Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
THE COMPANY
Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as "Blue Dolphin" or the "Company") is engaged in the exploration, acquisition, development and operation of oil and gas properties, oil and gas transportation, processing and marketing, and the terminaling and storage of crude oil and refined products. It's primary business activities are located offshore in the Gulf of Mexico and along the Texas Gulf Coast. The Company was incorporated in 1986 as a Delaware corporation as the result of the corporate combination of ZIM Energy Corporation, a Texas corporation founded in 1983 whose name was changed to ZIM Exploration and Production Co. ("ZEPCO"), and Petra Resources, Inc., an Oklahoma corporation formed in 1980 ("Petra"). The Company succeeded to the business, properties and assets of ZEPCO and Petra. During the year ended January 31, 1988, the Company changed its name from ZIM Energy Corporation to Mustang Resources Corp. In January 1990, the Company's name was changed to Blue Dolphin Energy Company.
The Company's principal assets are owned and operations conducted by its wholly-owned subsidiaries Ivory Production Co., a Delaware corporation ("Ivory"), Blue Dolphin Exploration Company, a division of Ivory ("BDEX"), Mission Energy, Inc., a Delaware corporation d/b/a MEI Mission Energy, Inc. ("Mission"), Blue Dolphin Pipe Line Company., a Delaware corporation ("BDPC"), Buccaneer Pipe Line Co., a Texas corporation, Blue Dolphin Services Co., a Texas corporation, and Petroport, Inc., a Delaware corporation ("Petroport"). The Company is a holding company that conducts substantially all of its operations through its subsidiaries.
The principal executive office of the Company is located at Eleven Greenway Plaza, Suite 1606, Houston, Texas, 77046, telephone number (713) 621-3993. A shore base facility is maintained in Freeport, Texas serving Gulf of Mexico operations. The Company has 14 full-time employees. The Company's Common Stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") under the trading symbol "BDCO".
FINANCING ACTIVITIES
In December 1990, Dolphin Pipeline, Inc. ("Dolphin") owner of approximately 66% of the voting stock of the Company, transferred to the Company $3,500,000 face amount of the Company's 7 1/2% Convertible Subordinated Notes, Series B, due 2001, held by Dolphin, 7,030,017 shares of Common Stock, and a small amount of cash in exchange for the issuance to Dolphin of 13,292,874 shares of Common Stock. Immediately following the exchange, Dolphin distributed its 13,292,874 shares of Common Stock and 15,000,000 shares of Series A Preferred Stock ("Preferred Stock") to the individual shareholders of Dolphin. The distribution, which represented all of its holdings in the Company, resulted in a deconcentration of the Company's ownership. Also in December 1990, pursuant to a Regulation S Offshore Offering, 809,000 shares of Common Stock were sold for $353,938.
In December 1991, the Company restructured certain of its outstanding debt, and arranged for a credit facility from A/S Investa ("Investa"), a principal shareholder of the Company. On December 31, 1991, Investa purchased the Company's senior debt of approximately $1,650,000 from First Interstate Bank of Texas ("Senior Debt"). The Company and Investa amended the Senior Debt agreement effective December 31, 1991. Among other things, the amendment provided for deferral of principal and interest payments. The credit facility from Investa provided for a draw down line of credit in the amount of $1,500,000 (the "Credit Facility"). The Company fully drew down the Credit Facility in 1992. Additionally, $788,000 principal amount of short-term notes from certain affiliates arranged during 1991, were exchanged for $788,000 principal amount of Non-negotiable Long-Term Convertible Notes ("Long-Term Notes"), effective December 31, 1991.
From October 1992 through November 1993, the Company purchased and retired $2,000,000 principal amount of its 7 1/2% Convertible Subordinated Notes, Series A, due 2001 ("Series A Notes") for $1,139,000. The Series A Notes were secured by U.S. Treasury securities which were released to the Company and sold for approximately $1,165,000.
In March 1993, the Company completed renegotiation of the payment terms of a note payable incurred to acquire 360 acres of land in Freeport, Texas, upon which the Company's shore facilities are located (the "Land Note"). A final lump sum payment of approximately $1,000,000 was due and payable in January 1993, under the Land Note as originally issued. Under the restructured note, the principal balance was retired through monthly payments of principal and interest during the period March 1, 1993 through March 1, 1994.
In April 1993, Investa sold to various purchasers, including the Company, all of its holdings in the Company. Such holdings included 5,062,812 shares of Common Stock; 10,650,000 shares of Preferred Stock, along with cumulative unpaid dividends of $704,675; the Senior Debt, in the principal amount of $1,691,276, along with accrued interest of $175,662; the Credit Facility, in the principal amount of $1,500,000, along with accrued interest of $87,371; and certain Long-Term Notes, in the principal amount of $300,000, along with accrued interest of $22,760. The Company participated in the purchase of these securities in the amount of $150,000, and received 208,942 shares of Common Stock; 439,525 shares of Preferred Stock, along with cumulative unpaid dividends of $28,672; $69,799 of the Senior Debt, along with accrued interest of $7,250; $61,905 of debt under the Credit Facility, along with accrued interest of $3,606; and $12,381 of the Long-Term Notes, along with accrued interest of $939. The above securities acquired by the Company were retired in April 1993.
Effective May 1, 1993, the Company rearranged and restructured the remaining outstanding debt of $3,347,191 which had been purchased from Investa by others. Payment terms of the Senior Debt were extended. See Note 5 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference. The principal balances due under the Credit Facility and the Long-Term Notes, $1,438,095 and $287,691, respectively, were combined into the Credit Facility and accrued interest of $107,530 was eliminated. In addition, payment terms were extended and conversion rights were replaced with warrants. The conversion features of the Credit Facility and Long-Term Notes, wherein the debt holders had the right to convert the principal balances outstanding into Common Stock, at the rate of $0.05 per share (34,514,280 shares if fully converted) were replaced with detachable warrants to purchase 17,257,140 shares of Common Stock. The warrants are exercisable through April 30, 1996 at the rate of $.10 per share.
Effective June 1, 1993, the Company renegotiated the terms of a $150,000 Long- Term Note with an affiliate (Harris A. Kaffie), whereby, among other things, until September 30, 1993, the principal balance could be converted, at the lender's option, into Common Stock, at a rate of 13.3 shares for each $1.00 of principal balance outstanding. The original terms of the note provided for conversion at a rate of 20 shares of Common Stock for each $1.00 of principal outstanding. During September 1993, the entire $150,000 was converted into 2,000,000 shares of Common Stock. Also, in June 1993, holders of $219,000 principal amount of Long-Term Notes ($150,000 from Harris A. Kaffie and $69,000 from Columbus Petroleum, Ltd.) converted the notes into 4,380,000 shares of Common Stock.
In January 1994, the Company arranged a reducing revolving credit facility with Bank One, Texas, N.A., ("Loan Agreement") in an amount of $10,000,000, with an initial availability of $6,500,000. The amount available under the Loan Agreement can be redetermined semi-annually. The facility was made available for retirement and consolidation of existing debt and to finance future working capital needs, including the acquisition and development of oil and gas reserve based assets.
Upon consummation of the Loan Agreement, the Company purchased and retired its Senior Debt, outstanding debt under the Credit Facility, the Land Note, its Long-Term Notes, and the Series B Notes. Face amount of the above debt, totaling $6,350,729, inclusive of interest, was purchased for approximately $5,460,000.
Also in the first quarter 1994, the remaining $500,000 of Series A Notes were purchased at a cost of $470,000. The Series A Notes were secured by U. S. Treasury securities which were released to the Company and sold for approximately $306,000. The Company has retired all $8,000,000 of its 7 1/2% Convertible Subordinated Notes, Series A and B, issued in 1986.
BUSINESS AND PROPERTIES
The Company conducts its traditional operations in two primary business segments: (i) oil and gas exploration and production, and (ii) pipeline operations. The Company's oil and gas activities include the exploration, acquisition, development, operation and, when appropriate, disposition of oil and gas properties, including the marketing of production therefrom. The Company also develops for sale to industry drillable exploration prospects in the Gulf of Mexico. The Company owns and operates through its subsidiaries, natural gas and oil pipeline facilities including related processing facilities. See Note 11 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference for information relating to revenues, operating profit or loss and identifiable assets of the Company's business segments. In March 1995, the Company acquired exclusive rights to certain proprietary technology represented by patents, associated with the development and operation of a deepwater crude oil and products terminal and storage facility. Operations associated with this acquisition will be conducted in a newly formed subsidiary, and represent a new business segment for the Company. See Note 12 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference for information relating to Petroport, Inc.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The following is a description of the Company's major oil and gas exploration and production properties and activities:
THE BUCCANEER PROPERTIES. In 1985, the Company purchased leasehold interests covering the Galveston Block 288 Field (the "Buccaneer Field"). The Buccaneer Field is comprised of interests in parts of four blocks covering 14,660 acres of land located approximately 30 miles south of Galveston, Texas, offshore in United States territorial waters in the Gulf of Mexico. Operation of the field is conducted from two platforms located in waters averaging approximately 65 feet in depth. Contemporaneously with the acquisition of the Buccaneer Field, certain lands and facilities related to the Buccaneer Field and its operations were also acquired including: approximately 360 acres of land in Brazoria County, Texas (the "Buccaneer Real Estate"), all of the issued and outstanding shares of BDPC, which owns the Blue Dolphin Pipeline described in "Pipeline Operations" below; onshore facilities located on the Buccaneer Real Estate for oil and gas separation and dehydration, and tankage for liquids storage with capacity totalling 85,000 Bbls (the "Processing Facility"); and a barge loading terminal located on the Intracoastal Waterway near Freeport, Texas, together with an 8 inch oil pipeline to transport crude oil and condensate from the Processing Facility to the barge loading terminal (together, the "Buccaneer Pipeline"). In 1994, a 15,000 Bbl capacity liquids storage tank was taken out of service. The tank had not been utilized since its' acquisition.
The Company owns a 100% working interest in the Buccaneer Field (81.33% net revenue interest), less and except 100% of the Operating Rights covering 2,340 acres in Galveston Block 295 and 1,890 acres in Galveston Block 296 as to certain depths, which will be assigned to the Farmee pursuant to the Farmout Agreement. The Company will retain a 6.33% overriding royalty interest before payout in the Operating Rights assigned. See Note 10 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference. The Company's leasehold interests in the Buccaneer Field represent 100% of the discounted present value of estimated future net revenues from Proved Reserves of the Company as of December 31, 1994. Production from the Buccaneer Field accounted for 100% of the total revenues from oil and gas sales of the Company for the year ended December 31, 1994. See "Proved Oil and Gas Reserves", below.
Buccaneer Field condensate and natural gas production are separated offshore at the Company's Galveston Block 296-B platform, metered, recombined and then delivered to the Blue Dolphin Pipeline, which transports the production along with production of third parties to the Processing Facility where the natural gas is again separated from the crude oil and condensate. The crude oil and condensate are stored in tanks at the Processing Facility and subsequently transported through the Buccaneer Pipeline to a barge loading terminal where the liquids are sold. Sale of condensate from the Buccaneer Field represented 5% of the revenues of the Company from oil and gas sales in the year ended December 31, 1994. During 1994, condensate sales represented 1% of the Company's total revenues.
Natural gas produced from the Buccaneer Field is sold to Dow Chemical Company. The gas delivered through the Blue Dolphin Pipeline to the Processing Facility, following the separation of crude oil and condensate from the gas stream and dehydration of the gas, is delivered directly to Dow's Intrastate pipeline system and chemical plants complex in Freeport, Texas. Under a gas purchase contract dated May 1, 1991, (the "Dow Contract") Dow agreed to purchase the gas produced from the Buccaneer Field for an initial three year term with monthly extensions thereafter. Currently, Dow and the Company have extended the contract through June 1995. From May 1994 through October 1994, the Company received a monthly price based on a floating industry index which averaged $1.87/MMBtu per month. From November 1994 through June 1995, the Company will receive a variable monthly price based on an agreed fixed monthly rate schedule which averages $1.90/MMBtu per month. Purchases of gas by Dow from the Buccaneer Field represented 95% of the oil and gas sales revenues and 16% of the total revenues of the Company for the year ended December 31, 1994. Deliveries averaged approximately 1,100 MMBtu of gas per day during February 1995.
In November 1992, the Company entered into a Farmout Agreement (the "Farmout Agreement") with a third party ("Farmee"), wherein the third party earned an interest in certain of the non-producing and undeveloped acreage in the Buccaneer Field through successful drilling and development of the acreage. The farmout acreage consists of two project areas. In January 1993, the initial well under the Farmout Agreement was drilled and production casing was set. Production commenced in March 1994 from the initial well. The drilling of a second well in March 1994 resulted in a dry hole. The drilling option under which the Farmee could earn additional acreage expired March 27, 1995.
In August 1993, the U. S. Department of the Interior, Minerals Management Service ("MMS") informed Ivory that additional security would be required to provide for the estimated future abandonment obligations associated with the Buccaneer Field. In February 1994, agreement was reached with the MMS as to the amount and form of such additional security. In February 1994, Ivory provided the MMS a supplemental surety bond in the amount of $700,000. The bond is being funded over approximately a six year period, through escrowing with the surety of $10,000 per month. Additionally, a sinking fund has been established wherein the greater of the net proceeds from the Farmout acreage or $250,000 annually will be set aside until a total of approximately $2,400,000 has been accumulated to meet end of lease abandonment and site clearance obligations. Ivory estimates the remaining life of its major Buccaneer Field facilities to be in excess of ten years.
To meet current abandonment obligations, in November 1993, a "turnkey" agreement was arranged with a third party contractor to physically plug and abandon certain wells and satellite platform facilities for which there was no further utility in future field development. Work to abandon the facilities was completed in June 1994, at a cost of approximately $1,990,000. Vendor financing was provided under the agreement. Remaining payments of approximately $720,000 and $532,000 are payable during 1995 and 1996, respectively.
In addition to conducting traditional oil and gas production operations for itself, the Company operates and maintains oil and gas production facilities for third parties who also utilize the Blue Dolphin Pipeline System for transportation of their production. Such contract operation and maintenance services are currently provided to two third party producer/shippers. During 1994, revenues attributable to provision of contract operation and maintenance services, and transportation and processing services for these customers, represented 19% of the Company's total revenues.
In addition to realizing revenues attributable to the sale of Buccaneer Field gas and oil production, the Company also receives economic benefits from the marketing of certain gas transported through the Blue Dolphin Pipeline.
OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, BDEX initiated a program to develop drillable oil and gas prospects in the Gulf of Mexico for sale to industry. The program utilizes the latest technology in 3-D seismic processing. A 3-D seismic data acquisition agreement has been arranged whereby a minimum of $1,500,000 will be committed over a five year period to acquire 3-D seismic data.
The prospect generation program was initiated to take advantage of several favorable factors including: increased industry activity offshore in the Gulf of Mexico; availability of 3-D seismic data; availability of experienced, qualified personnel; and the available market for high quality, high potential, 3-D seismic based offshore oil and gas prospects.
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, 1994, by Gerald W. DuPont Enterprises, Inc., independent petroleum engineers.
The following table summarizes the estimates of Proved Reserves, Proved Developed 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, 1994, using the SEC Method.
PROVED RESERVES INFORMATION As of December 31, 1994
Net Oil Net Gas Undiscounted Discounted Reserves Reserves Net Revenue Net Revenue(3) Buccaneer Field (MB) (MMCF) ($000) ($000)
Proved Reserves (1) 195 33,475 $37,571 $18,311 ======== ======== ======== ========
Proved Developed 119 20,351 $26,980 $14,005 Reserves (2) ======== ======== ======== ========
MB = Thousand Barrels MMCF = Million Cubic Feet
(1) "Proved Reserves" means the estimated quantities of oil, natural gas and condensate which geological and engineering data demonstrate with reasonable certainty to be recoverable by primary producing mechanisms in future years from known reservoirs under existing economic and operating conditions.
(2) "Proved Developed Reserves" are those quantities of oil, natural gas and condensate which are expected to be recovered through existing wells with existing equipment and operating methods.
(3) 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").
The quantities of proved natural gas and crude 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.
The reserves and future net revenues presented in the evaluations summarized above reflect capital expenditures totalling $250,000, $2,320,000, $2,250,000 and $2,025,000 in the years ending December 31, 1996, 1997, 1998, and 1999, respectively. 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 may affect the Company's timing for further development of the Buccaneer Field, and there can be no assurance that such reserves will be developed 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, ad valorem taxes, 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 as of the date of the evaluation without escalation except to the extent contractually committed. Lease operating expenses, production and development costs, and ad valorem taxes were estimated based on such costs in effect on the date of the evaluation, 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. Of the Company's total Proved Developed Reserves, 10% of its estimated gas reserves and 7% of its estimated oil reserves were being produced at December 31, 1994.
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 Supplemental Disclosures - Oil and Gas Producing Activities of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference. The Company has not filed with, or included in reports to, any federal authority or agency, any estimates of total oil and gas reserves.
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, 1994.
ACREAGE AND WELLS
Productive Wells (1) Developed Undeveloped Gross Net Acres (1) Acres (1) Oil Gas Oil Gas Gross Net Gross Net ---- --- --- --- ----- --- ----- --- Buccaneer Field 0 2 0 1.1 8,730 8,730 5,930 5,930
(1) "Productive wells" are producing wells and wells capable of production, and include gas wells awaiting pipeline connections or necessary governmental certifications to commence deliveries and oil wells to be connected to production facilities. "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.
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, plant liquids and natural gas attributable to the interest of the Company for each of the periods indicated:
NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31, 1994 1993 1992 --------- --------- --------- Gas: Production (Mcf) 490,587 554,346 518,031 Revenue $1,073,324 $1,302,514 $1,016,001 Average Mcf Per Day 1,344.1 1,518.8 1,415.4 Average Sales Price per Mcf $2.19 $2.35 $1.96
Oil: (1) Production (Bbls) 3,791 3,666 14,178 Revenue (2) $58,312 $62,566 $271,852 Average Bbls per Day 10.4 10.0 38.7 Average Sales Price per BBL $15.38 $17.07 $19.17
Production Costs:
Per Equivalent Mcf (3): $1.93 $1.11 $1.60
(1) Includes condensate. The majority of oil production reported in 1992 relates to the Constantin Property sold in September 1992.
(2) Recognition of Buccaneer Field oil revenue is based upon production.
(3) Production costs, exclusive of workover costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes. Costs totalling $222,000, $303,000, and $287,000 for the years ended December 31, 1994, 1993, and 1992, respectively, for contract production operations and maintenance services provided to third party producers have been excluded. Oil production is converted to equivalent Mcf at the rate of six Mcf per Bbl.
The Company sells its condensate production at market prices at the time of sale, and its natural gas production under a short-term contract. The Company sold all of its Buccaneer Field gas production to Dow under a contract which accounted for 95% of oil and gas sales and 16% of the total revenues of the Company in the year ended December 31, 1994, and all of its condensate from the Buccaneer Field to Coastal States Trading, Inc. at posted prices which accounted for approximately 5% of total oil and gas sales during the year ended December 31, 1994.
DRILLING ACTIVITY. There was one farmout well drilled in 1994 which was dry, and one farmout well drilled in 1993, which began production in 1994. See Note 10 to the Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference. There was no drilling activity during 1992.
The Company maintains a professional staff capable of supervising and coordinating the operation and administration of its oil and gas properties and other assets. From time to time, major maintenance and engineering design and construction projects are contracted to third-party engineering and service companies.
PIPELINE OPERATIONS AND ACTIVITIES
The Company is engaged in both natural gas and oil pipeline operations onshore and offshore Texas in the Gulf of Mexico. The Company, through BDPC, owns and operates the Blue Dolphin Pipeline, which is engaged in the transportation of gas, crude oil and condensate from the Buccaneer Field and other fields in the market area to the Company's Processing Facility located in Freeport, Texas. After processing, the gas is transported to Dow. The Company, through its Buccaneer Pipe Line Co. subsidiary, owns and operates the Buccaneer Pipeline, which transports oil and condensate from the Processing Facility to the Company's barge loading terminal on the Intracoastal Waterway near Freeport, Texas. Both of these pipeline operations are critical to the Company's successful production and marketing of gas and oil from the Buccaneer Field. These operations are also of significant value to third-party producers who have or may connect to the Blue Dolphin Pipeline for the transportation of gas and oil to shore for ultimate delivery to markets.
Prior to February 5, 1992, BDPC was classified as a "natural gas company" pursuant to the Natural Gas Act of 1938 ("NGA") and the Blue Dolphin Pipeline was classified as an "interstate pipeline" pursuant to the Natural Gas Policy Act of 1978 ("NGPA"). On February 5, 1992, by Declaratory Order, the Federal Energy Regulatory Commission ("FERC") ruled that BDPC's facilities, including the Blue Dolphin Pipeline, were gathering facilities, and no longer subject to FERC rate jurisdiction. The ruling allows the Company to set transportation rates for the Blue Dolphin Pipeline that are responsive to market conditions and reflective of the value of the service provided. The Company now also has the flexibility to expand the system, with the ability to earn additional fees associated with the added service without the necessity of petitioning FERC through a rate case proceeding.
The Blue Dolphin Pipeline consists of two separate segments. The offshore segment is comprised of approximately 36 miles of twenty inch pipeline from the Buccaneer Field platforms to shore and 4 miles to the Processing Facility at Freeport, Texas. The onshore segment consists of approximately 2.0 miles of 16-inch pipeline from the Processing Facility to a delivery point at Dow's Freeport, Texas plants' complex and Dow Pipeline Company's intrastate pipeline system.
Various fees are charged to producer/shippers for provision of transportation and Processing Facility services. Blue Dolphin Pipeline throughput averaged approximately 53% of capacity during 1994. Current capacity of the system is approximately 165 MMcf per day of gas and 4,000 Bbls per day of oil and condensate. Ninety eight percent of gas volumes transported and 99% of oil and condensate volumes transported are attributable to production from third party producer/shippers.
The economic return to the Company on its pipeline investment is solely dependent upon the amounts of gas and oil transported through the Blue Dolphin Pipeline. Similarly, since currently the only source of hydrocarbons available for processing by the Processing Facility is the production delivered to shore by the Blue Dolphin Pipeline, the return on the Processing Facility investment is directly linked to Blue Dolphin Pipeline throughput volumes.
The Company is aggressively marketing pipeline system transportation services to prospective third party producer/shippers in the vicinity of the Blue Dolphin Pipeline. In February 1995, the pipeline system operated at approximately 43% of capacity. Future utilization of the pipelines and related facilities will depend upon the success of drilling programs in the Blue Dolphin Pipeline corridor, attraction to the system, and execution of contracts with producer/shippers to transport their oil and gas production through the Company's pipeline systems.
OFFSHORE DEEPWATER PORT AND STORAGE FACILITY
In March 1995, the Company completed acquisition of Petroport, L.C. Petroport, L.C. was merged into Petroport. Petroport, L.C. holds proprietary technology, represented by certain patents issued and or pending, associated with the development and operation of an offshore deepwater crude oil and products port and storage facility. The Petroport offshore terminal and storage facility will receive and store imported crude oil and refined products with deliveries into U.S. markets. The design concept of the facility, which is unique to Petroport, incorporates salt dome cavern storage directly under a delivery vessel, thereby reducing construction costs and vessel turnaround time. Petroport will provide importers with a competitive and environmentally attractive alternative to the lightering of large tankers as well as low cost long-term storage of crude oil and products. At this time, the Company is developing its business plan focusing on the initial activities associated with the project. See Item 7 Managements Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition: Liquidity and Capital Resources.
The Company expects to focus its efforts in the future on the acquisition, exploration and development of oil and gas reserve based assets, generation of oil and gas exploration prospects, the further development and expansion of its pipeline transportation system, and development of Petroport.
COMPETITION, MARKETS AND REGULATION
COMPETITION
The oil and gas industry is highly competitive in all phases. 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. Competition also exists with other industries in supplying the energy and fuel needs of consumers.
The competitors of the Company in the acquisition, exploration and development of oil and gas properties and in the production, transportation and marketing of oil, gas and other hydrocarbons include the major oil companies and large gas pipeline companies in addition to numerous independent oil and gas companies and pipelines, individual proprietors, and income and drilling programs. Many of these competitors possess and employ financial and personnel resources substantially in excess of those which are available to the Company, which may allow them to pay greater amounts for desirable properties, to define, evaluate, bid for and purchase a greater number of potential properties, to obtain equipment, services and other resources necessary to operate producing properties and facilities at prices more favorable than the Company, and to market production at higher prices and on better terms than the Company. The ability of the Company to replace and add reserves, and generate revenues in the future will be dependent on the Company's ability to select, acquire and develop suitable producing properties and market its production and pipeline capacity in competition with these companies and individuals.
In addition to competition in oil and natural gas exploration and production activities, there is intense competition in the marketing and transportation of oil and natural gas. Because the revenues from the Company's production, transportation and other services are dependent upon the ability of the Company and other oil and gas producers to locate and maintain markets for oil and gas production, the marketing of oil and gas by the Company and by other producers or marketers transporting gas through the Blue Dolphin Pipeline and the Buccaneer Pipeline is of great importance to the Company. In general, gas sellers have numerous competitors, including marketing affiliates of interstate pipelines, the major integrated oil companies, gas producers and pipelines, and local and national gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Notwithstanding Order No. 636 (discussed below) the Company believes that some of the marketing affiliates of interstate pipelines may enjoy competitive advantages over independent gas marketers, including the Company. Certain competitors, such as the major producers, have capital resources many times greater than the Company and control substantially greater supplies of gas. Local utilities and distributors of gas are, in some cases, engaged directly and through affiliates in marketing activities that may compete with those of the Company and other producers transporting gas through the Blue Dolphin Pipeline.
MARKETS
The availability of a ready market for natural gas and oil, and the prices of such natural gas and oil, depend upon a number of factors which are beyond the control of the Company. These include, among other things, the level of domestic production, the availability of imported oil and gas, actions taken by foreign oil and gas producing nations, the availability of pipelines with adequate capacity and other transportation facilities, 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, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and alternative fuels.
Accordingly, in view of the many uncertainties affecting the supply and demand for crude oil, natural gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the natural gas and oil obtained as a result of the Company's operations.
Notwithstanding increases in natural gas prices over the last several years, the prices of crude oil, natural gas, and refined petroleum products, generally, have declined significantly in the past ten years as a result of an oversupply of a number of fuels, including certain petroleum products such as natural gas, gasoline and fuel oils, relative to the demand for such products. The spot market price for certain grades of crude oil has declined from a high price of approximately $40 per Bbl in 1981 to an average of approximately $15 per Bbl in 1994, discounting volatile market fluctuations.
GOVERNMENTAL REGULATION
The production, processing, marketing and transportation of oil and natural gas 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 sale for resale of natural gas in interstate commerce are regulated pursuant to the NGA and the NGPA. Both statutes are administered by the FERC.
The Natural Gas Wellhead Decontrol Act of 1989 removed all NGPA and NGA price and non-price controls affecting wellhead sales of gas effective January 1, 1993. The FERC still has general investigatory and other powers under both the NGA and the NGPA which now largely apply to transportation of natural gas in interstate commerce. Failure to comply with the terms of the NGPA, the NGA, other applicable legislation or the regulations promulgated thereunder may result in the imposition of civil or criminal penalties.
In April 1992, FERC issued Order No. 636, which calls for the unbundling of pipelines' merchant and transportation functions. The goal of Order No. 636, as amended by Order Nos. 636-A and 636-B, is to enhance competition in the industry through maximum efficient, flexible use of the national grid. Among other things, Order No. 636 (i) requires interstate pipelines to provide transportation and storage services to all customers (including third-party gas sellers) on a comparable basis, (ii) requires interstate pipelines to design their rates using a straight-fixed-variable methodology, under which all of the pipeline's fixed costs are allocated to the pipeline's reservation charges, and (iii) provides several mechanisms by which unused interstate pipeline transportation capacity can be reallocated in the marketplace. Although the pipelines have gone through Order No. 636 restructuring, the specific details of each interstate pipeline's restructuring are continuing to evolve through compliance filings and subsequent rate cases.
While Order No. 636 will not directly regulate the Company's activities, it may have an indirect effect because of its broad scope. In particular gas consumers, producers, certain interstate pipelines and independent gathering companies such as BDPC have expressed concern to FERC in various forums that "straight-fixed-variable to the wellhead" rate design (which results in effectively zero-rate interstate pipeline fees for production area transportation due to subsidies paid by market-area customers) is in fact an anticompetitive "tying". FERC has instituted industry-wide reevaluation of this rate design in the production area in a generic proceeding. Meanwhile, BDPC is among the parties objecting to institution of this rate design in a pending FERC rate case of Transcontinental Gas Pipe Line Corporation, a large interstate pipeline whose offshore laterals straddle BDPC. BDPC has testified in that case that to the extent that Transco is correct in alleging that Transco's lack of this rate design handicaps Transco in competing against pipelines able to employ it, the same disadvantages Transco alleges would impact BDPC as well. Nonetheless, BDPC's testimony has also pointed out that notwithstanding Transco's allegations of competitive disadvantage, Transco's throughput has actually increased during the period in question. In early 1995, The Williams Companies, whose Williams Gas Marketing subsidiary made essentially the same arguments as BDPC to oppose Transco's rate design proposal as grossly anticompetitive, acquired Transco. Accordingly, it is unclear how Transco under its new management will be able to persist with this proposal. Thus it is not only infeasible to predict whether Transco will be able to employ this rate design, it is also infeasible to predict what impact Transco's use of firm-to-the-wellhead rates would have on BDPC. It is possible, however, that if Transco is able to institute this rate design, BDPC may anticipate difficulty in competing to attract new production in the future. In addition, Order No. 636 will bring a degree of confusion and uncertainty to interstate natural gas sales and transportation for an unknown period of time.
Some of the above-described orders are subject to further revision by FERC or the courts and it is currently unclear how and when those orders will be resolved or further modified. The Company cannot accurately predict how the above-described laws and regulations, or future laws and regulations, will affect its operations.
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.
DECERTIFICATION OF BLUE DOLPHIN PIPELINE. On February 5, 1992, the FERC issued a Declaratory Order granting BDPC's petition which had requested a finding that the pipeline and facilities are exempt from further FERC jurisdiction under the NGA by virtue of that act's gathering exemption. In a subsequent ruling in February 1994, the FERC cited with approval the February 5, 1992, BDPC Declaratory Order, when it issued an order granting nonjurisdictional gathering status to a 20- inch, 95-mile offshore pipeline with characteristics far closer to those of an interstate pipeline than BDPC. Nonetheless, in that same February 1994 order, FERC stated that nonjurisdictional gathering lines, as well as interstate pipelines, are fully subject to the open access and nondiscriminatory requirements of Section 5 of the Outer Continental Shelf Lands Act (OCSLA) which generally authorizes FERC to insure that natural gas pipelines on the OCS will transport for non-owner shippers in a nondiscriminatory manner and will be operated in accordance with certain pro-competitive principles. Since BDPC already operates on the basis required under OCSLA, the Company does not anticipate significant changes resulting from this ruling. If however, BDPC's throughput increases to the extent that the pipeline is completely utilized, under OCSLA, FERC may be petitioned to direct capacity allocation on BDPC. Accordingly, the Company cannot predict how application of the OCSLA to BDPC may ultimately affect Company operations.
Aside from OCSLA requirements and federal safety and operational regulations, regulation of natural 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 currently 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 October 1993, FERC issued Order No. 561, whose intent was to simplify oil pipeline ratemaking, largely through use of a ceiling based on an indexing system. At the same time, FERC launched an inquiry to explore ways to improve the collection of data on oil pipeline costs. Because operation of Order No. 561 has not yet come fully into play, the Company cannot predict whether or how an indexed rate system will affect the Buccaneer Pipeline's rates. Similarly, it is not possible to predict the impact of possible additional reporting requirements.
FEDERAL OIL AND GAS LEASES. The Company's operations conducted on the Buccaneer Field leases and any other Company operations conducted on federal oil and gas leases 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. Moreover, on certain federal leases, prior approval of drillsite locations must be obtained from the Environmental Protection Agency ("EPA").
With respect to any Company operations conducted on offshore federal leases, including operations in the Buccaneer Field, liability may generally be imposed under the Outer Continental Shelf Lands Act ("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 when production ceases, although the MMS is considering the establishment of procedures under which certain of such facilities may be left in place, with EPA approval. See "Oil and Gas Exploration and Production Activities - The Buccaneer Properties".
ENVIRONMENTAL REGULATIONS. The Company may generally be liable for defined clean-up costs to the U.S. Government, with respect to its operations on both onshore and offshore properties, under the Federal Clean Water Act for each incident of oil or hazardous substance pollution and under the Comprehensive Environmental Response, Compensation and Liability Act of 1981, as amended (Superfund), for hazardous substance contamination. Such liability may be unlimited in cases of negligence or willful misconduct, and there is no limit on liability for environmental clean-up costs or damages with respect to claims by the states or by private persons or entities. In addition, the EPA requires the Company to obtain permits to authorize the discharge of pollutants into navigable waters. State and local permits and/or approvals may also be needed with respect to wastewater discharges and air pollutant emissions. Violations of environmental related lease conditions or environmental permits can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
PROPOSED LEGISLATION AND RULEMAKING. On August 25, 1993, the MMS published an Advance Notice of Proposed Rulemaking. The MMS announced its intent pursuant to the Oil Pollution Act of 1990 ("OPA 90") to publish regulations governing the establishment of financial responsibility and requested comments from interested parties thereto. These regulations, as initially proposed, will increase the current level of financial responsibility from $35,000,000 to $150,000,000 for certain offshore operations. The Company currently maintains the statutory $35,000,000 coverage.
In response to overwhelming opposition to this proposal from the Company and virtually all other industry parties, the Department of the Interior announced in December 1994 the appointment of a special advisory group that will recommend ways to implement OPA 90 without causing severe economic damage. This group will explore ways to implement the financial responsibility requirements of the new law, including legislative proposals to avert severe economic consequences Congress may not have intended. Nonetheless, the Company cannot predict how these rules and/or future laws, will affect its operations.
Legislative proposals and administrative rules and regulations are pending in Congress and in the legislatures of various states and at federal agencies, that, if enacted, could significantly affect the oil and gas industry. These include proposals by FERC and Congress to streamline the certification process for certain types of pipelines, and several Congressional energy bills and executive branch energy initiatives which have as their goal the decreased reliance by the United States on foreign energy supplies. It is impossible to predict which of these state and federal 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, or otherwise relating to the protection of the public health and the environment, may affect the Company's operations, expenses and costs. The trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes, and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations may result in increased operating costs for the Company and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations will continue to increase. In addition, the Company is subject to laws and regulations concerning occupational health and safety. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental or occupational health and safety laws and regulations, but in as much as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance.
ITEM 2.



ITEM 2. PROPERTIES
Information appearing in Item 1 describing the Company's properties under the caption "Business and Properties" is incorporated herein by reference.
In addition, the Company leases, under a lease expiring September 30, 1998, 6,069 square feet for its corporate and subsidiaries' executive offices in Houston, Texas.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
Neither the Company nor any of its property is subject to any material pending legal proceeding.
ITEM 4.

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, 1994.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock trades in the over-the-counter market and is quoted on NASDAQ under the symbol "BDCO". As of March 15, 1995, there were an estimated 1000 stockholders of record of the Common Stock. NASDAQ quotations reflect inter-dealer prices, without adjustment for retail mark-ups, mark-downs or commissions and may not represent actual transactions. The following table sets forth, for the periods indicated, the high and low closing bid and ask quotations for the Common Stock, as reported on NASDAQ.
Bid Ask High Low High Low ---- --- ---- ---
Quarter Ended March 31, 1993.......... 0.06 0.03 0.09 0.06 Quarter Ended June 30, 1993........... 0.38 0.03 0.47 0.06 Quarter Ended September 30, 1993...... 0.41 0.19 0.47 0.25 Quarter Ended December 31, 1993....... 0.34 0.25 0.41 0.28 Quarter Ended March 31, 1994.......... 0.59 0.31 0.63 0.38 Quarter Ended June 30, 1994........... 0.50 0.34 0.53 0.38 Quarter Ended September 30, 1994...... 0.41 0.28 0.44 0.31 Quarter Ended December 31, 1994....... 0.28 0.19 0.34 0.25
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. The Company is restricted, pursuant to the Loan Agreement, from paying dividends on Preferred and Common Stock. In addition, the Company is in arrears on payment of dividends on its Preferred Stock which imposes limits on the payment of dividends on the 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. The Company has not declared or paid any dividends on the Common Stock since its incorporation.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The comparative selected financial data of the Company and its consolidated subsidiaries is presented for the fiscal years ended December 31, 1994, 1993, 1992, 1991, and 1990. Such information should be read in conjunction with Item 7.

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 of the Company and Subsidiaries included elsewhere in this report.
For the year ended December 31, 1994, revenues increased $1,572,435 or 30% to $6,792,765 compared to revenues of $5,220,330 reported for the year ended December 31, 1993. Pre-tax earnings increased $1,053,265 or 75% to $2,450,163 compared to 1993 pre-tax earnings of $1,396,898. Net income increased $686,900 or 80% to $1,542,699 compared to 1993 net income of $855,799.
Results for both 1994 and 1993 included extraordinary gains from early retirement of debt. After tax gains of $612,040 and $497,105 were realized in 1994 and 1993, respectively. Excluding the extraordinary gains, 1994 net income increased 159% to $930,659 compared to $358,694 in 1993.
Results for 1994 included provision for income taxes of $907,464, of which $809,663 is offset with an increase to paid in capital, reflecting utilization of net operating loss carryforwards that were incurred prior to a quasi-reorganization recorded at December 31, 1989.
FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 1994, the Company's working capital deficit (current assets less current liabilities) was $1,415,091, representing an improvement of $867,344 as compared with a working capital deficit of $2,282,435 at December 31, 1993.
The improvement in the Company's working capital position during 1994, was due to the refinancing of debt, which resulted in a decrease in accrued interest payable of approximately $434,000, and a reduction in accounts payable of approximately $1,036,000. These decreases were offset in part by the reclassification of accrued abandonment costs of approximately $365,000 from long- term to current, as a result of the physical abandonment of certain facilities in 1994, and a reduction in accounts receivable of approximately $343,000.
In January 1994, the Company arranged a $10,000,000 reducing revolving credit facility with Bank One, Texas, N.A. ("Loan Agreement"), with initial borrowing availability of $6,500,000. The borrowing availability and reducing amount are redetermined semi-annually. Effective March 1, 1995, the borrowing base was increased from $5,300,000 to $5,800,000, reducing by $150,000 per month beginning April 1, 1995. The facility was made available for debt retirement and consolidation, and to finance future working capital needs, including the acquisition of oil and gas reserve based assets. Upon consummation of the Loan Agreement in January 1994, the Company purchased and retired debt totalling $6,350,729 including interest, for approximately $5,460,000 with funds from the new facility. See Notes 3 and 5 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements:
Independent Auditors' Report............................
Consolidated Balance Sheets, at December 31, 1994 and 1993.
Consolidated Statements of Operations, for the years ended December 31, 1994, 1993, and 1992.............
Consolidated Statements of Stockholders' Equity, for the years ended December 31, 1994, 1993, and 1992.......
Consolidated Statements of Cash Flows, for the years ended December 31, 1994, 1993, and 1992.............
Notes to Consolidated Financial Statements..............
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None. PART III
In accordance with paragraph (3) of General Instruction G to Form 10-K, Part III of this Report is omitted because the Registrant will file with the Securities and Exchange Commission not later than 120 days after December 31, 1994, a definitive proxy statement pursuant to Regulation 14A involving the election of Directors. Reference is made to the sections of such proxy statement entitled "Ownership of Securities", "Election of Directors", "Executive Compensation" and "Transactions With Related Persons", which sections of such proxy statement are incorporated herein.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements:
Consolidated Balance Sheets, at December 31, 1994 and 1993.
Consolidated Statements of Operations, for the years ended December 31, 1994, 1993, and 1992.
Consolidated Statements of Stockholders' Equity, for the years ended December 31, 1994, 1993, and 1992.
Consolidated Statements of Cash Flows, for the years ended December 31, 1994, 1993, and 1992.
Notes to Consolidated Financial Statements.
(a) 3.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 Stock Designation of the Company dated December 11,
3.6 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 14, 1989
3.7 (2) Bylaws of the Company
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Preferred Stock
4.2 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock
4.3 (5) Specimen Form of Warrant Certificate
10.11 (3) Gas Purchase Agreement between Dow Chemical Company and Ivory Production Co. dated May 1, 1991
10.18 (4) Form of Consulting Agreement between Blue Dolphin Services Co. and Soil, Inc. dated July 22, 1992
10.19 (5) Fourth Amendment to Loan Agreement between Blue Dolphin Energy Company, MEI Mission Energy, Inc., Ivory Production Co., Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., and Soil, Inc., dated May 1, 1993
10.20 (5) First Amendment to Credit Facility Agreement between Blue Dolphin Energy Company and Soil, Inc., dated May 1, 1993
10.21 (5) Form of Non-negotiable Long-Term Convertible Note between Blue Dolphin Energy Company and Harris Kaffie, dated June 1, 1993
10.22 (5) Equipment acquisition lease between MEI Mission Energy, Inc., and Banc One Leasing Corporation, dated November 23, 1993
10.23 (5) Loan Agreement between Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., MEI Mission Energy, Inc., Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated January 14, 1994
10.24 Plan and Agreement of Merger between Petroport, L.C. and Blue Dolphin Acquisition Company
10.3 Blue Dolphin Energy Company 1985 Employee Stock Option Plan
21.1 List of Subsidiaries of the Company
23.1 Consent of Gerald W. DuPont Enterprises, Inc., independent petroleum engineers
27.1 Financial Data Schedule
(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.
(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, 1991 under the Securities and Exchange Act of 1934, dated March 27, 1992.
(4) Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1992 under the Securities and Exchange Act of 1934, dated March 30, 1993.
(5) Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1993 under the Securities and Exchange Act of 1934, dated March 30, 1994.
(b) Reports on Form 8-K
(1) Form 8-K dated March 23, 1995, relating to the acquisition of Petroport, L.C.
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 28, 1995
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 28, 1995 Michael J. Jacobson executive officer)
/s/ Brian Lloyd Treasurer, Secretary and March 28, 1995 Brian Lloyd Controller
/s/ Ivar Siem Chairman March 28, 1995 Ivar Siem
/s/ Harris Kaffie Director March 28, 1995 Harris Kaffie
/s/ Daniel Porter Director March 28, 1995 Daniel B. Porter
/s/ Michael Chadwick Director March 28, 1995 Michael Chadwick
/s/ Christian Hysing-Dahl Director March 28, 1995 Christian Hysing-Dahl
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, 1994 and 1993, 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, 1994. 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 conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in notes 1 and 4 to the consolidated financial statements, the Company changed its method of accounting for income taxes to adopt the provisions of Statement of Financial Accounting Standards No. 109, ACCOUNTING FOR INCOME TAXES, in 1993.
KPMG PEAT MARWICK LLP
Houston, Texas March 17, 1995
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1994 and 1993 Assets 1994 1993 ---- ---- Current assets: Cash and cash equivalents ........................ $ 434,157 650,933 Trade accounts receivable ........................ 774,362 1,117,352 Crude oil inventory, at market ................... 17,350 16,935 Prepaid expenses and other assets ................ 217,203 132,724 ---------- ---------- Total current assets .................. 1,443,072 1,917,944 ---------- ---------- Property and equipment, at cost: Oil and gas properties (full-cost method) ........ 18,156,320 17,770,980 Onshore separation and handling facilities ....... 1,917,186 1,877,316 Land ............................................. 1,700,000 1,700,000 Pipelines ........................................ 1,493,418 1,440,830 Other property and equipment ..................... 76,356 75,126 ---------- ---------- 23,343,280 22,864,252 Less accumulated depletion, depreciation and amortization .................................... 4,299,078 3,698,441 ---------- ---------- 19,044,202 19,165,811 ---------- ---------- Other assets ...................................... 272,064 -
Investment in government bonds, at cost which approximates market value, restricted ............ - 267,325 ---------- ---------- $20,759,338 21,351,080 ========== ==========
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1994 and 1993
Liabilities and Stockholders Equity 1994 1993 ---- ---- Current liabilities: Trade accounts payable .......................... $ 606,065 $ 1,641,835 Current portion of long-term debt ............... 1,392,299 1,545,038 Current portion of accrued abandonment costs .... 716,144 351,000 Accrued interest payable ........................ 50,566 484,679 Other liabilities and accrued expenses .......... 37,689 114,827 Income taxes payable ............................ 55,400 63,000 ---------- ---------- Total current liabilities ............ 2,858,163 4,200,379 __________ __________ Long-term debt, less current portion ............. 4,450,000 2,642,303
Convertible subordinated notes ................... - 2,500,000
Accrued abandonment costs, less current portion .. 1,924,321 2,982,489
Dividends payable on preferred stock ............. 1,456,442 1,165,238 ---------- ---------- Total long-term liabilities .......... 7,830,763 9,290,030
Stockholders' equity: Cumulative convertible preferred stock, Series A, $.10 par value, 25,000,000 shares authorized, 14,560,475 shares issued and outstanding at December 31, 1994 and 1993 ...... 1,456,048 1,456,048
Common stock, $.01 par value, 100,000,000 shares authorized, 34,379,116 shares issued and outstanding at December 31, 1994; 33,651,507 shares issued and outstanding at December 31, 1993 ............... 343,791 336,515
Additional paid-in capital ...................... 13,210,354 12,259,384
Accumulated deficit since January 1, 1990 ....... (4,939,781) (6,191,276) ---------- ---------- Total stockholders equity ............ 10,070,412 7,860,671 ---------- ---------- Commitments and contingencies .................... $ 20,759,338 21,351,080 ========== ========== See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended December 31, 1994, 1993 and 1992
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended December 31, 1994, 1993 and 1992
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 1994, 1993 and 1992
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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, processing and marketing. It was formed for the purpose of changing the domicile and combining the business and properties of ZIM Energy Corporation, a Texas corporation founded in 1983, and Petra Resources, Inc., an Oklahoma corporation founded in 1980, pursuant to a reorganization effective June 9, 1986. During the year ended January 31, 1988, ZIM Energy Corporation changed its name to Mustang Resources Corp.
On January 5, 1990, Mustang Resources Corp. changed its name to Blue Dolphin Energy Company.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
CASH AND CASH EQUIVALENTS
Cash includes all currency and any liquid investments with an original maturity of three months or less. See notes 5 and 7 for discussion of significant noncash investing and financing activities.
CRUDE OIL INVENTORY
Inventory represents crude oil in storage tanks at the Company's shore facility near Freeport, Texas. Such inventories are recorded at their fair market value as of the balance sheet date.
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 are capitalized on a country-by-country cost center basis. Amortization of such costs and estimated future development costs is determined using the unit-of-production method. Estimated proved oil and gas reserves are based upon reports of an independent petroleum engineer. The net carrying value of oil and gas properties 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.
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives of 10-15 years. In 1994, the Company extended the estimated useful lives for pipeline and facilities. The effect of the change in estimate is a decrease in depreciation of approximately $445,000 in 1994.
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.
GOVERNMENT BONDS
Investments in government bonds are recorded at cost which approximates market value and collateralized a portion of the Convertible Subordinated Notes which were redeemed in 1994. In May 1993, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, which is effective for fiscal years beginning after December 15, 1993. The Company believes that the adoption of this accounting standard has not had a significant impact on the consolidated financial statements.
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 made using the straight-line method over the estimated useful lives of the pipeline and pipeline facilities. These provisions are included in depletion, depreciation and amortization expense and accrued abandonment costs, respectively. The aggregate abandonment liability is estimated to be approximately $4,500,000 at December 31, 1994.
RECOGNITION OF CRUDE OIL REVENUE
Revenue from crude oil produced and sold from the Buccaneer Field is recognized when such crude oil is produced rather than when sold.
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.
INCOME TAXES
In February 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, ACCOUNTING FOR INCOME TAXES (Statement 109). Statement 109 requires a change from the deferred method of accounting for income taxes of APB Opinion 11 to the asset and liability method of accounting for income taxes. Under the asset and liability method of Statement 109, deferred tax assets and liabilities are recognized for the 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. Under Statement 109, 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.
Effective January 1, 1993, the Company adopted Statement 109. There was no cumulative effect of the change in the method of accounting for income taxes.
NET INCOME (LOSS) PER SHARE
Net income (loss) per common share is computed after consideration of dividend requirements on preferred stock, using the weighted average number of common shares outstanding and common share equivalents during each of the years presented. Outstanding stock options and warrants are common share equivalents and are considered when the effect is dilutive. Cumulative convertible preferred stock and convertible debt are other potentially dilutive securities and are considered in fully diluted net income (loss) per share when the effect is dilutive.
RECLASSIFICATIONS
Certain reclassifications have been made to prior year financial statements to conform with the current year presentation.
(2) QUASI-REORGANIZATION
In connection with the Company's emergence from Chapter 11 proceedings in 1989, the Board of Directors authorized the Company to revalue its consolidated balance sheet at December 31, 1989 to fair value in accordance with principles of accounting for quasi-reorganizations. The principal adjustments to fair value included an $810,000 increase in the carrying value of land and the elimination of the remaining deferred debt offering costs associated with the Convertible Subordinated Notes of $994,192, resulting in a net charge to the accumulated deficit of $184,192.
The Company's remaining assets and liabilities at December 31, 1989 approximated fair value; accordingly, the accumulated depletion, depreciation and amortization at December 31, 1989 was eliminated against the original cost of the assets. The accumulated deficit of $14,031,556 at December 31, 1989 was then transferred to additional paid-in capital. Any benefits realized upon the utilization of tax operating losses generated prior to January 1, 1990 will be credited to additional paid-in capital (see note 4).
(3) LIQUIDITY
At December 31, 1994, the Company has negative working capital of approximately $1,400,000.
In January 1994, the Company entered into a reducing revolving credit facility with Bank One, Texas, NA, in the amount of $10,000,000. At March 1, 1995, the borrowing availability was $5,800,000 reducing by $150,000 per month beginning April 1, 1995. The balance borrowed under the agreement was $5,800,000 at March 17, 1995. The borrowing availability and reducing amount are to be redetermined semiannually or on such other frequency as requested by the Company. Determination of the borrowing availability is significantly impacted by third party reserves producing into the Company's Blue Dolphin Pipeline System.
During the first quarter 1995, producer/shippers of two Galveston Area fields transporting production through the Blue Dolphin Pipeline, drilled and completed new wells with production commencing late first quarter 1995. A third existing producer/shipper began drilling an additional development well in March 1995. Additionally, two new field discoveries have recently been reported in Galveston Area lease blocks in the vicinity of the Blue Dolphin Pipeline. The Company is aggressively competing to attract these producer/shippers to the Blue Dolphin Pipeline System. Tie-in decisions are expected to be made during the second quarter 1995 and production operations are expected to commence during the third quarter 1995 for both fields. As the pipeline system is currently being utilized at less than full capacity, additional revenues can be generated in excess of additional operating expenses.
Management expects that funds available from the reducing revolving credit facility and funds generated through its regular operations will provide sufficient liquidity to meet its anticipated obligations during 1995.
To the extent funds from operations are not sufficient to meet obligations when they become due, the Company may be required to seek additional equity or debt financing, defer its development or discretionary capital expenditures, or seek other financing alternatives.
(4) INCOME TAXES
As discussed in note 1, the Company adopted Statement 109 as of January 1, 1993. There was no cumulative effect of the change in the method of accounting for income taxes. Prior years' financial statements were not restated to apply the provisions of Statement 109.
For 1992, the Company did not record a provision for income tax benefits related to operating losses.
Total income taxes were allocated as follows for 1994 and 1993:
1994 1993 -------- ------- Income from continuing operations ........................ $592,171 280,237 Extraordinary gains ...................................... 315,293 260,862 Stockholders' equity, related to gain on refinancing of notes to related parties (see note 5) ............. -- 36,430 -------- ------- $907,464 577,529 ======== =======
Income tax expense attributable to continuing operations for 1994 and 1993 consists of:
Current Federal .......................................... $ 29,000 40,000 State ............................................ 68,801 23,000 Deferred federal-charge in lieu of taxes ........... 494,370 217,237 -------- ------- $592,171 280,237 ======== =======
During 1994 and 1993, the valuation allowance decreased approximately $809,000 and $500,000, respectively. As a result of the quasi-reorganization described in note 2, the benefits of such reductions have been recorded directly to stockholders' equity and the statements of operations include a charge in lieu of taxes, allocated as described above.
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, 1994 and 1993 are presented below.
1994 1993 ----------- ---------- Deferred tax assets: Accrued abandonment costs ..................... $ 481,050 1,133,386 Net operating loss carryforwards .............. 5,447,812 5,539,321 Alternative minimum tax credit ................ 69,000 40,000 ----------- ---------- Total gross deferred tax assets ......... 5,997,862 6,712,707 Less valuation allowance ................ (2,272,003) (3,081,666) ----------- ---------- Net deferred tax assets ................. 3,725,859 3,631,041 Deferred tax liabilities: Bases differences in property and equipment ... (3,725,859) (3,631,041)
Net deferred tax liability .............. $ -- --
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company has established a valuation allowance for such deferred tax assets to the extent such amounts are not expected to be realized as a reduction in future taxable income generated from existing deferred tax liabilities.
If income tax benefits related to the valuation allowance are recognized subsequent to December 31, 1994, approximately $1.1 million will be allocated to stockholders' equity (see note 2).
The Company's effective tax rate applicable to continuing operations in 1993 and 1994 differs from the expected tax rate of 34% due to the following:
1994 1993
Expected tax rate ...................................... 34% 34% State taxes, net of federal benefit .................... 3 2 Expenses not deductible for tax purposes ............... 2 8 -- -- 39% 44%
At December 31, 1994, the Company had the following estimated net operating loss carryforwards (NOL) for tax reporting purposes:
Year of Net operating loss EXPIRATION CARRYFORWARDS ---------- ------------- 2001 ............................... $ 3,306,730 2002 ............................... 4,081,357 2003 ............................... 2,217,525 2004 ............................... 2,167,468 2005 ............................... 2,572,302 2006 ............................... 1,099,663 2007 ............................... 402,349 2008 ............................... 175,580 ------------ $ 16,022,974
The Tax Reform Act of 1986 significantly limits the amount of NOL available to offset future taxable income when a change in ownership occurs. Such a limitation of the NOL in a given year could prevent the Company from realizing the full benefit of the NOL within the 15 year statutory limit. The Company had two changes in ownership prior to 1994. The Company believes that the limitation, if any, would not have a significant impact on the consolidated financial statements.
(5) LONG-TERM DEBT
In January 1994, the Company arranged a reducing revolving credit facility (Loan Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of $10,000,000, with an initial availability of $6,500,000 reducing $217,000 per month beginning February 1, 1994. The borrowing availability and reducing amount are to be redetermined semi-annually. Beginning March 1, 1994 and the first day of each month thereafter, interest is due and payable on the outstanding loan balance at the rate of 1.5% above Bank One's prime rate of interest. Borrowings under the Loan Agreement are secured by first liens on the Buccaneer Field, the Blue Dolphin Pipeline, the Buccaneer Pipeline, the Freeport, Texas acreage and the shore facilities. The Loan Agreement matures January 14, 1997.
The Loan Agreement includes certain restrictive covenants, including a restriction of the payment of dividends on capital stock and the maintenance of certain financial coverage ratios.
Upon consummation of the Loan Agreement in January 1994, the Land Note, the Credit Facility, the Senior Debt, and $2,000,000 of the Series B notes (see note 6), totaling $6,350,729 including accrued interest, were retired for approximately $5,460,000. The resulting gain was recorded as an extraordinary item.
Long-term debt at December 31, 1994 and 1993 is as follows:
Maturities of long-term debt as of December 31, 1994 are as follows:
1995 $ 1,392,299 1996 1,800,000 1997 2,650,000 ----------- $ 5,842,299 ===========
In connection with the gain on refinancing of notes to related parties, as described in the table above, approximately $106,000 of accrued interest was forgiven in 1993. Such amount is included as interest expense for 1993 and earlier years and an increase to additional paid-in capital, representing contributions from stockholders.
(6) CONVERTIBLE SUBORDINATED NOTES
In June 1986, the Company issued $8,000,000 of 7-1/2% convertible subordinated notes due 2001, convertible at $4.80 per share into 2,083.25 shares of common stock for each $10,000 note. Pursuant to the note agreement, a portion of the proceeds were reserved as collateral. At December 31, 1993, $500,000 face amount of the notes were collateralized by government bonds scheduled to mature in May 2001 for $500,000. The remaining $2,000,000 of the notes at December 31, 1993 were collateralized by a third lien on oil and gas properties. The net proceeds of the notes were originally used to acquire and develop oil and gas properties.
In 1994, $500,000 of the notes collateralized by government bonds, plus accrued interest of approximately $25,000, were purchased at a cost of approximately $470,000. The remaining $2,000,000 of the notes, plus accrued interest of approximately $87,500, were purchased at a cost of approximately $1,250,000. The applicable portion of the government bonds collateralizing the notes purchased was released to the Company and sold. The $928,000 gain on the early retirement of these notes and the indebtedness in note 5 was recorded as an extraordinary item in 1994.
In 1993, $1,600,000 of the notes collateralized by government bonds, plus accrued interest of approximately $82,000, were purchased at a cost of approximately $924,000. The applicable portion of the collateral for the notes purchased was released to the Company and sold. The $758,000 gain on the early retirement of these notes was recorded as an extraordinary item.
In 1992, $400,000 of the notes collateralized by government bonds were purchased at a cost of approximately $215,000. The applicable portion of the collateral for the notes purchased was released to the Company and sold. The $185,000 gain on the early retirement of these notes was recorded as an extraordinary item.
(7) STOCKHOLDERS' EQUITY
Each share of series A cumulative convertible preferred stock, $.10 par value, is entitled to receive dividends in the annual amount of $.02 per share on each June 30, which are cumulative from the date of issue, are convertible at the option of the holders of the preferred stock into one share of the Company's $.01 par value common stock, are redeemable at the option of the Company for $.20 per share, has a preference in liquidation equal to $.20 per share and the accrued dividends on the date thereon, and have equal voting rights with the common stock, except that the holders of the preferred stock are entitled to elect a majority of the Board of Directors in the event of certain dividend arrearages. As of December 31, 1994, the holders of the preferred stock are entitled to elect a majority of the Board of Directors, and currently do exercise such control of the Board of Directors. The Company has not declared or paid any dividends since the date of issuance; accordingly, $1,456,442 of dividends are in arrears and have been accrued as of December 31, 1994. As a result of the debt refinancing described in note 5, dividends are prohibited from being paid until the bank credit facility indebtedness is retired. Accordingly, the accrued dividends have been reclassified from current liabilities to noncurrent liabilities at December 31, 1994. The dividend arrearages restrict the Company's ability to pay common dividends or reacquire common stock. The reacquisition of common stock during 1993 was approved by the Board of Directors, which as described above, is controlled by holders of the preferred stock.
At December 31, 1994, the Company has reserved a total of approximately 2,447,000 shares of common stock for issuance under its stock option plan. 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:
PRICE PER SHARE --------------------- SHARES FROM TO ---------- --------- ------ Balance, December 31, 1992 .......... 2,050,000 $ .0625 .3453 Granted .......................... 550,000 .1594 .1594 Exercised ........................ (744,998) .0625 .3453 Terminated ....................... (25,000) .2125 .2125 ---------- --------- ------ Balance, December 31, 1993 .......... 1,830,002 $ .0625 .3453 Granted .......................... 735,000 .2922 .2922 Exercised ........................ (436,668) .0625 .2125 ---------- --------- ------ Balance, December 31, 1994 .......... 2,128,334 $ .0625 .3453 ========== ========= ======
As of January 1, 1995, 745,002 options are immediately exercisable.
Outstanding options at December 31, 1994 expire between April 5, 1995 and August 9, 1999. The Plan specifies that the options are exercisable as granted; however, generally only one-third of options granted are exercisable in any one year. Employees must continue their employment with the Company for one year after exercising the options, or the underlying stock reverts to the Company.
The outstanding exercisable warrants to purchase shares of the Company's common stock, issued in connection with the 1993 debt refinancings described in note 5, are as follows: PRICE PER SHARE --------------- SHARES FROM TO ----------- ----- ---- Balance, December 31, 1992 .............. -- $ -- -- Granted ................................. 17,257,140 0.10 0.10 ----------- ----- ---- Balance, December 31, 1993 .............. 17,257,140 0.10 0.10 Exercised ............................... (420,941) 0.10 0.10 ----------- ----- ---- Balance, December 31, 1994 .............. 16,836,199 $ 0.10 0.10 =========== ===== ====
Outstanding warrants at December 31, 1994 are immediately exercisable and expire April 30, 1996.
The Company has reserved 14,560,475 shares of common stock in the event the series A convertible preferred stock is fully converted and 16,836,198 shares of common stock in the event the outstanding warrants are exercised.
(8) RELATED PARTY TRANSACTIONS
Significant related party transactions which are not disclosed elsewhere in these consolidated financial statements are discussed in the following paragraphs.
In 1993, the Company paid $20,000 to a director for financial advisory services rendered in association with financing activities and debt restructuring.
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 $37,500 under the contract in 1992, $90,000 in 1993, and $90,000 in 1994.
(9) LEASES
The Company is obligated under a capital lease for a vapor recovery unit that has been capitalized and is included in property, plant and equipment. The lease expires in 1995.
In addition, the Company has various noncancelable operating leases which continue through 1998.
The following is a schedule of future minimum lease payments under capital lease obligations (the principal of which is recorded in long-term debt) and rental payments required under long-term noncancelable operating leases at December 31, 1994:
YEARS ENDING CAPITAL OPERATING DECEMBER 31, LEASE LEASES ------------ ----- ------ 1995 $ 203,510 225,576 1996 -- 125,526 1997 -- 103,176 1998 -- 77,382 --------- -------- $ 203,510 531,660 ========= =======
Rental expense under operating leases for the years indicated were as follows:
YEARS ENDED DECEMBER 31, ------------ 1994 $ 225,576 1993 185,019 1992 86,299 ========
(10) COMMITMENTS AND CONTINGENCIES
In November 1992, the Company entered into a Farmout Agreement with a third party, wherein the third party will earn an interest in certain of the non-producing and undeveloped acreage in the Buccaneer Field through the successful drilling and development of the acreage. The Company will retain an overriding royalty interest convertible at the Company's election to a working interest upon Project Payout. In January 1993 the initial well under the Farmout Agreement was drilled and production casing was set. As a result of regulatory delays, the well was not completed until March 1994. Production from this initial well commenced in March 1994. Drilling of a second well under the Farmout Agreement resulted in a dry hole. The drilling option under which interest in additional acreage can be earned will expire March 27, 1995.
As a result of filing development plans for the contemplated wells under the Farmout Agreement, the United States Department of the Interior, Minerals Management Service (MMS) required the Company's wholly-owned subsidiary, Ivory Production Co. (Ivory) to provide additional security to ensure it could meet the future abandonment obligations associated with the Buccaneer Field. In February 1994, Ivory and the MMS agreed on the form of such security and the amount of the future obligations.
As additional security for the future Buccaneer Field abandonment obligations, in February 1994, Ivory provided the MMS with a $700,000 supplemental surety bond. The bond will be fully funded over approximately a six year period, through the escrowing with the surety of $10,000 per month. Such escrow funding began in February 1994.
A sinking fund was established in 1994 wherein the greater of the net proceeds from the Farmout acreage or $250,000 annually will be set aside until a total of approximately $2,400,000 has been accumulated to meet end of lease abandonment and site clearance obligations. Ivory estimates the remaining useful life of its major Buccaneer Field facilities to be in excess of ten years.
To meet current abandonment obligations, in November 1993, a "turnkey" agreement was arranged with a third party contractor to physically plug and abandon certain wells and satellite platform facilities for which there was no further utility in future field development. Work to abandon the facilities was completed in June 1994, at a cost of approximately $1,990,000. Vendor financing was provided under the agreement. Remaining payments of approximately $720,000 and $532,000 are payable during 1995 and 1996, respectively and are included in accrued abandonment costs.
In July 1994, the Company entered into a Regional 3-D Seismic Data Acquisition and Purchase Agreement with a third party provider of seismic data which provides the Company access to the third party's 3-D and 2-D seismic data base. The Company's minimum commitment during the five-year term of the agreement is $1,500,000.
(11) BUSINESS SEGMENT INFORMATION
The Company conducts its operations in two principal business segments: oil and gas exploration and production, and pipeline operations. Intersegment revenues consist of transportation, processing and storage fees charged by wholly-owned subsidiaries to another for natural gas and crude oil transported through the pipeline and pipeline system. The intercompany revenues and expenses are eliminated in consolidation. Information concerning these segments for the years ended December 31, 1994, 1993 and 1992 is as follows:
(1) Consolidated income (loss) from operations includes $380,558, $403,955 and $395,817 in unallocated general and administrative expenses for the years ended December 31, 1994, 1993 and 1992, respectively.
(2) Pipeline depletion, depreciation and amortization includes a provision for pipeline abandonment of $39,420 for the year ended December 31, 1994 and $360,000 for each of the years ended December 31, 1993 and 1992. Oil and gas depletion, depreciation and amortization includes a provision for abandonment costs of platforms and wells of $33,760, $58,490, and $62,339 for the years ended December 31, 1994, 1993 and 1992, 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 $179,331 were incurred for pipeline operations for the year ended December 31, 1994.
The Company's primary market area is the Texas Gulf Coast region of the United States. For the year ended December 31, 1994 and prior years the Company had a concentration of credit risk with customers in the energy and chemical 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. Management believes that the concentration of credit risk referred to above will decrease with the addition of new fields to the Blue Dolphin pipeline system. Revenues from major customers exceeding 10% of segment revenues were as follows for the periods indicated:
(12) SUBSEQUENT EVENTS
In March 1995, the Company completed acquisition of Petroport, L.C. Petroport, L.C. holds proprietary technology, represented by certain patents issued and or pending, associated with the development and operation of an offshore deepwater crude oil and products port and storage facility. The form of the transaction was a merger of Petroport, L.C. into Petroport, Inc., a wholly-owned subsidiary of the Company.
Consideration paid included $150,000 cash and future consideration contingent upon the successful development and operation of the primary Petroport facility, planned for the western Gulf of Mexico off the Texas coast. The contingent consideration includes $350,000 to be paid when the Company obtains funding for the licensing and permitting phase of the project and 9,000,000 shares of Company common stock, with issuance dependent upon successful completion of the facility and maintaining a prespecified throughput volume.
(13) 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 Statement of Financial Accounting Standards No. 69 DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Statement 69).
At December 31, 1994 the Buccaneer Field accounted for 100% of the Company's future net cash flows from proved reserves.
The timing and amount of the 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.
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 natural gas reserves for the periods indicated, as estimated by the Company's independent petroleum engineer. 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 natural 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, 1991 ..... 655,488 30,699,281 Sale of reserves ............................... (222,498) -- Revisions to previous estimates ................ 21,437 2,843,620 Production ..................................... (14,178) (518,031) ----------- ----------- Total proved reserves at December 31, 1992 ..... 440,249 33,024,870 Revisions to previous estimates ................ (212,289) 5,295,906 Production ..................................... (3,666) (554,346) ----------- -----------
Total proved reserves at December 31, 1993 ..... 224,294 37,766,430 ----------- ----------- Revisions to previous estimates ................ (25,098) (3,800,747) Production ..................................... (3,791) (490,587) ----------- ----------- Total proved reserves at December 31, 1994 ..... 195,405 33,475,096 =========== =========== Proved developed reserves: December 31, 1994 ............................ 119,327 20,351,150 December 31, 1993 ............................ 148,216 24,642,484 December 31, 1992 ............................ 280,820 21,867,545
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, ---------------------------- 1994 1993 ------------ ------------ Productive and nonproductive properties being amortized .............................. $ 18,156,320 17,770,980 Less accumulated depletion, depreciation and amortization ............................. 3,381,871 2,972,067 ------------ ------------ Net capitalized costs ................... $ 14,774,449 14,798,913 ============ ============ Accrued offshore platform and well abandonment costs ................ $ 1,888,580 1,053,488 ============ ============
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.
DECEMBER 31, ---------------------------- 1994 1993 1992 -------- -------- -------- Property acquisition costs - unproved properties . $ -- -- -- Exploration costs ................................ 136,290 45,701 35,689 Development costs ................................ 249,050 306,751 107,068 -------- -------- -------- $385,340 352,452 142,757 ======== ======== ======== Amortization expense per Mcf equivalent produced ........................ $ .86 .80 .76 ======== ======== ========
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, ----------------------------- 1994 1993 ------------ ------------ Future cash inflows .......................... $ 61,759,797 94,915,996 Future development costs ..................... (9,950,732) (11,668,045) Future production costs ...................... (14,238,221) (14,278,849) ------------ ------------ Future net cash inflows before income taxes ....................... 37,570,844 68,969,102 Future income taxes .......................... (9,700,652) (21,123,645) ------------ ------------ Future net cash flows ........................ 27,870,192 47,845,457 10% discount factor .......................... (12,661,504) (23,765,780) ------------ ------------ Standardized measure of discounted future net cash inflows ............. $ 15,208,688 24,079,677 ============ ============
Future net cash flows at each period-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, 1994, such prices were $16.00 per barrel and $1.75 per Mcf) and (2) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on current costs). Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and the post-December 31, 1989 estimated net operating loss carryforwards. The future income taxes computation gives effect to permanent differences but does not reflect the impact of future operations relating to the Company's proved oil and gas reserves (see note 4). 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 flows.
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 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: