marketplace. In 2000, the FERC issued Order No. 637 which, among other things, will permit pipelines to file for peak/off-peak and term differentiated rate structures and changed existing regulations relating to scheduling procedures, capacity segmentation pipeline imbalance processes and penalties and pipeline reporting requirements. The Company cannot predict whether the FERC's actions will achieve the goal of increasing competition in the gas markets or how these, or future regulations will affect its operations or competitive position. However, the Company does not believe that any action taken will affect it in any way that materially differs from the way that such action affects the Company's competitors. Of the gas pipelines owned by the Company in 2000, only the recently sold Black Marlin Pipeline was subject to rules and regulations of the Natural Gas Act. As a result, its gas transportation service and pricing service were subject to the regulatory jurisdiction of the FERC. All of the Company's pipelines located offshore in federal waters are subject to the requirements of the Outer Continental Shelf Lands Act ("OCSLA"). FERC has stated that nonjurisdictional gathering lines, as well as interstate pipelines, are fully subject to the open access and nondiscrimination requirements of OCSLA's Section 5, which generally authorizes the FERC to insure that gas pipelines on the Outer Continental Shelf will transport for non-owner shippers in a nondiscriminatory manner and will be operated in accordance with certain pro-competitive principles. More recently, the FERC has undertaken several investigations into the nature and extent of its regulatory powers on the Outer Continental Shelf. It issued a policy statement on Outer Continental Shelf pipelines reaffirming the requirement that all pipelines provide nondiscriminatory service. In 2000, FERC issued Order 639, formally imposing new OCSLA regulations on offshore pipelines not otherwise subject to its Natural Gas Act jurisdiction. Order 639's requirements, which largely entail reporting and disclosure obligations to FERC, contain certain exemptions for, among other things, an offshore pipeline system that "feeds into a facility where gas is first collected or a facility where gas is first separated, dehydrated, or otherwise processed." Further FERC initiatives concerning possibly diminished Natural Gas Act regulation of pipelines on the OCS and/or broader regulation under the OCSLA remain possible and could cause increased regulatory compliance costs. Since all of the Companies' offshore pipelines fall within the exemption for feeder facilities and already operate on the basis required under OCSLA, the Company does not anticipate significant changes directly resulting from requirements concerning nondiscriminatory open access transportation. Moreover, if an offshore pipeline's throughput increases to the extent that the pipeline's capacity is completely utilized, under OCSLA, the FERC may be petitioned to direct capacity allocation on the pipeline. Accordingly, the Company cannot predict how application of the OCSLA to its pipelines may ultimately affect Company operations. 19 Aside from the OCSLA requirements and federal safety and operational regulations, regulation of gas gathering activities is primarily a matter of state oversight. Regulation of gathering activities in Texas includes various transportation, safety, environmental and non-discriminatory purchase/transport requirements. FEDERAL REGULATION OF OIL PIPELINES. The Company's operation of the Buccaneer Pipeline is subject to a variety of regulations promulgated by the FERC and imposed on all oil pipelines pursuant to federal law. In particular, the rates chargeable by the Company are subject to prior approval by the FERC, as are operating conditions and related matters contained in the Company's transportation tariffs which are on file with the FERC. In 1993, the FERC issued Order No. 561, which was intended to simplify oil pipeline ratemaking, largely through use of a ceiling based on an indexing system. At the end of 2000, the Commission issued an order based on a five-year review of the indexing system, affirming this approach to oil pipeline ratemaking. Because Buccaneer Pipeline has not taken action to become subject to Order No. 561 or Order No. 572 concerning market-based rates for oil pipelines, the Company cannot predict whether or how an indexed or market-based rate system will affect the Buccaneer Pipeline's rates. SAFETY AND OPERATIONAL REGULATIONS. The operations of the Company are generally subject to safety and operational regulations administered primarily by the MMS, the U.S. Department of Transportation, the U.S. Coast Guard, the FERC and/or various state agencies. Currently, the Company believes that it is in material compliance with the various safety and operational regulations that it is subject to. However, as safety and operational regulations are frequently changed, the Company is unable to predict the future effect changes in these regulations will have on its operations, if any. REGULATION OF DEEPWATER PORTS: Permitting and Licensing. The ownership, construction and operation of a deepwater crude oil terminal facility (a "Deepwater Port"), such as the Company's proposed Petroport and Sabine Seaport facilities, must conform to the requirements of a number of federal, state and local laws. A license from the Department of Transportation ("DOT") is required under the Deepwater Port Act of 1974 ("DWPA"), as amended. Permits from the Environmental Protection Agency and the Federal Communication Commission are required, as well as permits from the U.S. Army Corps of Engineers and the State of Texas to construct ancillary port facilities, such as pipelines and onshore facilities. The DWPA empowers the Secretary of Transportation to license and regulate Deepwater Ports beyond the territorial sea of the United States. License applications must include sufficient information to allow the Secretary of Transportation to judge whether a Deepwater Port will comply with all technical, environmental, and economic criteria. The application and licensing process includes the preparation of an Environmental Impact Statement, development of detailed operations procedures, submission of extensive financial and ownership data and public hearings. The Company was a principal participant in the development and passage of The Deepwater Port Modernization Act in 1996, successfully amending the DWPA. The amendments to the Deepwater Port Act provide: (1) upon written request of an applicant for a license, the Secretary may exempt the applicant from certain of the informational filing requirements if the Secretary determines such information is not necessary to facilitate his or her determination and such exemption will not limit public review; (2) the facility is explicitly permitted to receive domestic production from the United States Outer Continental Shelf; (3) simplification and streamlining of the regulatory process to which the facility would be subject during both the licensing process and when in operation; and (4) elimination of various facility use restrictions. Once a license is issued, the law states that it remains in effect unless suspended or revoked by the Secretary of Transportation or is surrendered by the licensee. 20 Regulations provide for extensive consultation among all interested federal agencies, any potentially affected coastal state, and the general public. Adjacent coastal states are granted an effective veto power or reservation over proposed Deepwater Ports. The Secretary of Transportation will not issue a license without the approval of the governor of each adjacent coastal state. Under the statute, if a Governor of an adjacent coastal state notifies the Secretary of Transportation that a proposal is inconsistent with the state programs relating to environmental protection, land and water use, and coastal zone management, then the Secretary of Transportation shall grant the license on the condition that the proposal is made consistent with such state programs. Governors may, in their discretion, also reject proposed Deepwater Ports on other grounds. In addition, the DWPA requires all Deepwater Ports, including related storage facilities, be operated as common carriers. As a common carrier the Company's proposed Petroport and Sabine Seaport facilities would be required to accept, transport or convey all oil delivered, unless it is subject to "effective competition" from alternative transportation systems. Given the nature and complexity of obtaining the necessary license and permits, there can be no assurance that the Company will be issued a Deepwater Port license and other necessary permits. FEDERAL OIL AND GAS LEASES. The Company's operations conducted on offshore federal oil and gas leases under the OCSLA must be conducted in accordance with permits issued by the MMS and are subject to a number of other regulatory restrictions similar to those imposed by the states. With respect to any Company operations conducted on offshore federal leases, liability may generally be imposed under OCSLA for costs of clean-up and damages caused by pollution resulting from such operations, other than damages caused by acts of war or the negligence of third parties. Under certain circumstances, including but not limited to conditions deemed a threat or harm to the environment, the MMS may also require any Company operations on federal leases to be suspended or terminated in the affected area. Furthermore, the MMS generally requires that offshore facilities be dismantled and removed within one year after production ceases or the lease expires. ENVIRONMENTAL REGULATION. The Company's activities with respect to (1) exploration, development and production of oil and natural gas and (2) the operation and construction of pipelines, plants, and other facilities for the transportation and processing, and storage of natural gas and natural gas liquids are subject to stringent environmental regulation by local, state and federal authorities, including the U.S. Environmental Protection Agency ("EPA"). Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells and related equipment. Similarly, such regulation has also increased the cost of design, construction, and operation of natural gas pipelines and processing facilities. Although the Company believes that compliance with existing environmental regulations will not have a material adverse affect on operations or earnings, there can be no assurance that significant costs and liabilities, including civil and criminal penalties, will not be incurred. Moreover, future developments, such as stricter environmental laws and regulations or claims for personal injury or property damage resulting from our operations, could result in substantial costs and liabilities. It is not anticipated that, in response to such regulation, the Company will be required in the near future to expend amounts that are material relative to its total capital structure. However, it is possible that the costs of compliance with environmental and health and safety laws and regulations will continue to increase. Given the frequent changes made to environmental and health and safety regulations and laws, the Company is unable to predict the ultimate cost of compliance. 21 The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") imposes liability, without regard to fault or the legality of the original conduct, on responsible parties with respect to the release or threatened release of a "hazardous substance" into the environment. Responsible parties, which include the owner or operator of a site where the release occurred and persons that disposed or arranged for the disposal of a hazardous substance at the site, are liable for response and remediation costs and for damages to natural resources. Petroleum and natural gas are excluded from the definition of "hazardous substances;" however, this exclusion does not apply to all materials associated with the production of petroleum or natural gas. At this time, neither the Company nor any of its predecessors has been designated as a potentially responsible party under CERCLA. The federal Resource Conservation and Recovery Act ("RCRA") and its state counterparts regulate solid and hazardous wastes and impose civil and criminal penalties for improper handling and disposal of such wastes. EPA and various state agencies have promulgated regulations that limit the disposal options for such wastes. Certain wastes generated by our oil and gas operations are currently exempt from regulation as "hazardous wastes," but in the future could be designated as "hazardous wastes" under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements. The Company currently owns or leases, or has in the past owned or leased, numerous properties used for the exploration and production of oil and gas or used to store and maintain equipment regularly used in these operations. Although our past operating and disposal practices at these properties were standard for the industry at the time, hydrocarbons or other substances may have been disposed of or released on or under these properties or on or under other locations. In addition, many of these properties have been operated by third parties whose waste handling activities were not under our control. These properties and any waste disposed thereon may be subject to CERCLA, RCRA, and analogous state laws which could require the Company to remove or remediate wastes and other contamination or to perform remedial plugging operations to prevent future contamination. The Oil Pollution Act of 1990 ("OPA") and regulations promulgated thereunder include a variety of requirements related to the prevention of oil spills and impose liability for damages resulting from such spills. OPA imposes liability on owners and operators of onshore and offshore facilities and pipelines for removal costs and certain public and private damages arising from a spill. OPA establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser liability limits for vessels depending upon their size. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction, or operating regulations. If a party fails to report a spill or cooperate in the cleanup, liability limits likewise do not apply. OPA imposes ongoing requirements on responsible parties, including proof of financial responsibility for potential spills. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges, worst-case spill potential and other factors. The Company believes it has established adequate financial responsibility. While the financial responsibility requirements under OPA may be amended to impose additional costs on us, the impact of such a change is not expected to be any more burdensome on the Company than on others similarly situated. The Clean Air Act and state air quality laws and regulations contain provisions that impose pollution control requirements on emissions to the air and require permits for construction and operation of certain emissions sources, including sources located offshore. The Company may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining 22 operating permits and approvals addressing emission-related issues, although the Company does not expect to be materially adversely affected by such expenditures. The Clean Water Act ("CWA") regulates the discharge of pollutants to waters of the United States and imposes permit requirements on such discharges, including discharges to wetlands. Federal regulations under the CWA and OPA require certain owners or operators of facilities that store or otherwise handle oil, to prepare and implement spill prevention, control and countermeasure plans and facility response plans relating to the possible discharge of oil into surface waters. With respect to certain of our operations, we are required to prepare and comply with such plans and to obtain and comply with permits. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide varying civil and criminal penalties and liabilities for the spills to both surface and groundwaters. The Company believes it is in substantial compliance with the requirements of the CWA, OPA, and state laws, and that any non-compliance would not have a material adverse effect on the Company. LEGISLATION AND RULEMAKING. In October 1996 the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the OPA to establish requirements for evidence of financial responsibility for certain offshore facilities, other than Deepwater Ports. The amount required is $35.0 million for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. The Company currently maintains this statutory $35.0 million coverage. In August 1995, the DOT issued a Rulemaking under OPA providing that the Secretary of Transportation can set the liability limit and associated Certificate of Financial Responsibility requirement for Deepwater Ports from between $350.0 million and $50.0 million concurrent with the overall processing of the DWPA license application. Development of the liability limit would be based upon engineering and environmental analysis provided during the licensing process. Federal and state legislative rules and regulations are pending that, if enacted, could significantly affect the oil and gas industry. It is impossible to predict which of those federal and state proposals and rules, if any, will be adopted and what effect, if any, they would have on the operations of the Company. In addition, various federal, state and local laws and regulations covering the discharge of materials into the environment, occupational health and safety issues, or otherwise relating to the protection of public health and the environment, may affect the Company's operations, expenses and costs. The trend in such regulation has been to place more restrictions and limitations on activities that may impact the general or work environment, such as emissions of pollutants, generation and disposal of wastes, and use and handling of chemical substances. It is not anticipated that, in response to such regulation, the Company will be required in the near future to expend amounts that are material relative to its total capital structure. However, it is possible that the costs of compliance with environmental and health and safety laws and regulations will continue to increase. Given the frequent changes made to environmental and health and safety regulations and laws, the Company is unable to predict the ultimate cost of compliance. GLOSSARY OF CERTAIN OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbon. 23 Bcf. One billion cubic feet of gas. Btu OR BRITISH THERMAL UNIT. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. CONDENSATE. Liquid hydrocarbons associated with the production of a primarily gas reserve. DEVELOPMENT WELL. A well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. EXPLORATORY WELL. A well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir or to extend a known reservoir. FIELD. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. LEASE BLOCK. Refers to several leases within close proximity of one another. LEASEHOLD INTEREST. The interest of a lessee under an oil and gas lease. Mbbls. One thousand barrels of oil or other liquid hydrocarbons. Mcf. One thousand cubic feet of gas. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or gas liquids. Mmbtu. One million British Thermal Units. Mmcf. One million cubic feet of gas. Mmcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids. NET REVENUE INTEREST. The percentage of production to which the owner of a working interest is entitled. NONOPERATING WORKING INTEREST. A working interest, or a fraction of a working interest, in a tract where the owner is not the operator of the tract. OVERRIDING ROYALTY. An interest in oil and gas produced at the surface, free of the expense of production that is in addition to the usual royalty interest reserved to the lessor in an oil and gas lease. PROSPECT. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of oil, gas or both. PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved developed reserves are further categorized 24 into two sub categories, proved developed producing reserves and proved developed non-producing reserves. PROVED DEVELOPED PRODUCING. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. PROVED DEVELOPED NON-PRODUCING. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of producing for mechanical reasons. PROVED RESERVES. The estimated quantities of oil, gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required for recompletion. REVERSIONARY INTEREST. A form of ownership interest in property that reverts back to the transferor after expiration of an intervening income interest or the occurrence of another triggering event. ROYALTY INTEREST. An interest in a gas and oil property entitling the owner to a share of gas and oil production free of costs of production. UNDIVIDED INTEREST. A form of ownership interest in which more than one person concurrently owns an interest in the same oil and gas lease or pipeline. WORKING INTEREST. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. ITEM 2. PROPERTIES Information appearing in Item 1 describing the Company's oil and gas properties under the caption "Business and Properties" is incorporated herein by reference. The Company leases its executive offices in Houston, Texas, under an operating lease expiring December 31, 2006. The Company also leases under an operating lease, its division office in New Orleans, Louisiana. The lease has been extended from April 30, 2000 to April 30, 2002. The Company's aggregate annual lease payment obligations under these leases are $190,211. ITEM 3. LEGAL PROCEEDINGS On May 8, 2000, American Resources, a 77% owned subsidiary of the Company, and its former Chief Financial Officer, were named in a lawsuit in the United States District Court for the Southern District of Texas, Houston Division, styled H&N Gas and Howard Energy Marketing, L.L.C. v. American Resources Offshore, Inc. et al (Case No H-00-1371). The lawsuit alleges, among other things, that H&N Gas ("H&N") was defrauded by American Resources in connection with gas purchase options and gas price swap contracts entered into from February 1998 through September 1999. H&N alleges unlawful collusion between American Resources' prior management and the then president of H&N, Richard Hale ("Hale"), to 25 the detriment of H&N. H&N generally alleges that Hale directed H&N to purchase illusory options from American Resources that bore no relation to any physical gas business and that American Resources did not have the financial resources and/or sufficient quantity of gas to perform. H&N further alleges that American Resources and Hale colluded with respect to swap transactions that were designed to benefit American Resources at the expense of H&N Gas. H&N further alleges civil conspiracy against all the defendants. H&N is seeking approximately $6.2 million in actual damages plus treble damages, punitive damages, prejudgment interest and attorneys' fees against ARO directly. As a result of its conspiracy allegation, H&N also contends that all defendants are jointly and severally liable for over $62.0 million dollars in actual damages plus treble damages, punitive damages, prejudgment interest and attorneys' fees. American Resources intends to vigorously defend this claim. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Company did not submit any matter to a vote of security holders during the quarter ended December 31, 2000. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company's common stock trades in the over-the-counter market and is quoted on the NASDAQ Small Cap Market under the symbol "BDCO". As of March 26, 2001, there were an estimated 325 stockholders of record and the Company estimates there are more than 1,000 beneficial owners of its common stock. NASDAQ quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions. The following table sets forth, for the periods indicated, the high and low bid price for the common stock as reported on NASDAQ. High Low ---- --- Quarter Ended March 31, 1999....... $4.69 $3.13 Quarter Ended June 30, 1999........ $6.00 $4.00 Quarter Ended September 30, 1999... $6.88 $5.00 Quarter Ended December 31, 1999.... $7.94 $5.75 Quarter Ended March 31, 2000....... $6.38 $5.00 Quarter Ended June 30, 2000........ $6.13 $4.50 Quarter Ended September 30, 2000... $5.56 $2.75 Quarter Ended December 31, 2000.... $5.56 $2.50 The Company has not declared or paid any dividends on the common stock since its incorporation. The Company currently intends to retain earnings for its capital needs and expansion of its business and does not anticipate paying cash dividends on the common stock in the foreseeable future. Previously, the Company was restricted, pursuant to its loan agreement from paying dividends on the common stock if there was an outstanding balance under the loan agreement. Any loan agreements which the Company may enter into in the future will likely contain restrictions on the payment of dividends on its' common stock. Future policy with respect to dividends will be determined by the Board of Directors based upon the Company's earnings and financial condition, capital requirements and other considerations. The Company is a holding company that conducts substantially all of its operations through its subsidiaries. As a result, the Company's ability to pay dividends on the common stock is dependent on the cash flow of its subsidiaries. 26 RECENT SALES OF UNREGISTERED SECURITIES. During the year ended December 31, 2000, directors, officers and other employees exercised options to purchase 33,665 shares of common stock. The sale of shares was privately made to directors, officers and other employees pursuant to the Company's 1985 and 1996 Stock Option Plans, at exercise prices between $2.7885 and $3.825 per share. The Company relied on an exemption under Section 4(2) of the Securities Act of 1933 in effecting these transactions. ITEM 6. SELECTED FINANCIAL DATA The selected financial data of the Company and its consolidated subsidiaries is presented for the five years ended December 31, 2000. The selected financial data should be read in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements of the Company and the related notes included elsewhere in this report.

YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------------ 2000 1999 1998 1997 1996 ------------ ----------- ---------- ------ --------- Operating Revenues $ 7,941,970 $ 2,757,056 $ 3,558,773 $ 4,982,606 $ 4,128,568 Net Income (Loss) (10,135,120)(3) ($2,086,511)(4) ($9,059,979)(3) $ 983,095 $ 92,302 Net Income (Loss) per Common Share (1) (3) ($1.70) ($0.43) ($2.02) $.22 ($.06) Weighted average number of Common Shares outstanding (3) 5,963,318 4,837,504 4,492,344 4,462,072 3,107,206 Net Income (Loss) per diluted Common Share (1) (2) ($1.70) ($0.43) ($2.02) $.22 ($.06) Weighted average number of Common Shares and dilutive Potential Common Shares Outstanding (2) 5,963,318 4,837,504 4,492,344 4,531,208 3,107,026 Working Capital $ 1,388,465 $ 93,231 $ 310,543 $ 1,856,333 $ 917,113 Total Assets $ 13,912,955 $ 21,538,216 $ 14,867,216 $24,644,387 $23,428,426 Long-term debt - - $ 2,060,600 $ 2,060,600 $ 2,060,600

1. Income from continuing operations per Common Share and dilutive Common Share is based on the weighted average number of Common Shares outstanding. 2. The weighted average number of Common Shares and potential Common Shares outstanding for the year ended December 31, 1996 has been restated to reflect the one-for-fifteen reverse stock split effected on December 8, 1997. 3. Includes a non-cash impairment of oil and gas properties effective December 31, 2000 and 1998. 4. Includes the gain on the sale of a one-sixth interest in the Blue Dolphin Pipeline System effective March 1, 1999, and a non-cash valuation allowance of its deferred tax assets. 27 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a review of certain aspects of the financial condition and results of operations of the Company and should be read in conjunction with the Consolidated Financial Statements included in Item 8 and incorporated herein by reference, and Item 1. Business. FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES The following table summarizes our financial position at December 31, 2000 and 1999: December 31, (amounts in thousands) ---------------------- 2000 1999 ---- ---- Amount % Amount % ------ -- ------ -- Working Capital $1,388 15 $ 93 - Property and equipment, net 5,345 58 15,195 82 Other noncurrent assets 2,476 27 3,316 18 ------ --- ------- --- Total $9,209 100 $18,604 100 ====== === ======= === Other non-current liabilities $ 550 6 $ - - Minority Interest 1,196 13 958 5 Shareholders' equity 7,463 81 17,646 95 ------ --- ------- --- Total $9,209 100 $18,604 100 ====== === ======= === The significant change in our financial position from December 31, 1999 to December 31, 2000, was due to the impairment of oil and gas properties of $10.7 million recorded in 2000, comprised of a non-cash write-off of proved reserves from the Buccaneer Field of $5.3 million and the recognition of associated plugging and abandonment costs estimated to be $5.4 million. Historically, the Company has primarily relied on the proceeds from financing activities and the sale of assets to supplement its capital requirements. In 2000, the Company financed its activities through both private debt financing and operating activities. The Company's future cash flows are subject to a number of variables, including the level of production, utilization of its pipeline systems from operating activities, utilization of the Company's services by third parties and commodity prices among others. The Company believes that it will have sufficient cash flow from operations, private equity or debt financing activities and the sale of assets to meet its obligations and operating needs for the current year. However, the Company cannot be assured that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. The net cash provided by or used in our operating, investing and financing activities is summarized below: Years Ended December 31 ----------------------- (amounts in thousands) 2000 1999 1998 ---- ---- ---- Net cash provided by (used in): Operating activities $ 3,601 $(1,087) $ 397 Investing activities (3,548) (5,458) (1,791) Financing activities 852 7,118 231 ------- ------- ------- Net increase (decrease) in cash $ 905 $ 573 $(1,163) ======= ======= ======= 28 The Company's cash flow from operating activities increased by $4.7 million in 2000 from 1999, due primarily to income provided by American Resources, which was acquired in December 1999, and an increase in oil and gas volumes transported on the Black Marlin System along with gas price increases. The Company's cash flows from operating activities decreased $1.5 million in 1999 from 1998, due primarily to a decline in oil and gas volumes transported by the Blue Dolphin System. The Blue Dolphin System is dependent upon drilling and development activity in its vicinity which was very limited during 2000, 1999 and 1998. Cash flow used in investing activities in 2000 included capital expenditures for the exploration and development costs associated with the American Resources oil and gas properties of approximately $1.9 million and construction of the pipeline from High Island A-5 to the Black Marlin Pipeline of $.9 million. Cash flow used in investing activities in 1999 primarily included capital expenditures for the acquisition of the 50% ownership interest in the Black Marlin Pipeline of $2.7 million and the 75% ownership interest in American Resources of $4.5 million. Cash flow used in investing activities in 1998 included the unreimbursed costs of the oil and gas prospect generation program of $.7 million and development costs of Petroport of $.8 million. Cash flow provided by financing activities in 2000 primarily consisted of proceeds received from private placement of debt securities in the aggregate principal amount of $1.0 million. The Company issued three convertible promissory notes in 2000 totaling $1.0 million: two in the principal amount of $200,000 each on May 25, 2000 and July 6, 2000, issued to Ivar Siem, Chairman of the Company, and one in the principal amount of $0.6 million on November 30, 2000, issued to TI A/S, beneficially controlled by Ivar Siem. These convertible promissory notes were due March 31, 2001, bore interest at the rate of 10% per annum and were convertible into common stock at the rate of $6.00 per share. In January 2001, the Company retired these notes and a $1.0 million convertible promissory note payable to Harris A. Kaffie, a director of the Company, with the proceeds received from the sale of the Black Marlin System. The Company expects to continue to seek external financing to meet its liquidity requirements. On January 22, 2001, the Company and its partners sold the Black Marlin Pipeline System for $7.3 million and the recently constructed High Island Block A-5 pipeline for $2.0 million to Williams Field Services; $3.6 million and $1.0 million, respectively, net to the Company's interest. The Black Marlin System accounted for 30% of the Company's revenues for the year ended December 31, 2000. In November 2000, the Company elected to abandon the Buccaneer field due to adverse developments in the field. See Item 1 Business "Oil and Gas Exploration and Production Activities - Buccaneer Field." The Company reached an agreement with Tetra Applied Technologies, Inc. ("Tetra"), to plug and abandon the wells located in the Buccaneer Field. Tetra plugged and abandoned the remaining ten wells in the Buccaneer Field in the first quarter of 2001 for approximately $1.1 million. In addition, Maritech Resources, Inc. ("Maritech") an affiliate of Tetra has purchased an adjacent lease on which the Company provided production operating services to Apache Corporation. In December 2000, as a result of the Company's plans to abandon the Buccaneer Field platform facilities, the Company and Maritech terminated the operating agreement. A new platform will be installed to operate and maintain the Blue Dolphin Pipeline System, as well as handle the production from Maritech's lease. The Blue Dolphin System is currently tied into and operated from the Buccaneer Field platforms. The Company believes that the installation of the new platform is the best alternative to continue to operate and maintain the Blue Dolphin System. The Company expects that the platform will be installed in the second quarter of 2001, at an estimated cost of $1.5 million net to the Company's 50% interest in the Blue Dolphin System. The removal of the Buccaneer Field platform facilities is expected to begin in the second half of 2001, at an estimated cost of $4.3 million. 29 The Company will partially finance the well plugging and abandonment and the removal of the Buccaneer Field platform facilities totaling $5.4 million, by using its escrow fund for abandonment obligations of approximately $1.5 million. The Company expects to finance the remaining costs, and install a new Blue Dolphin System platform from the proceeds received from the sale of the Black Marlin System and from working capital and the private placement of debt or equity securities. In December 1999, the Company entered into an agreement with Fidelity Oil to manage their interest in the oil and gas properties acquired from American Resources for $40,000 per month. This amount was intended to reimburse the Company for the cost of the services provided. During the year ended December 31, 2000 the Company received $480,000 in management fees pursuant to this agreement. The agreement expired in December 2000 and provides for continuation thereafter on a year to year basis unless terminated by either party or extended by Fidelity Oil. Fidelity Oil terminated this agreement effective December 31, 2000. The Company's $10.0 million reducing revolving credit facility with Bank One, Texas, N.A. (the "Loan Agreement") expired on December 31, 2000. There was no outstanding balance at December 31, 2000. In July 2000, the Company executed an agreement to provide transportation services for Vastar Resources in High Island Block A-5 offshore Texas in the Gulf of Mexico. To accommodate this production, the Company agreed to construct a 3.4 mile 12" diameter pipeline from the production platform in High Island A-5 to the Black Marlin Pipeline. The cost to construct the pipeline was $1.9 million, $.9 million net to the Company's 50% interest in the pipeline. The pipeline was completed in September 2000. The Company sold this pipeline with the Black Marlin System in January 2001. In July 2000, the Company acquired an 83.3% ownership interest in an 8- inch, 12.78-mile pipeline from Walter Oil and Gas Corp. for approximately $224,000. The pipeline extends from Galveston Area Block 350 to an interconnect to another pipeline in Galveston Area Block 391, approximately 14 miles south of the Company's Blue Dolphin Pipeline. The pipeline currently transports 6 Mmcf of gas per day. The Company believes it is well positioned to attract future discoveries in the area. The reserves and future net revenues presented in Item 1 "Business - Oil and Gas Exploration and Production Activities," reflect capital expenditures totaling $898,900, $209,200, $189,300, $141,500 and $179,600 in the years ending December 31, 2001, 2002, 2003, 2004 and 2005, respectively. Management will continue to evaluate its capital expenditure program based on, among other things, field reservoir performance, availability and cost of drilling and workover equipment, and demand and prices obtainable for the Company's production, as well as availability of capital resources. There can be no assurance that reserves will be developed as currently planned. In April 2000, the Company amended its prospect generation program agreement with Fidelity Oil, whereby in exchange for certain participation rights of up to 100%, Fidelity Oil funded $1.1 million of the costs associated with the program during 2000. Fidelity Oil also reimbursed the Company for seismic data acquired. Fidelity Oil withdrew from the prospect generation program effective December 31, 2000. If funding from alternate sources is not arranged, the Company may terminate its prospect generation program. The Company developed prospects on three leases, awarded by the MMS, through its offshore prospect generation program. The leases were awarded to Callon Petroleum Operating Company ("Callon"), a subsidiary of Callon Petroleum Company, on high bids submitted at MMS Western Gulf of Mexico Lease Sale 177 held August 23, 2000. The leases cover Galveston Area Blocks 271 and 284, and 30 Matagorda Island Area Block 710. Callon will own a 50% interest and operate all leases. Other owners include Fidelity Oil, 40% and Black Hills Exploration and Production, Inc., a subsidiary of Black Hills Corporation, 10%. A fourth block, Galveston Area Block 285 acquired by the Company in 1998, will be assigned to the same ownership group. The Company's subsidiary, Blue Dolphin Exploration Company, owns a 10% reversionary working interest in the four leases after lease-wide payout is achieved by the original working interest owners. The Company previously announced a gas discovery in High Island Area Block A-7, in the Gulf of Mexico. The Company acquired the block in 1995, and owns an 8.9% reversionary working interest after lease-wide payout is first achieved. Production from the first well in the block began in September 2000 at a rate of 34 Mmcf of gas per day. A second successful discovery well was drilled and is expected to be on production in the second or third quarter of 2001. A third well is currently being drilled. Before the Company is assigned its working interest, the initial working interest owners must achieve lease-wide payout of their investment. In December 1999, American Resources was paid approximately $4.5 million by Blue Dolphin Exploration for American Resources common stock, representing a 75% ownership interest, and $24.2 million by Fidelity Oil for an 80% interest in its Gulf of Mexico assets. The proceeds were used by American Resources to retire certain indebtedness. The indebtedness included American Resources senior secured debt totaling approximately $51.2 million to Den norske bank ("Den norske"). Den norske sold the senior debt for $27.0 million and a contingent future payment if the cumulative net revenues received by American Resources and Fidelity Oil attributable to American Resources proved oil and gas reserves in the Gulf of Mexico as of January 1, 1999, exceed $30.0 million during the period January 1, 1999, through December 31, 2001. If that occurs Den norske will be entitled to receive an amount equal to 50% of the net revenues in excess of $30.0 million during that three-year period. If any contingent amount becomes payable to Den norske, 80% will be paid by Fidelity Oil and 20% will be paid by American Resources. The payment, if any, is due on March 15, 2002. American Resources now estimates that it is probable that a payment to Den norske will be due based upon current market conditions. The Company has provided for a liability to Den norske in the amount of $550,000 at December 31, 2000. Although the Loan Agreement expired in December 2000, the Company believes that it has, or can obtain, adequate capital to continue to meet its anticipated capital requirements. In the past, the Company's requirements have been financed by the disposition of certain assets, for example, interests in its pipelines, by borrowings under the Loan Agreement, private placements of its equity and debt securities, and investments by its directors. However, there can be no assurance that the Company will be able to continue to obtain financing from these sources or sell assets on commercially acceptable terms. The Company's inability to finance its capital requirements may adversely affect its results of operations, timing for major pipeline expansions, growth in oil and gas prospect generation activities, developmental midstream projects and other projects. RESULTS OF OPERATIONS For the year ended December 31, 2000, the Company reported a net loss of $10,135,120, compared to a net loss of $2,086,511 for the year ended December 31, 1999. The 2000 loss was due to the impairment of oil and gas properties recorded in 2000 of $10,754,976. For the year ended December 31, 1999, the Company reported a net loss of $2,086,511, compared to net loss of $9,059,979 reported for the year ended December 31, 1998, representing an improvement of $6,973,468. The improvement is primarily due to a non-cash impairment of oil and gas properties recorded 31 at December 31, 1998 of $8,952,785, net of income tax benefit, offset in part by a non-cash valuation allowance on deferred tax assets of $1,858,608 recorded at December 31, 1999. 2000 compared to 1999 REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Revenues from oil and gas sales increased by $4,952,037 in 2000, from those of 1999 due to the acquisition of American Resources in December 1999, resulting in additional revenues of $4,925,497 in 2000. In addition, oil and gas sales from the Buccaneer Field increased by approximately $205,000 due to a 86% increase in commodity prices from 1999 to 2000. However, Buccaneer Field production ceased in July 2000, due to downhole mechanical problems and subsequently the Buccaneer Field leases terminated in January 2001. REVENUE FROM PIPELINE OPERATIONS. Revenues from pipeline operations increased by $336,580 or 18% in 2000 to $2,212,296 from 1999. The increase was primarily due to an increase in gas volumes transported on the Black Marlin Pipeline System, which system was acquired on March 1, 1999, resulting in a $486,754 increase in pipeline revenues in 2000. During 2000, average daily gas volumes transported by the Black Marlin Pipeline System were 81,000 Mmbtu per day compared to 58,000 Mmbtu per day during the ten months the Company owned the system in 1999. This increase was offset in part by a decline in gas volumes on the Blue Dolphin Pipeline System. During 2000, average daily gas volumes transported by the Blue Dolphin Pipeline System were 30,000 Mmbtu per day compared to 38,000 Mmbtu per day during 1999, resulting in a reduction in pipeline revenues of $154,533. The reduction in pipeline revenue is partially attributable to a decrease in the Company's interest in the Blue Dolphin Pipeline System. On March 1, 1999, the Company sold a 1/6th interest in the Blue Dolphin Pipeline System, reducing its interest from 67% to 50%. LEASE OPERATING EXPENSES. Lease operating expenses for 2000 increased by $268,387 from 1999 due to the acquisition of American Resources in December 1999, resulting in additional lease operating expenses in 2000 of $661,243. The increase in expenses was offset by lower lease operating expenses in 2000 associated with the Buccaneer Field of $392,856. DEPLETION, DEPRECIATION AND AMORTIZATION EXPENSE. Depletion, depreciation and amortization for 2000 increased $1,401,624, primarily due to the acquisition of American Resources in December 1999, resulting in increased depletion of $1,484,584 in 2000. IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company recorded an impairment of oil and gas properties of $10,754,976, in 2000, comprised of a non-cash write-off of proved reserves from the Buccaneer Field of $5,354,976 and the recognition of associated plugging and abandonment costs estimated to be $5,400,000. INTEREST AND OTHER EXPENSE. In 2000, interest and other expense increased $523,256, due primarily to the recording of a $550,000 liability providing for the contingent payment associated with the acquisition of American Resources senior debt in December 1999 (see note 9 to the Company's Financial Statements). In addition the Company retired $1,811,555 principal amount of promissory notes in December 1999, resulting in a decrease in interest expense of $170,211. The decrease was offset in part by interest expense of $126,990 on the $1,000,000 convertible promissory note issued in December 1999, the $200,000 convertible promissory note issued in May 2000, the $200,000 convertible promissory note issued in July 2000 and the $600,000 convertible promissory note issued in November 2000. 1999 compared to 1998 32 REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Oil and gas sales and operating fees increased by $111,511 or 15% in 1999 to $881,340 from 1998. The acquisition of American Resources in December 1999 provided revenues of $307,195, partially offset by a reduction in Buccaneer Field revenues of $195,684 or 25%. Although commodity prices in general increased during 1999, gas sales from the Buccaneer Field were based on a fixed price of $2.08 per MMBtu through September 1999. Since October 1999, the price received for Buccaneer Field gas production has been based on the current monthly market price. REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by $913,228 or 33% in 1999 to $1,875,716 from 1998. The decrease was due to a decline in gas and oil volumes transported by the Blue Dolphin System of approximately $1,424,749, and the sale of a one-sixth interest in the Blue Dolphin System in March 1999, reducing revenues by $189,623, offset in part by the acquisition of the Black Marlin System in March 1999, which provided revenues of $701,144. LEASE OPERATING EXPENSES. Lease operating expenses increased by $254,450 or 30% in 1999 to $1,100,549 from 1998. The increase was due primarily to costs of approximately $187,738 associated with repairs made to the offshore platforms in the Buccaneer Field in 1999 and approximately $66,712 associated with the American Resources properties that were acquired in December 1999. PIPELINE OPERATING EXPENSES. Pipeline operating expenses increased $218,946 or 25% to $1,102,998 from 1998. The increase was due to the acquisition of the Black Marlin System in March 1999, adding expenses of $393,696 in 1999, offset in part by the sale of a one-sixth interest in the Blue Dolphin System in March 1999, reducing expenses by $108,205, and cost reductions from continuing operations of $66,545. DEPLETION, DEPRECIATION AND AMORTIZATION. Depletion, depreciation and amortization expense increased by $194,304 or 48% in 1999 to $595,286 from 1998. The increase was due to the acquisition of the Black Marlin System in March 1999, resulting in additional depreciation of approximately $199,017, and American Resources in December 1999, resulting in additional depletion of approximately $124,562. These increases were partially offset by a reduction in depletion due to lower production volumes from the Buccaneer Field of approximately $92,475, and the sale of a one-sixth interest in the Blue Dolphin System in March 1999, resulting in a $36,800 reduction in depreciation. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased $595,067 or 41% to $2,061,805 from 1998. The increase was primarily due to increased personnel costs associated with the Company's asset acquisitions during 1999. The Company expects to maintain this higher level of general and administrative expenses. GAIN ON SALE OF ASSETS. In March 1999, the Company reported a gain on the sale of a one-sixth interest in the Blue Dolphin System of approximately $2,052,920. INCOME TAX EXPENSE. In 1999 the Company recorded a valuation allowance of its deferred tax assets in accordance with SFAS No. 109 Accounting for Income Taxes, whereby the deferred tax asset of $2,103,052 was reduced to $244,444, resulting in an increase in income tax expense of $1,858,608. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), was issued in June 1998 by the Financial Accounting Standards Board. 33 SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk. Certain provisions of SFAS 133 were amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of Statement 133", SFAS 133, as amended, is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. SFAS 133, as amended, will not have a material effect on the Company's consolidated financial position or the results of operations. In March 2000, the FASB issued FASB Interpretation No. 44 "Accounting for Certain Transactions involving Stock Compensation - and interpretation of APB Opinion No. 25" ("FIN 44"). FIN 44 provides guidance on the accounting for certain stock option transactions and subsequent amendments to stock option transactions. FIN 44 is effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. To the extent that FIN 44 covers events occurring during the periods from December 15, 1998 and January 12, 2000, but before July 1, 2000, the effects of applying this interpretation are to be recognized on a prospective basis. FIN 44 did not have a material effect on the Company's consolidated financial position or the results of operations. In December 1999, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin No. 101, "Revenue Recognition" ("SAB 101"), which provides guidance on the recognition, presentation and disclosure of revenue in financial statements filed with the SEC. Subsequently, the SEC released SAB 101B, which delayed the implementation date of SAB 101 for registrants with fiscal years beginning between December 16, 1999 and March 15, 2000. SAB 101 did not have a material effect on the Company's consolidated financial position or the results of operations. In April 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities" ("SOP 98-5"). SOP 98-5 requires that costs of start-up activities be charged to expense as incurred and broadly defines such costs. The Company has capitalized certain costs incurred in connection with a new business segment, and SOP 98-5 requires that such costs be charged to results of operations upon its adoption. The Company adopted the requirements of SOP 98-5 as of January 1, 1999, resulting in a cumulative effect of a change in an accounting principle of $80,334, net of income tax benefit of $41,480. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risk, including adverse changes in commodity prices and interest rates as discussed below. COMMODITY PRICE RISK: The Company produces and sells gas, crude oil, and gas liquids. As a result, the Company's financial results can be significantly affected if these commodity prices fluctuate widely in response to changing market forces. Except as discussed below, the Company has not used derivative products in the past to manage commodity price risk. INTEREST RATE RISK: The Company currently has no short-term or long-term debt with floating interest rates and, is not subject to risk of interest rate changes. DERIVATIVES: In October 1999, American Resources sold call options for 5 Mmbtu's per day of gas at a call price of $3.25 per Mmbtu to H & N Gas. The call options expired in September 2000. In exchange for establishing a ceiling of $3.25 per Mmbtu over the option term, American Resources received an average option premium of approximately $0.12 per Mmbtu on the volumes contracted for under the 34 call option agreement. Fidelity Oil agreed to assume 80%, or 4 Mmbtu's per day, of any liability from these options. The call options were settled each month. The months of October 1999 through May 2000 expired with no liability to American Resources. The liability from the options for the months of June, July, August and September 2000, included settlement amounts of $147,900, $222,580, $79,515 and $215,250, respectively, of which Fidelity Oil has reimbursed American Resources $118,320, $178,064, $63,612 and $172,200, respectively. The Company had no derivative contracts in place as of December 31, 2000. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page ---- Index to Financial Statements: Independent Auditors' Report................................. 36 Consolidated Balance Sheets, at December 31, 2000 and 1999... 38 Consolidated Statements of Operations, for the years ended December 31, 2000, 1999, and 1998................. 40 Consolidated Statements of Stockholders' Equity, for the years ended December 31, 2000, 1999, and 1998........... 41 Consolidated Statements of Cash Flows, for the years ended December 31, 2000, 1999, and 1998................. 42 Notes to Consolidated Financial Statements................... 44 35 Independent Auditors' Report The Board of Directors Blue Dolphin Energy Company: We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the years in the three-year period ended December 31, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the consolidated financial statements of American Resources Offshore, Inc., a 77 percent owned subsidiary, which statements reflect total assets constituting 80 percent and total revenues constituting 66 percent in 2000 of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for American Resources Offshore, Inc., is based solely on the report of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated financial statements, effective January 1, 1999, the Company changed its method of accounting for costs of start-up activities. /s/ KPMG LLP Houston, Texas March 23, 2001 36 Independent Auditors' Report The Board of Directors and Shareholders American Resources Offshore, Inc. We have audited the consolidated balance sheets of American Resources Offshore, Inc. as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000 (not presented separately herein). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion of these consolidated financial statements based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of American Resources Offshore, Inc. as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ Ernst & Young LLP New Orleans, Louisiana February 23, 2001 37 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2000 and 1999

Assets 2000 1999 ------ ----------- ---------- Current assets: Cash and cash equivalents $ 2,071,682 1,166,730 Trade accounts receivable 2,406,751 1,542,328 Funds escrowed for abandonment 1,485,728 -- Prepaid expenses and other assets 127,913 318,139 ----------- ---------- Total current assets 6,092,074 3,027,197 ----------- ---------- Property and equipment, at cost: Oil and gas properties, including $430,782 and $950,813 of unproved leasehold cost at December 31, 2000 and 1999, respectively (full-cost method) 28,032,211 26,474,957 Onshore separation and handling facilities 1,583,610 1,583,610 Land 930,500 930,500 Pipelines 4,845,975 3,653,397 Other property and equipment 397,683 431,294 ----------- ---------- 35,789,979 33,073,758 Less accumulated depletion, depreciation, amortization and impairment 30,444,622 17,879,183 ----------- ---------- 5,345,357 15,194,575 Deferred federal income tax 244,444 244,444 Acquisition and development costs - Petroport 1,885,219 1,741,823 Funds escrowed for abandonment -- 1,168,564 Other assets 345,861 161,613 ----------- ---------- $13,912,955 21,538,216 =========== ==========

See accompanying notes to consolidated financial statements. (Continued) 38 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, CONTINUED December 31, 2000 and 1999

Liabilities and Stockholders' Equity 2000 1999 ------------------------------------ ---- ---- Current liabilities: Trade accounts payable and accrued expenses $ 2,235,493 1,347,944 Current portion of long term debt 218,412 319,045 Note payable - related party 2,000,000 1,000,000 Accrued expenses and other liabilities 249,704 266,977 ---------------- ---------------- Total current liabilities 4,703,609 2,933,966 ---------------- ---------------- Other non-current liabilities 550,000 -- Minority interest 1,196,479 958,521 Stockholders' equity: Common stock, $.01 par value, 10,000,000 shares authorized at December 31, 2000 and 1999, 6,016,718 shares issued and outstanding at December 31, 2000; 5,950,879 shares issued and outstanding at December 31, 1999 60,167 59,509 Additional paid-in capital 25,775,417 25,823,817 Accumulated (deficit) (18,372,717) (8,237,597) ---------------- ---------------- Total stockholders' equity 7,462,867 17,645,729 $ 13,912,955 21,538,216 ---------------- ----------------

See accompanying notes to consolidated financial statements. 39 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Years ended December 31, 2000, 1999 and 1998

2000 1999 1998 ------------ ---------- ----------- Revenue from operations: Oil and gas sales $ 5,519,140 567,103 412,753 Pipeline operations 2,212,296 1,875,716 2,788,944 Operating fees 210,534 314,237 357,076 ------------ ---------- ----------- Revenue from operations 7,941,970 2,757,056 3,558,773 ------------ ---------- ----------- Cost of operations: Lease operating expenses 1,368,936 1,100,549 846,099 Pipeline operating expenses 976,999 1,102,998 884,052 Impairment of oil and gas properties 10,754,976 -- 12,011,544 Depletion, depreciation and amortization 1,996,910 595,286 400,982 General and administrative expenses 2,093,840 2,061,805 1,466,738 ------------ ---------- ----------- Cost of operations 17,191,661 4,860,638 15,609,415 ------------ ---------- ----------- Loss from operations (9,249,691) (2,103,582) (12,050,642) Other income (expense): Interest and other expense (761,578) (238,322) (215,141) Gain on sale of assets -- 2,052,920 -- Interest and other income 114,107 80,722 105,994 ------------ ---------- ----------- Loss before income taxes (9,897,162) (208,262) (12,159,789) Minority interest (237,958) (882) -- Income tax benefit (expense) -- (1,797,033) 3,099,810 ------------ ---------- ----------- Loss before cumulative effect of a change in an accounting principle (10,135,120) (2,006,177) (9,059,979) Change in accounting principle (net of $41,480 income tax) -- (80,334) -- ------------ ---------- ----------- Net loss $(10,135,120) (2,086,511) (9,059,979) ============ ========== =========== Earnings per common share-basic and diluted Loss before accounting change $(1.70) (0.41) (2.02) Cumulative effect of a change in accounting principle -- (0.02) -- Net loss $(1.70) (0.43) (2.02) ============ ========== =========== Weighted average number of common shares outstanding: 5,963,318 4,837,504 4,492,344

See accompanying notes to consolidated financial statements. 40 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY Years ended December 31, 2000, 1999, and 1998

ADDITIONAL TOTAL COMMON PAID-IN ACCUMULATED STOCKHOLDERS' STOCK CAPITAL (DEFICIT) EQUITY ----- --------- ---------- ------------- Balance at December 31, 1997 44,918 17,669,515 2,908,894 20,623,327 ------- ---------- ----------- ----------- Exercise of 12,780 stock options 128 35,509 -- 35,637 Other -- (4,191) -- (4,191) Net loss -- -- (9,059,979) (9,059,979) ------- ---------- ----------- ----------- Balance at December 31, 1998 45,046 17,700,833 (6,151,085) 11,594,794 ------- ---------- ----------- ----------- Exercise of 32,004 stock options 320 115,073 -- 115,393 Cancellation of 14,470 shares of stock (145) (85,010) -- (85,155) Issuance of shares to 401K plan 200 59,800 -- 60,000 Private placements 10,939 6,159,980 -- 6,170,919 Notes and accrued interest tendered for stock 3,149 1,886,241 -- 1,889,390 Other -- (13,100) (1) (13,101) Net loss -- -- (2,086,511) (2,086,511) ------- ---------- ----------- ----------- Balance at December 31, 1999 $59,509 25,823,817 (8,237,597) 17,645,729 ------- ---------- ----------- ----------- Exercise of 33,665 stock options 336 109,843 -- 110,179 Issuance of shares to 401K plan 300 89,700 -- 90,000 Stock registration costs and other 22 (247,943) -- (247,921) Net loss (10,135,120) (10,135,120) ------- ---------- ----------- ----------- Balance at December 31, 2000 60,167 25,775,417 (18,372,717) 7,462,867 ======= ========== =========== ===========

See accompanying notes to consolidated financial statements. 41 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31, 2000, 1999, and 1998

2000 1999 1998 ------------ ----------- ---------- Operating activities: Net income (loss) $(10,135,120) (2,086,511) (9,059,979) Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 1,996,910 595,286 400,982 Minority interest 237,958 882 -- Deferred income taxes -- 1,765,616 (3,113,980) Change in accounting principle -- 121,814 -- Gain on sale of property and equipment -- (2,052,920) -- Impairment of oil and gas properties 10,754,976 -- 12,011,544 Increase in other non-current liabilities 550,000 -- -- Changes in operating assets and liabilities: (Increase) decrease in trade accounts receivable (864,423) (771,060) 90,472 (Increase) decrease in prepaid expenses and other assets 190,226 (298,298) (62,750) (Decrease) increase in trade accounts payable, accrued expenses and other liabilities 870,276 1,638,583 130,282 ---------- ----------- ---------- Net cash provided by (used in) operating activities 3,600,803 (1,086,608) 396,571 ---------- ----------- ---------- Investing activities: Oil and gas prospect generation costs -- (1,268,098) (737,868) Reimbursement of oil and gas prospect generation costs -- 1,292,125 Development costs - New Avoca (184,248) -- -- Exploration and development costs (1,620,564) -- (100,051) Purchases of property and equipment (1,269,924) (10,290,563) (354,821) Net proceeds from sale of assets -- 5,513,423 -- Acquisition and development costs - Petroport (155,576) (299,426) (822,086) Reduction of escrowed abandonment fund -- -- 593,830 Abandonment of oil and gas properties -- (344,698) -- Funds escrowed for abandonment costs (317,164) (60,991) (369,806) ---------- ----------- ---------- Net cash used in investing activities (3,547,476) (5,458,228) (1,790,802) ---------- ----------- ----------

See accompanying notes to consolidated financial statements. 42 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS, CONTINUED Years ended December 31, 2000, 1999, and 1998

2000 1999 1998 ---------- --------- --------- Financing activities: Proceeds from borrowings, Bank -- 200,000 200,000 Proceeds from borrowings, Director 1,000,000 1,000,000 Payments on borrowings (100,633) (330,000) -- Payments of offering costs and other (247,921) -- -- Net proceeds from private placement -- 6,170,919 Net proceeds from the issuance of stock and the exercise of stock options 200,179 77,138 31,446 ---------- --------- ---------- Net cash provided by financing activities 851,625 7,118,057 231,446 ---------- --------- ---------- Increase (decrease) in cash 904,952 573,221 (1,162,785) Cash and cash equivalents at beginning of year 1,166,730 593,509 1,756,294 ---------- --------- ---------- Cash and cash equivalents at end of year $2,071,682 1,166,730 593,509 ========== ========= ========== Supplementary cash flow information: Interest paid $ 86,316 326,819 214,926 ========== ========= ========== Income taxes (received) paid $ 8,498 12,620 (93,264) ========== ========= ==========

NON-CASH TRANSACTIONS: During 1999, holders of $1,811,555 of notes payable along with accrued interest of $77,835 converted the notes payable into 314,898 shares of Common Stock. See accompanying notes to consolidated financial statements. 43 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2000, 1999 and 1998 (1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION Blue Dolphin Energy Company (the Company) was incorporated in Delaware in January 1986 to engage in oil and gas exploration, production and acquisition activities and oil and gas transportation and marketing. It was formed pursuant to a reorganization effective June 9, 1986. PRINCIPLES OF CONSOLIDATION The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and majority owned subsidiary (American Resources). All significant intercompany balances and transactions have been eliminated in consolidation. ACCOUNTING ESTIMATES Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and to the disclosure of contingent assets and liabilities including reserve information which affects the depletion calculation as well as the computation of the full cost ceiling limitation to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. CASH EQUIVALENTS Cash equivalents include liquid investments with an original maturity of three months or less. OIL AND GAS PROPERTIES Oil and gas properties are accounted for using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a country-by-country cost center basis. Due to the difference in the expected life of the reserves of the properties, the Company uses two separate cost centers, one for its Buccaneer Field property and one for its other properties. With the write off of the Buccaneer Field during the year ended December 31, 2000, the Company is now utilizing one cost center for all of its properties. Amortization of such costs and estimated future development costs are determined using the unit- of- (Continued) 44 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS production method. Provision for the estimated costs of offshore platform and well abandonment, net of salvage value, is computed on the units of production method and is included in depletion, depreciation and amortization. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred. Estimated proved oil and gas reserves are based upon reports of independent petroleum engineers. The net carrying value of oil and gas properties, less related deferred income taxes, is limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% discount rate applied) of estimated future net revenues from proved reserves, after giving effect to income taxes, and the lower of cost or estimated fair value of unproved properties. Disposition of oil and gas properties are recorded as adjustments to capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The following table reflects the depletion expense incurred from oil and gas properties during the periods indicated: Year Ended December 31, ------------------------ 2000 1999 1998 ---- ---- ---- Depletion expense per Mcf equivalent produced $1.18 $0.83 $0.77 ===== ===== ===== At December 31, 2000, oil and gas properties included $430,782 of unproved leasehold costs that are not being amortized. These costs will begin to be amortized when they are evaluated and proved reserves are discovered, impairment is indicated or when the lease term expires. Unproved leasehold costs consist of interests in state and federal leases located in the Gulf of Mexico with expiration dates ranging from January 2001 to November 2004. In order to retain the leases after the primary term, they must be producing or development operations must be in progress. The leases have primary terms of 5 years. Development of these leases is dependent upon the other owners of the leases to initiate a plan of development. The following table reflects the periods when costs were incurred for unproved leasehold costs:

Year Ended December 31, -------------------------------------------- Total 2000 1999 1998 -------- -------- ------- -------- Property acquisition costs $280,438 - 280,438 - Exploration costs 150,344 - 57,632 92,712 -------- ------- ------- ------ $430,782 - 338,070 92,712 ======== ======= ======= ======

(Continued) 45 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Company capitalizes interest on expenditures made in connection with significant exploration and production projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest has been capitalized for the periods reflected herein. PIPELINES AND FACILITIES Pipelines and facilities are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives of 10-25 years. Provision for the estimated cost of pipeline and facilities abandonment, net of salvage value, is computed on a straight line basis over the estimated useful life of such assets and is included in DD&A. The Company in 1995 adopted Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of, with no impact to the Company's consolidated financial statements. Assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom. OTHER PROPERTY AND EQUIPMENT Depreciation of furniture, fixtures and other equipment, including assets held under capital leases, is computed using the straight-line method over estimated useful lives of 2-5 years. ABANDONMENT A provision for the abandonment, dismantlement and site remediation of offshore production platforms and existing wells is made using the unit-of- production method applied to estimates based on current costs. A provision for pipeline and pipeline facilities abandonment costs is also provided using the straight-line method over the estimated useful lives of the pipeline and pipeline facilities. These provisions are included in accumulated depletion, depreciation, amortization and impairment, and are undiscounted. Aggregate abandonment liability was estimated to be approximately $5,900,000 at December 31, 2000. NEW AVOCA AND DRILLMAR The Company records its investment in New Avoca and Drillmar using the equity method of accounting. Under the equity method, investments are recorded at cost plus the Company's equity in undistributed earnings and losses after acquisition. (Continued) 46 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS STOCK-BASED COMPENSATION The Company applies SFAS No. 123, Accounting for Stock-Based Compensation, which allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. The Company has chosen to continue to account for stock-based compensation under the intrinsic value method and provides the pro forma effects of the fair value method as required. RECOGNITION OF OIL AND GAS REVENUE Sales from producing wells are recognized on the entitlement method of accounting which defers recognition of sales when, and to the extent that, deliveries to customers exceed the Company's net revenue interest in production. Similarly, when deliveries are below the Company's net revenue interest in production, sales are recorded to reflect the full net revenue interest. The Company's imbalance liability at December 31, 2000 and 1999 was not material. RECOGNITION OF PIPELINE TRANSPORTATION REVENUE Revenue from the transportation of gas, condensate and crude oil is recognized on the accrual basis as products are transported. OPERATION OF OIL AND GAS PROPERTIES Until December 2000, the Company operated, for a monthly fee, oil and gas properties in which it did not own an interest. Revenues and costs from these activities are included in operating fees and lease operating expenses, respectively. Operating fees received related to properties in which the Company owns an interest are netted against the appropriate operating costs in the Statement of Operations. Fees received in excess of costs incurred are reflected as a reduction of the full cost pool. INCOME TAXES The Company provides for income taxes using the asset and liability method pursuant to SFAS No. 109, Accounting for Income Taxes ("Statement 109"). Under the asset and liability method of Statement 109, deferred tax assets and liabilities are recognized for the (Continue) 47 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. EARNINGS PER SHARE The Company follows SFAS No. 128 ("Statement 128"), Earnings per Share, for computing and presenting earnings per share and requires, among other things, dual presentation of basic and diluted earnings per share on the face of the statement of operations. The employee stock options at December 31, 2000, 1999 and 1998, were not included in the computation of diluted earnings per share because the effect of their assumed exercise and conversion would have an antidilutive effect on the computation of diluted loss per share. The following unaudited pro forma information for the years ended December 31, 1999 and 1998, presents a summary of consolidated results of operations as if the acquisition of the 75% ownership interest in American Resources made in 1999 had occurred on January 1, 1998, with pro forma adjustments to give effect to depreciation and certain other adjustments together with related income tax effects Year Ended December 31, -------------- 1999 1998 ---- ---- Revenues $ 5,726,056 $ 8,995,773 Net Earnings $(2,257,225) $(7,905,549) Basic and diluted earnings per share $ (0.47) $ (1.76) The above pro forma information is not necessarily indicative of the results of operations as they would have been had the acquisition been effected on January 1, 1998. ENVIRONMENTAL The Company is subject to extensive Federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. (Continued) 48 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. COSTS OF START-UP ACTIVITIES In April 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5 requires that costs of start-up activities be charged to expense as incurred and broadly defines such costs. The Company deferred certain costs incurred in connection with a new business segment, and SOP 98-5 requires that such deferred costs be charged to results of operations upon its adoption. The Company adopted the requirements of SOP 98-5 on January 1, 1999. The cumulative effect of the change in accounting principle for the adoption of SOP 98-5 resulted in a charge to results of operations in the financial statements for the year ended December 31, 1999 of $80,334, net of $41,480 of income taxes. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), was issued in June 1998 by the Financial Accounting Standards Board. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk. Certain provisions of SFAS 133 were amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an Amendment of Statement 133", SFAS 133, as amended, is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The adoption of SFAS 133 will not have a material effect on the Company's consolidated financial position or the results of operations. (2) FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying values of cash and cash equivalents, receivables and accounts payable approximate fair value due to the short-term maturities of these instruments. The carrying value of the notes payable approximates fair value at December 31, 2000 and 1999. (Continued) 49 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (3) INCOME TAXES Income tax expense (benefit) for 2000, 1999 and 1998 consists of: 2000 1999 1998 ---- ---- ---- Current: Federal $ -- -- -- State -- -- 14,170 Deferred - Federal -- 1,797,033 (3,113,980) ----- --------- ---------- $ -- 1,797,033 (3,099,810) ===== ========= ========== The income tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2000 and 1999 are presented below. 2000 1999 ---- ---- Deferred tax assets: Net operating loss carryforwards 10,315,000 9,800,517 Alternative minimum tax credit 244,444 244,444 Basis differences in property and equipment 2,720,000 1,562,100 ----------- ------------ Total gross deferred tax assets 13,279,444 11,607,061 Deferred tax liabilities-state tax (34,000) (34,009) ----------- ------------ Net deferred tax asset 13,245,444 11,573,052 Less valuation allowance (13,001,000) (11,328,608) ----------- ------------ Deferred tax asset $ 244,444 $ 244,444 In 1999, the Company acquired American Resources, which had deferred tax assets of approximately $8.5 million made up of basis differences in oil and gas properties and net operating losses. A full valuation allowance was recorded to reduce the corresponding deferred assets, since it is more likely than not that they will not be realized, due to the limitation of the use of the net operating loss carryforwards resulting from the ownership change in December 1999. In assessing the realizability of deferred tax assets, the Company applies SFAS No. 109 to determine whether it is more likely than not that some portion or all of the deferred tax (Continued) 50 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS assets will not be realized. As a result, the Company recorded a valuation allowance at December 31, 1999 to reduce the deferred tax asset to $244,444. The Company's effective tax rate applicable to continuing operations in 2000, 1999, and 1998 differs from the expected tax rate of 34% due to the following: 2000 1999 1998 ---- ---- ---- Expected tax rate (34%) (34%) (34%) State taxes, net of federal benefit -- -- -- Expenses not deductible for tax purposes -- 2% -- Increase in valuation allowance recognized in earnings 34% 893% 8% Other -- 2% -- ---- ----- ---- 0% 863% (26%) ==== ===== ==== For federal tax purposes, the company had a net operating loss carryforwards ("NOL") of approximately $28.3 million, $28.8 million and $7.9 million for the years ended December 31, 2000, 1999 and 1998. These NOLs must be utilized prior to their expiration, which is between 2001 and 2020. Of the $28.3 million of NOLs for the year ended December 31, 2000, $17.2 million relate to American Resources. The Company has an alternative minimum tax credit carry forward of $244,444 that does not expire and may be applied to reduce regular tax to an amount not less than the alternative minimum tax payable in any one year. (4) LONG-TERM DEBT The Company's reducing revolving credit facility (Loan Agreement) with Bank One, Texas, N.A., in an amount of $10,000,000 expired December 31, 2000. Borrowings under the Loan Agreement were secured by first liens on the Buccaneer Field, the Blue Dolphin Pipeline, the Buccaneer Pipeline, the Freeport, Texas acreage, the Shore Facilities and the Black Marlin Pipeline. In December 1996, the Company issued $2,050,600 in promissory notes to the holders of the Preferred Stock as full payment of the cumulative preferred stock dividends. The promissory notes were unsecured and bore interest at the rate of 10.25% per annum. Interest only was payable semi-annually with the principal due on December 31, 2000. On December 1, 1999, the holders of promissory notes totaling $1,811,555 tendered their promissory notes, along with accrued interest of $77,835 for common stock pursuant to the Company's private placement of shares. Additionally, the Company retired $20,634 principal amount of promissory notes in January 2000. The Company retired the remaining $218,412 principal amount of promissory notes in January 2001. (Continued) 51 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On December 1, 1999, the Company issued a $1,000,000 promissory note to a director of the Company. The note was due June 1, 2000, bore interest at 10% per annum, and was convertible into common stock at $6.60 per share. The due date of the note was subsequently extended to March 31, 2001 and is convertible into common stock at $6.00 per share. This note and accrued interest were paid in full in January 2001. The Company issued three convertible promissory notes in the principal amounts of $200,000, $200,000 and $600,000, on May 25, 2000, July 6, 2000, and November 30, 2000, respectively. The notes were issued to a director of the Company. These convertible promissory notes were due March 31, 2001, bore interest at the rate of 10% per annum and were convertible into common stock at the rate of $6.00 per share. These notes and accrued interest were paid in full in January 2001. Long-term debt at December 31, 2000 and 1999 is as follows: December 31, ----------------- 2000 1999 ---- ---- Note payables - directors, interest at 10% per annum, principal due March 31, 2001, convertible into common stock at $6.00 per share. $2,000,000 $1,000,000 $10,000,000 bank credit facility, $80,000 borrowing base, interest payable monthly at prime rate (8. 5% at December 31, 1999) plus 1.25%. Borrowing availability and reducing base amount were redetermined semiannually. - $ 80,000 Notes payable, interest at 10.25% per annum payable semi-annually, principal due December 31, 2000. 218,412 239,045 ---------- ---------- 2,218,412 1,319,045 Less current maturities, including note payable-related party 2,218,412 1,319,045 ---------- ---------- $ -- $ -- ========== ========== (5) STOCKHOLDERS' EQUITY In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its' common stock, $.01 par value per share, at $5.00 per share. The proceeds were used to replenish working capital previously used for planned investments in longer term, high potential projects and for general working capital. (Continued) 52 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In order to provide funding for the acquisition of American Resources in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively and a $1,000,000 convertible promissory note, see notes 4 and 7. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately $4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999. In 2000, the Company incurred costs totaling $263,458 associated with the registration of shares of common stock, $.01 par per share. In addition the Company issued 2,785 shares of its common stock as a severance payment to a former employee and recorded compensation expense of $15,537. (5) STOCK OPTIONS Effective April 14, 2000, the Company adopted a stock incentive plan (the "2000 Plan"). The stock subject to the options and other provisions of the 2000 Plan are shares of the Company's common stock $.01 par value (the "Stock"). No more than 500,000 shares of Stock will be available for incentive stock options ("ISOs"). The 2000 Plan is administered by the Compensation Committee of the Board of Directors. Options granted must be exercised within 10 years from their grant date. The exercise price of ISOs can not be less than 100% of the fair market value of a share of Stock. The 2000 Plan also provides for the granting of other incentive awards, however only ISOs and non-statutory stock options have been issued under the 2000 Plan. The Company adopted a stock option plan in 1996 (the "1996 Plan"). The stock subject to the options and other provisions of the 1996 Plan are shares of the Company's common stock. The total amount of the common stock with respect to which options may be granted shall not exceed in the aggregate 10% of the number of issued and outstanding shares of Common Stock of the Company. The stock options become exercisable from time to time in part or as a whole, as the Compensation Committee (the Committee), appointed by the Board of Directors, or the Board of Directors in their discretion may provide. However, the Committee shall not grant options which may become exercisable in any one calendar year to purchase more than one-third of the maximum amount granted. All options expire five years after the date of grant. The price of options granted may not be less than eighty-five percent of the fair market value of the common stock on the date the option is granted. Optionees must continue their association with the Company for six months after exercising the options, or the underlying stock reverts to the Company. As of December 31, 2000, all options granted pursuant to the Company's 1985 stock option plan were either exercised or expired. At December 31, 2000 the Company has reserved a total of 151,236 shares of common stock (Continued) 53 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for issuance under the above mentioned stock option plans. The outstanding stock options granted to key employees, officers and directors, for the purchase of shares of the Company's common stock, are as follows: Exercise price per share --------------- Shares From To ------ ---- -- Balance, December 31, 1998 151,231 2.789 4.383 ------- ----- ----- Granted 72,100 3.125 5.000 Expired (14,223) 4.383 2.789 Exercised (32,004) 2.789 4.383 ------- ----- ----- Balance, December 31, 1999 177,104 2.789 5.000 ======= ===== ===== Granted 55,300 6.000 6.000 Expired (47,503) 2.789 6.000 Exercised (33,665) 2.789 3.984 ------- ----- ----- Balance, December 31, 2000 151,236 2.789 6.000 ======= ===== ===== The weighted average exercise price per share was $3.365 and $3.606 in 2000 and 1999, respectively. As of December 31, 2000, options for 103,391 shares of common stock were immediately exercisable. There were 55,300 options granted in 2000. Pursuant to the requirements of FASB No. 123, the weighted average fair market value of options granted during 2000 and 1999 are $1.30 per share and $1.57 per share, respectively. The weighted average closing bid prices for the Company's stock at the date the options were granted during 2000 and 1999 are $5.25 and $3.34, respectively. The fair market value pursuant to FASB No. 123 of each option granted is estimated on the date of grant using the Black-Scholes options-pricing model. The model assumed expected volatility of 70% and 61% and risk-free interest rates of 6.39% and 3.75% for grants in 2000 and 1999, respectively and an expected life of 1 and 3 years respectively. As the Company has not declared dividends since it became a public entity, no dividend yield was used. Actual value realized, if any, is dependent on the future performance of the Company's common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Black-Scholes model. As discussed in Note 1, no compensation expense has been recorded in 2000, 1999, and 1998 for stock options granted. Had compensation cost for the Company's stock option plans been determined based on the fair market value at the grant dates for awards made after December 31, 1996 under those plans, the Company's net income (loss) and earnings (loss) per share would have been reduced to the pro forma amounts indicated below: (Continued) 54 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Year ended December 31, ----------------------- 2000 1999 1998 ------------- -------------- ------------- Net (loss) as reported $(10,135,120) $(2,086,511) $(9,059,979) Pro Forma $(10,271,293) $(2,190,033) $(9,172,801) Basic and diluted (loss) Per share as reported (1.70) (0.43) (2.02) Pro Forma (1.72) (0.45) (2.04) Outstanding options at December 31, 2000 expire between August 18, 2000 and January 14, 2004. Under the provisions of SFAS No. 123, the pro forma disclosures above include only the effects of stock options granted by the Company subsequent to December 31, 1994. During this initial phase-in period, the pro forma disclosures as required by SFAS No. 123 are not representative of the effects on reported net income for future years as options vest over several years and additional awards are generally made each year and there is a risk of forfeiture. (6) RELATED PARTY TRANSACTIONS Related party transactions which are not disclosed elsewhere in these consolidated financial statements are discussed in the following paragraph. In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its common stock, $.01 par value per share, at $5.00 per share. A director of the Company participated in the private placement, purchasing 100,000 shares. In order to provide funding for the acquisition of American Resources in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately $4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999. Three directors of the Company participated in this private placement; one director paid $100,002 for 16,667 shares and tendered a note in the amount of $95,761 plus accrued (Continued) 55 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS interest of $4,114 and cash of $325 for 16,700 shares, another director tendered a note in the amount of $179,921 plus accrued interest of $7,730 and cash of $149 for 31,300 shares and a third director tendered a note in the amount of $26,769 plus accrued interest of $1,150 and cash of $281 for 4,700 shares. In late 2000, the Company formed Drillmar, Inc., 37.5% owned by the Company. Drillmar acquired a 1% general partner interest in Zephyr Drilling, Ltd. At December 31, 2000, Drillmar's investment in Zephyr was $86,000. Harris A. Kaffie, director of the Company, and Ivar Siem, Chairman of the Company, are limited partners in Zephyr owning 37.5% and 37.1% interests, respectively. In 1992, the Company entered into a contract with a company, in which a director of the Company is a principal, for business development consulting services. The Company paid $71,250 under the contract in 1998. The contract was terminated October 15, 1998. (7) LEASES The Company has various noncancelable operating leases which continue through 2006. The following is a schedule of future minimum lease payments required under noncancelable operating leases at December 31, 2000: Years ending December 31, ------------ 2001 $ 198,548 2002 186,498 2003 185,521 2004 195,617 2005 195,617 Thereafter 195,617 ---------- $1,157,418 ========== Rental expense under operating leases for the years indicated are as follows: Years ended December 31, ------------ 2000 $190,211 1999 136,310 1998 119,490 (8) COMMITMENTS AND CONTINGENCIES As a result of the decision to cease operating activities in the Buccaneer Field, the (Continued) 56 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Company's leases in or on the Buccaneer Field terminated in January 2001. The Company must plug and abandon all remaining wells and remove platform facilities within one year from the termination of the leases. In the first quarter of 2001, the Company removed its remaining wells at a cost of approximately $1.1 million. Removal of the platform facilities is expected to take place in the second half of 2001 at a cost estimated to be $4.3 million. The Company has $1.5 million in funds escrowed to pay for some of these costs. In December 1999, American Resources received approximately $4.5 million from Blue Dolphin Exploration for American Resources common stock representing a 75% ownership interest and $24.2 million from Fidelity Oil for an 80% interest in its Gulf of Mexico assets. American Resources senior secured debt was held by Den norske bank ("Den norske"). Den norske sold the senior debt to the Company for the right to receive a possible future payment if the cumulative net revenues received by American Resources and Fidelity Oil attributable to American Resources proved oil and gas reserves in the Gulf of Mexico as of January 1, 1999, exceed $30.0 million during the period January 1, 1999, through December 31, 2001. If that occurs, Den norske will be entitled to receive an amount equal to 50% of those net revenues in excess of $30.0 million during that three-year period. If any contingent amount becomes payable to Den norske, 80% of it will be paid by Fidelity Oil and 20% of it will be paid by American Resources. The payment, if any, is due on March 15, 2002. American Resources now estimates that it is probable that a payment to Den norske will be due based upon these terms and current market conditions. The Company has provided for a liability to Den norske in the amount of $550,000 at December 31, 2000. The Company is involved in various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material effect on the Company's financial position, results of operations or cash flows. On May 8, 2000, American Resources, a 77% owned subsidiary of the Company, and its former Chief Financial Officer, were named in a lawsuit in the United States District Court for the Southern District of Texas, Houston Division, styled H&N Gas and Howard Energy Marketing, L.L.C. v. American Resources Offshore, Inc. et al (Case No H-00-1371). The lawsuit alleges, among other things, that H&N Gas ("H&N") was defrauded by American Resources in connection with gas purchase options and gas price swap contracts entered into from February 1998 through September 1999. H&N alleges unlawful collusion between American Resources' prior management and the then president of H&N, Richard Hale ("Hale"), to the detriment of H&N. H&N generally alleges that Hale directed H&N to purchase illusory options from American Resources that bore no relation to any physical gas business and that American Resources did not have the financial resources and/or sufficient quantity of gas to perform. H&N further alleges that American Resources and Hale colluded with respect to swap transactions that were designed to benefit American Resources at the expense of H&N. H&N further alleges civil conspiracy against all the defendants. H&N is seeking approximately $6.2 million in actual damages plus treble damages, punitive damages, prejudgment interest and attorneys' fees against American Resources directly. As a result of its conspiracy allegation, H&N also contends that all defendants are jointly and severally (Continued) 57 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS liable for over $62.0 million dollars in actual damages plus treble damages, punitive damages, prejudgment interest and attorneys' fees. American Resources intends to vigorously defend this claim. (10) BUSINESS SEGMENT INFORMATION The Company's income producing operations are conducted in two principal business segments: oil and gas exploration and production which includes upstream projects, and pipeline operations, which includes mid stream projects. Intersegment revenues consist of transportation, general processing and storage fees charged by certain subsidiaries to another for gas and crude oil transported through the Blue Dolphin Pipeline System. The intercompany revenues and expenses are eliminated in consolidation. Information concerning these segments for the years ended December 31, 2000, 1999, and 1998 is as follows

Operating Depletion, Intersegment income Identifiable depreciation and Revenues revenues (loss)(1) assets amortization(2) ------------ ------------- ------------ ------------- ---------------- Year ended December 31, 2000: Oil and gas exploration and production and operating fees $ 5,735,674 6,000 (8,577,943) 4,164,299 12,292,574 Pipeline operations 2,225,312 13,016 625,486 8,958,876 369,824 Other (19,016) (1,297,234) 789,780 89,488 ----------- ---------- ---------- ---------- Consolidated 7,941,970 - (9,249,691) 13,912,955 12,751,886 Other expense (647,471) ---------- Loss before income taxes (9,897,162) Year ended December 31, 1999: Oil and gas exploration and production and operating fees $ 887,340 6,000 (892,032) 12,816,861 212,441 Pipeline operations 1,889,837 14,121 (551,339) 7,735,149 345,600 Other (20,121) (660,211) 986,206 37,245 ----------- ---------- ---------- ---------- Consolidated 2,757,056 - (2,103,582) 21,538,216 595,286 Other income 1,895,320 ---------- Loss before income taxes (208,262) Year ended December 31, 1998: Oil and gas exploration and production operating fees $ 777,829 8,000 (12,448,875) 6,869,682 179,384 Pipeline operations 2,818,921 29,976 739,610 5,912,550 193,086 Other (37,976) (341,377) 2,084,984 28,512 ----------- ----------- ---------- ---------- Consolidated 3,558,774 - (12,050,642) 14,867,216 400,982 Other expense (109,147) ----------- Loss before income taxes (12,159,789)

(Continued) 58 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Consolidated income from operations includes $1,188,721, $602,845, and $564,584 in unallocated general and administrative expenses, and unallocated depletion, depreciation and amortization of $89,488, $37,245, and $28,512 for the years ended December 31, 2000, 1999 and 1998, respectively. (2) Pipeline depletion, depreciation and amortization includes a provision for pipeline abandonment of $19,740, $20,840, and $26,340, for the years ended December 31, 2000, 1999 and 1998, respectfully. Oil and gas depletion, depreciation and amortization includes a provision for abandonment costs of platforms and wells of $13,793, $17,656, and $30,378 for the years ended December 31, 2000, 1999 and 1998, respectively. See the supplemental disclosures for oil and gas producing activities for discussion of capitalized costs incurred for oil and gas production operations. Capital expenditures of $1,282,104 were incurred for pipeline operations for the year ended December 31, 2000. Capitalized expenditures of $143,396 were incurred for mid stream projects for the year ended December 31, 2000. The Company's primary market area is the Texas and Louisiana Gulf Coast region of the United States. The Company has a concentration of credit risk with customers in the energy and petrochemical industries. The Company's customers may be similarly affected by changes in economic, regulatory or other factors. Trade receivables are generally not collateralized; however, the Company's customers' historical and future credit positions are thoroughly analyzed prior to extending credit. Revenues from major customers exceeding 10% of segment revenues were as follows for the periods indicated. In 2000, no customer accounted for more than 10% of the Company's total revenues. Oil and Gas sales and Pipeline operating fees operations Total -------------- ---------- ----- Year ended December 31, 1999: Apache Corporation $ 295,525 723,437 1,018,962 The Dow Chemical Company 227,778 22,512 250,290 Year ended December 31, 1998: Apache Corporation $ 333,787 1,504,375 1,838,162 The Dow Chemical Company 391,913 46,119 438,032 Burlington Resources -- 429,186 429,186 (Continued) 59 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (11) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED The following supplemental information regarding the oil and gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission ("SEC") and SFAS No. 69 Disclosures About Oil and Gas Producing Activities (`Statement 69"). Proved reserves previously reported at December 31, 1999 were revised to eliminate proved undeveloped reserves attributable to the Buccaneer Field, before income taxes. This revision eliminated 76,074 barrels of oil and 13,123,893 Mcf of gas, thereby decreasing the standardized measure of discounted future net cash inflow by $1,234,601. In November 2000, the Company decided to abandon the Buccaneer Field as a result of the occurrence of unforeseen adverse events. In July 2000, production from the only producing well in the Buccaneer Field, the A-12 well, ceased due to down-hole mechanical problems. Due to the age of the wellbore of this well, it is probable that a new well would be needed to restore production at the Buccaneer Field, at an estimated cost of $2.8 million. In addition, in October 2000, during the annual inspection by the U.S. Minerals Management Service ("MMS") of the two major platform complexes in the Buccaneer Field, the MMS notified the Company that certain repairs to the platforms would be required before the Company could resume operating activities. The Company estimated the cost of these required, unplanned repairs to be in excess of $1.0 million. However, the Company believes that if it elected to resume production from the Buccaneer Field the actual costs would have been approximately $2.6 million, including an estimated $600,000 to repair one of the platform complexes. Thus, the total cost to reestablish production would have increased to an estimated $5.4 million, consisting of $2.6 million in front-end infrastructure costs and $2.8 million in drilling costs. After considering the costs associated with drilling a new well to reestablish production, together with the unplanned cost of repairs to the platforms and the projected rate of production and discounted cash flow from the field, the Company decided to abandon and not reestablish production from the Buccaneer Field. As a result of this decision, the leases on the field terminated in January 2001 pursuant to their terms. In connection with the Blue Dolphin Exploration's acquisition of American Resources in December 1999, Blue Dolphin Exploration arranged for Fidelity Oil to acquire an 80% interest in American Resources oil and gas assets located in the Gulf of Mexico for approximately $24.2 million. For the right to participate in the acquisition of these assets, Fidelity Oil has agreed to assign Blue Dolphin Exploration 10% of its working interest in the proved properties acquired from American Resources after it has recovered its investment in these properties. In addition, Fidelity Oil has agreed to assign Blue Dolphin Exploration 15% of its interest in each property after Fidelity has recovered its investment (Continued) 60 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS in exploratory properties on a property by property basis. The Company expects that payout of the proved properties will be achieved in late 2001. The following table summarizes the estimates of Proved Reserves, Proved Developed Reserves, and Proved Undeveloped Reserves (as hereinafter defined), future net revenues and the discounted present value of future net revenues from Proved Reserves before income taxes to the net interest the Company expects to receive from Fidelity Oil from proved properties acquired from American Resources as of December 31, 2000, using the SEC Method (defined below):

Net Oil Net Gas Future Discounted Future Reserves Reserves Net Revenues Net Revenues (Mbbls) (Mmcf) (in thousands) (in thousands) ----------- ----------- ------------ ------------- Total Proved Reserves 65.9 1,025 $10,756 $7,972 Total Proved Developed Reserves 65.0 884 $ 9,586 $6,988 Total Proved Undeveloped Reserves 0.9 141 $ 1,170 $ 984

(1) The estimated future net revenues before deductions for income taxes from the Company's Proved Reserves have been determined and discounted at a 10% annual rate in accordance with requirements for reporting oil and gas reserves pursuant the SEC Method. These reserves are excluded from the estimated quantities of proved oil and gas reserves and the standardized measure of discounted future net cash flows shown below. These reserve estimates were prepared based on oil and gas prices in effect at year end, which were $25.45 per Bbl of oil and $9.91 per Mcf of gas at December 31, 2000. Gas prices subsequently have declined substantially since year end. At February 28, 2001, the Company was receiving average gas prices of approximately $5.68 per Mcf. The decrease in gas prices will require Fidelity to sell more oil and gas reserves before its investment is recovered and Blue Dolphin Exploration is assigned this interest. The timing and amount of estimated future development costs may significantly increase or decrease the Company's total proved and proved developed reserve volumes, the Standardized Measure of Discounted Future Net Cash Flows, and the components and changes therein. These reserves and future net revenues reflect capital expenditures totaling $18,606, $79,201, $20,372, $51,200 and $71,839 in the years ending December 31, 2001, 2002, 2003, 2004 and 2005, respectively. (Continued) 61 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES Set forth below is a summary of the changes in the estimated quantities of the Company's crude oil and condensate, and gas reserves for the periods indicated, as estimated by Ryder Scott Company as of December 31, 2000. All of the Company's reserves are located within the United States. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions. Proved reserves are estimated quantities of gas, crude oil, and condensate which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Oil Gas Quantity of Oil and Gas Reserves (Bbls) (Mcf) -------------------------------- -------- ------- Total proved reserves at December 31, 1996 193,802 32,715,044 ------- ---------- Revisions to previous estimates (8,500) (1,125,504) Production (1,156) (176,986) ------- ---------- Total proved reserves at December 31, 1997 184,146 31,412,554 ------- ---------- Revisions to previous estimates 6,743 (40,387) Production (1,628) (177,260) ------- ---------- Total proved reserves at December 31, 1998 189,261 31,194,907 ------- ---------- Acquisitions 150,012 4,419,130 Revisions to previous estimates (76,711) (13,226,766) Production (6,338) (169,329) ------- ---------- Total proved reserves at December 31, 1999 256,224 22,217,942 ------- ---------- Revisions to previous estimates (10,175) (18,507,271) New discoveries and extensions 3,793 1,868,000 Production (64,707) (911,671) ------- ---------- Total proved reserves at December 31, 2000 185,135 4,667,000 ======= ========== (Continued) 62 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Proved developed reserves: December 31, 2000 182,106 3,134,000 December 31, 1999 205,525 20,400,120 December 31, 1998 113,183 18,070,961 CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES The following table sets forth the aggregate amounts of capitalized costs relating to the Company's oil and gas producing activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated: December 31, 2000 1999 Unproved properties and prospect generation costs not being amortized $ 430,782 $ 950,813 Proved properties being amortized 27,601,429 25,524,144 Less accumulated depletion, depreciation, amortization and impairment (28,408,166) (16,129,385) ------------ ------------ Net capitalized costs $ (375,955) $ 10,345,572 ============ ============ During 2000, the Company recorded an impairment charge on its oil and gas properties of $10,754,976. The impairment was comprised of a non-cash write-off of proved reserves from the Buccaneer Field of $5.4 million and the recognition of associated plugging and abandonment costs estimated to be $5.4 million. At December 31, 1998 the Company recorded an impairment charge on its oil and gas properties and certain exploration activity costs of $12,011,544, resulting from lower oil and gas prices and changes to its development plans, whereby development of oil and gas properties have been deferred. COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES The following table reflects the costs incurred in oil and gas property acquisition, exploration and development activities during the periods indicated: (Continued) 63 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, --------------------------- 2000 1999 1998 ---- ---- ---- Property acquisition costs $ 4,538,939 -- Exploration costs 1,620,564 57,632 277,501 Development costs -- -- -- ---------- --------- ------- $1,620,564 4,596,571 277,501 ========== ========= ======= STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The following table reflects the Standardized Measure of Discounted Future Net Cash Flows relating to the Company's interest in proved oil and gas reserves as of: December 31, -------------------- 2000 1999 ---- ---- Future cash inflows $51,320,776 54,304,207 Future development costs (2,397,403) (5,208,880) Future production costs (2,477,723) (15,655,715) ----------- ----------- Future net cash inflows before income taxes 46,445,650 33,439,612 Future income taxes (3,490,661) (195,748) ----------- ----------- Future net cash flows 42,954,989 33,243,864 10% discount factor (6,307,411) (18,340,109) ----------- ----------- Standardized measure of discounted future net cash inflow $36,647,578 14,903,755 =========== =========== Future net cash flows at each year end, as reported in the above schedule, were determined by summing the estimated annual net cash flows computed by: (1) multiplying estimated quantities of proved reserves to be produced during each year by current prices (at December 31, 2000, such prices were $25.45 per barrel of oil and $9.91 per Mcf of gas) and (2) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on current costs). Gas prices subsequently have declined substantially since year end. At February 28, 2001, the Company was receiving average gas prices of $5.68 per Mcf. Had the lower prices been used, the Company's standardize measure of discounted future net cash flows attributable to proved oil and gas reserves at December 31, 2000 would have been reduced. Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and available net operating loss carryforwards. The annual future net cash flows were discounted, using a prescribed 10% rate, and summed to determine the standardized measure of discounted future net cash flow. The Company cautions readers that the standardized measure information which places a value on proved reserves is not indicative of either fair market value or present value of future cash flows. Other logical assumptions could have been used for this computation (Continued) 64 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS which would likely have resulted in significantly different amounts. Such information is disclosed solely in accordance with Statement 69 and the requirements promulgated by the SEC to provide readers with a common base for use in preparing their own estimates of future cash flows and for comparing reserves among companies. Management of the Company does not rely on these computations when making investment and operating decisions. Principal changes in the Standardized Measure of Discounted Future Net Cash Flows attributable to the Company's proved oil and gas reserves for the periods indicated are as follows:

December 31, ------------------------------------ 2000 1999 1998 ---- ---- ---- Sales and transfers, net of production costs* $(4,150,204) 555,450 433,346 Acquisitions of reserves -- 4,335,908 -- Net change in estimated future development costs (5,495,874) 2,523,249 18,918 Extensions and discoveries 14,431,684 17,523 5,322,055 Revisions in previous quantity estimates 2,280,195 (9,433,590) 34 Net changes in sales and transfer prices, net of production costs 6,125,097 9,503,801 (10,944,737) Accretion of discount 1,499,151 618,430 2,277,393 Net change in income taxes (153,634) -- -- Change in production rates (timing) and other 7,207,408 811,953 (7,835,514) ----------- ---------- ----------- Net change $21,743,823 8,932,724 (10,728,505) =========== ========== ===========

*54% of the Company's estimated proved oil reserves and 28% of its estimated proved gas reserves were being produced at December 31, 2000. (12) SALE OF ASSETS On January 22, 2001, the Company sold its 50% interest in the Black Marlin Pipeline System to affiliates of the Williams Companies, Inc. for approximately $4.6 million. The Black Marlin Pipeline System includes a 75-mile gas and condensate gathering line with related shore facilities servicing the High Island Area, offshore Texas (the "Black Marlin Pipeline") and the recently constructed 3-mile lateral pipeline extending from High Island Block A-5 to an interconnection into the Black Marlin Pipeline in High Island Block A-6 (the "A-5 Lateral"). This disposition was consummated, in part, through a sale of all of the outstanding capital stock of Black Marlin Pipeline Company (formerly an indirect wholly owned subsidiary of the Company) the owner of a 50% interest in the Black Marlin Pipeline, pursuant to a Purchase and Sale Agreement dated January 12, 2001 (the "Stock Purchase Agreement") among Black Marlin Energy Company, a wholly owned subsidiary of the Company, MCNIC Offshore Pipeline & Processing Company ("MCNIC"), WBI Southern, Inc. ("WBI") and (Continued) 65 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Williams Field Services Group, Inc. The Company received $3.6 million for the outstanding capital stock of Black Marlin Pipeline Company for a gain of $922,865. The remaining part of this disposition was consummated through the sale of the A-5 Lateral owned 50% by Blue Dolphin Pipe Line Company, a wholly owned subsidiary of the Company ("BDPL"), pursuant to a Purchase and Sale Agreement dated January 12, 2001, among BDPL, MCNIC, WBI and Williams Field Services - Gulf Coast Company, L.P. The Company received $1.0 million for its interest in the A-5 Lateral, for a gain of $112,092. (13) QUARTERLY FINANCIAL DATA The following table shows summary quarterly financial data for 2000 and 1999. See Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this Form 10-K.

First Second Third Fourth Quarter Quarter Quarter Quarter ------ ------ ------- ------- 2000 ---- Operating revenues 1,584,781 1,807,930 2,368,062 2,181,197 Operating income (loss), pretax 105,395 201,102 (9,930,339) 1,232,677 Net income (loss) 52,838 151,697 (10,109,585) 229,070 EPS - basic and diluted 0.01 0.03 (1.69) 0.04 1999 ---- Operating revenues 584,442 604,238 631,493 936,883 Operating income (loss), pretax (499,970) (549,255) (593,267) (461,090) Net income (loss) 924,833 (406,946) (429,003) (2,175,395) EPS - basic and diluted 0.20 (0.09) (0.09) (0.36)

(Continued) 66 BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The following table provides information with respect to the Directors and the executive officers of the Company. POSITION NAME AGE POSITION HELD SINCE ---- --- -------- ---------- Ivar Siem 54 Chairman of the Board 1989 Robert L. Barbanell 70 Director 2000 Michael S. Chadwick 49 Director 1992 Harris A. Kaffie 51 Director 1989 Michael J. Jacobson 54 President and Chief 1990 Executive Officer Roland B. Keller 62 Executive Vice President 1990 John P. Atwood 49 Vice President 1998 G. Brian Lloyd 42 Vice President, Treasurer 1989 and Secretary The following is a brief description of the background and principal occupation of each Director and executive officer: IVAR SIEM - Chairman of the Board of Directors - From 1995 to 2000, Mr. Siem served on the Board of Directors of Greywolf Inc., during which time he served as Chairman from 1995 to 1998 and interim President (1995) during its restructuring. Since 1985, he has been an international consultant in energy, technology and finance. He has served as a Director of Business Development for Norwegian Petroleum Consultants and as an independent consultant to the oil and gas exploration and production industry based in London, England. Mr. Siem holds a Bachelor of Science Degree in Mechanical Engineering from the University of California, Berkeley, and has completed an executive MBA program at Amos Tuck School of Business, Dartmouth University. Since October 1999, Mr. Siem has served as a Director of American Resources Offshore, Inc., and since December 1999 he has served as President of American Resources, at which time American Resources became a 75% owned subsidiary of the Company. ROBERT L. BARBANELL - Director - Mr. Barbanell has served as President of Robert L. Barbanell Associates, Inc., a financial consulting firm since July 1994. Mr. Barbanell was employed by Bankers Trust New York Corporation from June 1986 to June 1994 as Managing Director and from December 1981 to June 1986 as Senior Vice President. He is also a director of Cantel Medical Corp., Kaye Group, Inc. and Marine Drilling Companies, Inc. (Continued) 67 MICHAEL S. CHADWICK - Director - Mr. Chadwick has been engaged in the commercial and investment banking businesses since 1975. From 1988 to 1994, Mr. Chadwick was President of Chadwick, Chambers & Associates, Inc., a private merchant and investment banking firm in Houston, Texas, which he founded in 1988. In 1994, Mr. Chadwick joined Sanders Morris Mundy Harris, an investment banking and financial advisory firm, as Senior Vice President and a Managing Director in the Corporate Finance Group. Mr. Chadwick holds a Bachelor of Arts Degree in Economics from the University of Texas at Austin and a Master of Business Administration Degree from Southern Methodist University. HARRIS A. KAFFIE - Director - Mr. Kaffie has been a partner in Kaffie Brothers, a real estate, farming and ranching company, and has held this position for more than five years. He currently serves as a Director of KBK Capital Corporation and Director of CCNG, Inc., the General Partner of Corpus Christi Natural Gas Company, L.P., a privately-held company which owns and operates natural gas pipelines and processing facilities, and is engaged in the marketing of gas. Mr. Kaffie received a Bachelor of Business Administration Degree from Southern Methodist University in 1972. MICHAEL J. JACOBSON - President and Chief Executive Officer - Mr. Jacobson has been associated with the energy industry since 1968, serving in various senior management capacities since 1980. He served as Senior Vice President and Chief Financial and Administrative Officer for Creole International, Inc. and it's subsidiaries, international providers of engineering and technical services to the energy sector, as well as Vice President of Operations for the parent holding company, from 1985 until joining the Company in January 1990. He has also served as Vice President and Chief Financial Officer of Volvo Petroleum, Inc. Mr. Jacobson began his career with Shell Oil Company, where he served in various analytical and management capacities in the exploration and production organization during the period 1968 through 1974. Mr. Jacobson holds a Bachelor of Science Degree in Finance from the University of Colorado. Mr. Jacobson has served as President and Chief Executive Officer of the Company since January 1990. Since October 1999, Mr. Jacobson has served as a Director of American Resources. ROLAND B. KELLER - Executive Vice President Exploration and Operations - Mr. Keller has been associated with the energy industry since 1962, serving in senior management capacities since 1976. Prior to joining the Company in 1990, he served as Senior Vice President - Exploration for Sandefer Oil and Gas Company, an independent oil and gas company from 1982. He served as Vice President - Exploration and Production for Volvo Petroleum, Inc., from 1980 to 1982, and Vice President and Division Manager for Florida Exploration Co., from 1976 to 1980. Mr. Keller began his career with Amoco Production Co., serving in various technical and management capacities from 1962 through 1976. Mr. Keller holds Bachelor of Science and Master of Science degrees in Geology from the University of Florida. Mr. Keller has served as Executive Vice President - Exploration and Development of the Company since September 1990. Since December 1999, Mr. Keller has served as Vice President of American Resources. JOHN P. ATWOOD - Vice President, Business Development - Mr. Atwood has been associated with the energy industry since 1974, serving in various management capacities since 1981. He served as Senior Area Land Manager for CSX Oil & Gas Corporation and Division Land Manager for Hamilton Brothers Oil Company/Volvo Petroleum, Inc. He served in various land capacities for Tenneco Oil Company from 1977 to 1981. Mr. Atwood is a Certified Professional Landman and (Continued) 68 holds a Bachelor of Arts Degree from Oklahoma City University and a Master of Business Administration Degree from Houston Baptist University. Mr. Atwood served as Vice President of Land from 1991 to 1998 and Vice President of Finance and Corporate Development until his appointment as Vice President of Business Development in 2001. Since December 1999, Mr. Atwood has served as a Director, Vice President and Secretary of American Resources. G. BRIAN LLOYD - Vice President, Treasurer and Secretary - Mr. Lloyd is a Certified Public Accountant and has been employed by the Company since December 1985. Prior to joining the Company, he was an accountant for DeNovo Oil and Gas Inc., an independent oil and gas company. Mr. Lloyd received a Bachelor of Science Degree in Finance from Miami University, Oxford, Ohio in 1982 and attended the University of Houston in 1983 and 1984. Mr. Lloyd has served as Secretary of the Company since May 1989, Treasurer since September 1989 and Vice President since March 1998. Since December 1999, Mr. Lloyd has served as Vice President and Treasurer of American Resources. There are no family relationships between any Director or executive officer. ITEM 11. EXECUTIVE COMPENSATION The Company pays to non-employee members of the Board of Directors an annual retainer of $3,000, plus $500 for each committee served on, and stock options as determined by the compensation committee. In 2001, the annual retainer was increased to $12,000, payable 50% in cash and 50% in Company Common Stock. The audit committee chairman receives an annual retainer of $3,000 and other audit committee members receive an annual retainer of $1,500. In addition, Directors will receive stock options based upon a market value of $20,000. No additional remuneration is paid to such Directors for committee meetings attended, except that such Directors are entitled to be reimbursed for expenses related to attendance of board or committee meetings. The following table sets forth the compensation paid to the Chief Executive Officer and each of the executive officers of the Company whose cash compensation exceeded $100,000 in 2000 (collectively, the "Named Executive Officers") for services rendered to the Company. (Continued) 69

SUMMARY COMPENSATION TABLE* LONG-TERM COMPENSATION AWARDS ----------------- ANNUAL COMPENSATION SECURITIES NAME AND ------------------------------------ UNDERLYING PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS (#) ------------------------- -------------- ------------------- ------------ ----------------- Ivar Siem 2000 $150,000 - 10,965 Chairman of the Board 1999 $150,000 - 14,292 1998 $ 65,085 - - Michael J. Jacobson 2000 $200,000 - 9,283 President and Chief 1999 $200,000 - 14,445 Executive Officer 1998 $200,000 - - Roland B. Keller 2000 $140,000 - 5,704 Executive Vice 1999 $140,000 - 10,140 President - 1998 $140,000 - - Exploration and Development John P. Atwood (1) 2000 $124,167 - 6,423 Vice President of 1999 $120,000 - 9,834 Business 1998 $105,000 - - Development

(1) Became an executive officer in October 1998. *Excludes certain personal benefits, the aggregate value of which do not exceed 10% of the Annual Compensation shown for each person. (Continued) 70 OPTION GRANTS IN LAST FISCAL YEAR

Potential Realizable Percent of Value At Assumed Total Annual Rates Of Number of Options Stock Appreciation Securities Granted to At Assumed Annual Underlying Employees Exercise of Rates for Options In Fiscal Base Price Expiration Option Term Name Granted # Year ($/Sh) Date 5% ($) 10% ($) ------------- ---------------- -------------- ------------- --------- -------- Ivar Siem 8,000 14% $6.00 5/17/2010 0 0 Michael J. Jacobson 6,000 11% $6.00 5/17/2010 0 0 Roland B. Keller 3,000 5% $6.00 5/17/2010 0 0 John P. Atwood 4,000 7% $6.00 5/17/2010 0 0

AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES

Value of Unexercised Number of Unexercised In-the-Money Options Options at at Year End (#) at Year End (1) Shares Acquired Value ------------------------------- -------------------------- Name on Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable ---- ---------------- --------- ----------- ------------- ----------- ------------- Ivar Siem 2,778 $ 3,539 16,444 8,446 $ 0 $ 0 Michael J. Jacobson 23,445 $14,166 22,223 7,332 $ 0 $ 0 Roland B. Keller 0 $ 0 11,222 8,112 $ 0 $ 0 John P. Atwood 1,000 $ 1,274 8,778 8,669 $ 0 $ 0 (1) Based on the difference between the average of the closing bid and ask prices on December 29, 2000 (the last trading day of 2000) and the exercise price.

71 The Company's Stock Option Plans provide that, upon a change of control, the Compensation Committee may accelerate the vesting of options, cancel options and make payments in respect thereof in cash in accordance with the Stock Option Plans, adjust the outstanding options as appropriate to reflect such change of control, or provide that each option shall thereafter be exercisable for the number and class of securities or property that the optionee would have been entitled to had the option already been exercised. The Stock Option Plans provide that a change of control occurs if any person, entity or group acquires or gains ownership or control of more than 50% of the outstanding Common Stock or, if after certain enumerated transactions, the persons who were Directors before such transactions cease to constitute a majority of the Board of Directors. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth, as of March 26, 2001, certain information with respect to the beneficial ownership of shares of the Common Stock (the only class of voting security issued and outstanding) as to (i) all persons known by the Company to be beneficial owners of 5% or more of the outstanding shares of Common Stock, (ii) each Director, (iii) each Named Executive Officer and (iv) all executive officers and Directors, as a group. Unless otherwise indicated, each of the following persons has sole voting and dispositive power with respect to such shares. 72 SHARES OWNED BENEFICIALLY NAME OF ------------------------------------ BENEFICIAL OWNER NUMBER PERCENT (1) ---------------- ----------- ---------------- Colombus Petroleum Limited, Inc. (2) 911,712 15.2 Ivar Siem (3) 418,177 7.0 Harris A. Kaffie (3) 707,775 11.8 Michael S. Chadwick (3) 11,476 * Robert Barbanell (3) 30,000 * Michael J. Jacobson (3) 147,556 2.5 Roland B. Keller (3) 44,469 * John P. Atwood (3) 25,755 * Executive Officers and Directors, as a Group (8 persons) (3) 1,404,289 23.3 ------------------------------ * Less than 1% (1) Based upon 6,016,718 shares of Common Stock outstanding on March 26, 2001. (2) The address of Colombus Petroleum Limited, Inc., is Aeulestrasse 74, FL-9490, Vaduz, Liechtenstein. (3) Includes shares of Common Stock issuable upon exercise of options that may be exercised within 60 days of March 26, 2001 as follows: Mr. Siem - 16,444; Mr. Kaffie - 6,890; Mr. Chadwick - 4,389; Mr. Barbanell - 10,000; Mr. Jacobson - 22,222; Mr. Keller - 11,222; Mr. Atwood - 8,778 and all directors and executive officers as a group - 98,830. 73 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS On December 1, 1999, the Company issued a $1,000,000 promissory note to Harris A. Kaffie, a director of the Company. The note was due June 1, 2000, bore interest at 10% per annum, and was convertible into Common Stock at $6.60 per share. The due date of the note was subsequently extended to March 31, 2001, and was convertible into common stock at $6.00 per share. The Company issued three convertible promissory notes in the principal amount of $200,000, $200,000 and $600,000 on May 25, 2000, July 6, 2000 and November 30, 2000, respectively. These notes were issued to Ivar Siem, Chairman of the Company. These convertible promissory notes were due March 31, 2001, bore interest at the rate of 10% per annum and were convertible into common stock at the rate of $6.00 per share. The principal and accrued interest due to Messrs. Kaffie and Siem were paid in full in January 2001. In late 2000, the Company formed Drillmar, Inc., 37.5% owned by the Company. Drillmar acquired a 1% general partnership interest in Zephyr Drilling, Ltd. At December 31, 2000, Drillmar's investment in Zephyr was $86,000. Harris A. Kaffie, director of the Company, and Ivar Siem, Chairman of the Company, are limited partners in Zephyr, investing $3.0 million dollars for a 37.5% interest and $2.97 million for a 37.1% interest, respectively. 74 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Financial Statements The following financial statements and the Reports of Independent Public Accountants are filed as a part of this report on the pages indicated: Page ---- Consolidated Balance Sheets, at December 31, 2000 and 1999................................................... 38 Consolidated Statements of Operations, for the years ended December 31, 2000, 1999, and 1998.......................... 40 Consolidated Statements of Stockholders' Equity, for the years ended December 31, 2000, 1999, and 1998.............. 41 Consolidated Statements of Cash Flows, for the years ended December 31, 2000, 1999, and 1998.......................... 42 Notes to Consolidated Financial Statements.................. 44 (a) 2. Exhibits No. Description 3.1 (1) Certificate of Incorporation of the Company. 3.2 (2) Certificate of Correction to the Certificate of Incorporation of the Company dated June 30, 1987. 3.3 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated June 30, 1987. 3.4 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 11, 1989. 3.5 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 14, 1989. 3.6 (2) Bylaws of the Company. 3.7 (4) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 8, 1997. 75 4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock. *10.1 (3) Blue Dolphin Energy Company 1996 Employee Stock Option Plan. *10.2 (7) Blue Dolphin Energy Company 2000 Stock Incentive Plan. 10.12 (5) Asset Purchase Agreement between WBI Southern, Inc., Blue Dolphin Pipeline Company, Buccaneer Pipe Line Co. and Mission Energy, Inc. 10.13 (5) Purchase and Sale Agreement between Enron Pipeline Company, Black Marlin Energy Company and Blue Dolphin Energy Company. 10.14 (5) Asset Purchase Agreement between WBI Southern, Inc., Black Marlin Pipeline Company and Black Marlin Energy Company. 10.15 (5) Asset Purchase Agreement between MCNIC Offshore Pipeline & Processing Company, Black Marlin Pipeline Company and Black Marlin Energy Company. 10.16 (6) Investment Agreement, as amended, by and between American Resources Offshore, Inc. and Blue Dolphin Exploration Company. 10.18 (8) Purchase and Sale Agreement by and between Williams Field Services Group, Inc. and Black Marlin Energy Company 10.19 (8) Purchase and Sale Agreement by and between Williams Field Services - Gulf Coast Company, L.P. and Blue Dolphin Pipeline Company 21.1** List of Subsidiaries of the Company. 23.1** Consent of Ryder Scott Company, independent petroleum engineers. 23.2** Consent of KPMG LLP 23.3** Consent of Ernst & Young LLP -------------- (1) Incorporated herein by reference to Exhibits filed in connection with Registration Statement on Form S-4 of ZIM Energy Corp. filed under the Securities Act of 1933 (Commission File No. 33-5559). (2) Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1989 under the Securities and Exchange Act of 1934, dated March 30, 1990 (Commission File No. 000-15905). (3) Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1995 under the Securities and Exchange Act of 1934, dated March 29, 1996 (Commission File No. 000-15905). 76 (4) Incorporated herein by reference to Exhibits filed in connection with the definitive Information Statement on Schedule 14C of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated November 18, 1997 (Commission File No. 000-15905). (5) Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated March 1, 1999 (Commission File No. 000-15905). (6) Incorporated herein by reference to Exhibits filed in connection with Schedule 13D of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated October 22, 1999 (Commission File No. 000- 15905). (7) Incorporated herein by reference to Exhibits filed in connection with the Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated May 18, 2000 (Commission File No. 000-15905). (8) Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated January 22, 2001 (Commission File No. 000-15905). * Management Compensation Plan. ** Filed herewith. (b) Reports on Form 8-K On January 31, 2001, the Company filed a current report on Form 8-K dated January 22, 2001, reporting the sale of its 50% interest in the Black Marlin Pipeline System. The items reported in such current report were Item 2 (Acquisitions or Dispositions of Assets) and Item 7 (Financial Statement and Exhibits). 77 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. BLUE DOLPHIN ENERGY COMPANY (Registrant) By: /s/ Michael J. Jacobson ------------------------------ Michael J. Jacobson, President (principal executive officer) Date: March 30, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. SIGNATURE TITLE DATE /s/ Michael J. Jacobson President (principal March 30, 2001 Michael J. Jacobson executive officer) /s/ G. Brian Lloyd Vice President, Treasurer March 30, 2001 G. Brian Lloyd (principal accounting and financial officer) /s/ Ivar Siem Chairman March 30, 2001 Ivar Siem /s/ Harris A. Kaffie Director March 30, 2001 Harris A. Kaffie /s/ Robert L. Barbanell Director March 30, 2001 Robert L. Barbanell /s/ Michael S. Chadwick Director March 30, 2001 Michael S. Chadwick 78