ITEM 1. BUSINESS
FORWARD LOOKING STATEMENTS. Certain of the statements included below, including those regarding future financial performance or results or that are not historical facts, are or contain "forward-looking" information as that term is defined in the Securities Act of 1933, as amended. The words "expect," "plan," "believe," "anticipate," "project," "estimate," and similar expressions are intended to identify forward-looking statements. Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as "Blue Dolphin" or the "Company") cautions readers that any such statements are not guarantees of future performance or events and such statements involve risks, uncertainties and assumptions, including but not limited to industry conditions, prices of crude oil and natural gas, regulatory changes, general economic conditions, interest rates, competition, and other factors discussed below. Should one or more of these risks or uncertainties materialize or should the underlying assumptions prove incorrect, actual results and outcomes may differ materially from those indicated in the forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date hereof. The Company undertakes no obligation to publish revised forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. Readers are also urged to carefully review and consider the various disclosures made by the Company which attempt to advise interested parties of the factors which affect the Company's business, including the disclosures made under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report, as well as the Company's periodic reports on Forms 10-Q and 8-K filed with the Securities and Exchange Commission.
THE COMPANY
The Company is engaged in the acquisition and exploration of oil and gas properties, and the gathering and transportation of natural gas and condensate. In addition, the Company actively pursues midstream projects with long term revenue potential, such as the Petroport offshore oil terminal and the Avoca natural gas storage project. The Company's primary geographical focus areas are the western and central coasts of the U.S. Gulf of Mexico. The Company was incorporated in 1986 as the result of the corporate combination of ZIM Energy Corporation ("ZIM"), a Texas corporation founded in 1983, and Petra Resources, Inc., an Oklahoma corporation formed in 1980 ("Petra"). The Company succeeded to the business, properties and assets of ZIM and Petra. In June 1987, the Company changed its name from ZIM Energy Corp. to Mustang Resources Corp. In January 1990, the Company's name was changed to Blue Dolphin Energy Company. In December 1999 the Company acquired at 75% ownership interest in American Resources Offshore, Inc. ("ARO").
The Company is a holding company that conducts substantially all of its operations through its subsidiaries. The Company's principal assets are owned and operations conducted by its subsidiaries, Blue Dolphin Exploration Company ("BDEX"), a Delaware corporation, Mission Energy, Inc., a Delaware corporation d/b/a MEI Mission Energy, Inc. ("MEI"), Blue Dolphin Pipe Line Company ("BDPC"), a Delaware corporation, Buccaneer Pipe Line Co. ("BPC"), a Texas corporation, Blue Dolphin Services Co. ("BDSC"), a Texas corporation, Petroport, Inc.("Petroport"), a Delaware corporation, Black Marlin Energy Company, a Delaware corporation and Black Marlin Pipeline Company ("BMPC"), a Texas Corporation. Additionally, BDEX owns a 75% interest and manages the oil and gas operations of ARO, a Delaware corporation and BDEC owns a 25% interest and manages New Avoca Gas Storage LLC ("New Avoca"), a Texas limited liability company.
The principal executive office of the Company is located at 801 Travis, Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. ARO maintains a division office in New Orleans,
Louisiana. Shore base facilities are maintained in Freeport and Texas City, Texas serving Gulf of Mexico operations. The Company has 25 full-time employees. The Company's Common Stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") Small Cap Market under the trading symbol "BDCO". The Company's home page address on the world wide web is http://www.blue-dolphin.com.
BUSINESS AND PROPERTIES
The Company conducts its business activities in three primary business segments: (i) pipeline operations, (ii) oil and gas exploration and production, and (iii) development of high potential mid-stream projects. The Company owns and operates, through its subsidiaries, natural gas and condensate pipeline gathering facilities. The Company's oil and gas exploration and production activities include the exploration, acquisition, development, operation and, when appropriate, disposition of oil and gas properties. The Company also develops for sale to third parties, oil and gas exploration prospects in the Gulf of Mexico. See Note 10 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. The Company is also in varying stages of development of the Petroport offshore oil terminal project and the Avoca natural gas storage project.
PIPELINE OPERATIONS AND ACTIVITIES
The Company's pipeline assets are held and operations conducted by BDPC, MEI, BPC, and BMPC, all wholly owned subsidiaries of the Company.
PURCHASE AND SALE OF PIPELINE INTERESTS. On March 1, 1999 the Company acquired Black Marlin Pipeline Company from Enron Pipeline Company ("Enron"), for $5,404,270 cash. Black Marlin Pipeline Company is the owner of the 75 mile Black Marlin Pipeline System, as defined below. This acquisition was funded by selling a one-sixth (1/6) undivided interest in the Company's Blue Dolphin Pipeline System, the Black Marlin Pipeline System and the Omega Pipeline to WBI Southern, Inc. ("WBI") for $3,712,000 and selling a one-third (1/3) undivided interest in the Black Marlin Pipeline System to MCNIC Pipeline and Processing Company ("MCNIC") for $1,801,423. MCNIC owns a one-third (1/3) undivided interest in the Blue Dolphin Pipeline System and the Omega Pipeline.
BLUE DOLPHIN PIPELINE SYSTEM. The Company owns a 50% undivided interest in the Blue Dolphin Pipeline System (the "Blue Dolphin System"). The Blue Dolphin System includes the Blue Dolphin Pipeline, Buccaneer Pipeline, onshore facilities for condensate and gas separation and dehydration, 85,000 barrels ("Bbls") of above-ground tankage for storage of condensate, a barge loading terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and on which are located the pipeline system shore facilities, pipeline easements and rights-of-way.
The Blue Dolphin System gathers and transports natural gas and condensate from the Buccaneer Field and other offshore fields in the area to shore facilities located in Freeport, Texas. After processing, the gas is transported to an end user and a major intrastate pipeline system with further downstream tie-ins to other intrastate and interstate pipeline systems and end users. The Buccaneer Pipeline, an 8" condensate pipeline, transports condensate from the storage tanks to the Company's barge loading terminal on the Intracoastal Waterway near Freeport, Texas for sale to third parties.
The Blue Dolphin Pipeline consists of two segments. The offshore segment transports both natural gas and condensate and is comprised of approximately 36 miles of 20-inch pipeline from the Buccaneer Field platforms to shore and 4 miles to the shore facility at Freeport, Texas. Additionally, the
offshore segment includes 9 field gathering lines totalling approximately 55 miles, connected to the main 20-inch line. The System's onshore segment consists of approximately 2 miles of 16-inch pipeline for transportation of natural gas from the shore facility to a sales point at a Freeport, Texas chemical plants' complex and intrastate pipeline system tie-in.
Various fees are charged to producer/shippers for provision of transportation and shore facility services. Blue Dolphin System natural gas throughput averaged approximately 21% of capacity during 1999. Current system capacity is approximately 160 million cubic feet ("MMcf") per day of gas and 7,000 Bbls per day of condensate. During 1999, 99% of gas and condensate volumes transported were attributable to production from third party producer/shippers. See Note 10 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference.
BLACK MARLIN PIPELINE SYSTEM. The Company owns a 50% undivided interest in the Black Marlin Pipeline System (the "Black Marlin System"). The Black Marlin System includes the Black Marlin Pipeline, onshore facilities for condensate and gas separation and dehydration, 3,000 Bbls of above ground tankage for storage of condensate, a truck loading facility for oil and condensate, and 5 acres of land in Galveston County, Texas where the Black Marlin Pipeline comes ashore and on which are located the pipeline system's shore facilities.
BMPC is classified as a "natural gas company" pursuant to the Natural Gas Act of 1938 ("NGA") and the Black Marlin Pipeline is classified as an "interstate pipeline" pursuant to the Natural Gas Policy Act of 1978 ("NGPA") and thus subject to Federal Energy Regulatory Commission ("FERC") regulation. Gas and condensate from various producer/shippers in the High Island and Galveston Areas of the Gulf of Mexico are gathered and transported through the Black Marlin Pipeline to its shore facilities. After separation and dehydration, gas is transported to an industrial end user or to either of two major intrastate pipeline systems with further downstream tie-ins to other intrastate and interstate pipeline systems and end users. Condensate is either delivered to a liquids pipeline or transported by truck.
The Black Marlin Pipeline consists of two segments. The offshore segment transports natural gas and condensate and is comprised of approximately 67 miles of 16-inch pipeline from a High Island Block 136 platform, including an extension from a platform in High Island Block A-6, to an interconnection in High Island Block 137, across Galveston Bay to the onshore facilities at Texas City, Texas. The offshore segment also includes approximately 7 miles of 8-inch pipeline from a platform in High Island Block 199 to an interconnection with the main line in High Island Block 171. The onshore segment consists of approximately 2 miles of 16-inch pipeline from the shore facilities to an end user and pipeline system tie-ins. Various fees are charged to producer/shippers for provision of transportation and shore facility services. Black Marlin System natural gas throughput averaged approximately 28% of capacity during 1999. Current Black Marlin System capacity is approximately 200 MMcf per day of gas and 1,500 Bbls. per day of condensate. During 1999, all gas and condensate volumes were attributable to production from third party producer/shippers.
OTHER. The Company also holds a 50% undivided interest in the currently inactive Omega Pipeline, MCNIC holds a one-third (1/3) interest and WBI holds a one-sixth (1/6) interest. The Omega Pipeline originates in West Cameron Block 342 and extends to High Island, East Addition Block A-173, where it was previously connected to the High Island Offshore System ("HIOS"). The line could either be reconnected to HIOS, or a lateral pipeline could be constructed connecting into the Black Marlin Pipeline approximately 14 miles to the west. Reactivation of the Omega Pipeline will be dependent upon future drilling activity in the vicinity and successfully attracting reserves to the system.
The economic return to the Company on its pipeline system investments is solely dependent upon the amounts of gas and condensate gathered and transported through the pipeline systems. Competition for provision of gathering and transportation services, similar to those provided by the Company, is intense in the market areas served by the Company. See Competition, Markets and Regulation - - Competition below. Since contracts for provision of such services between the Company and third party producer/shippers are generally for a specified time period, there can be no assurance that current or future producer/shippers will not subsequently tie-in to alternative transportation systems or that current rates charged by the Company will be maintained in the future. The Company actively markets gathering and transportation services to prospective third party producer/shippers in the vicinity of its pipeline systems. Future utilization of the pipelines and related facilities will depend upon the success of drilling programs around the pipelines, and attraction, and retention, of producer/shippers to the systems.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The Company's oil and gas assets are held, and operations conducted by BDEX a wholly-owned subsidiary and ARO, a 75% owned subsidiary of BDEX.
The following is a description of the Company's major oil and gas exploration and production assets and activities:
AMERICAN RESOURCES OFFSHORE, INC. On December 2, 1999, BDEX acquired a 75% ownership interest in ARO. The purchase price for the ARO shares was approximately $4.5 million. Concurrently with the sale to BDEX, ARO sold an 80% interest in its Gulf of Mexico assets to Fidelity Oil Holdings, Inc. a subsidiary of MDU Resources Group, Inc. ("MDU"). The proceeds received by ARO were used to retire certain indebtedness.
ARO's assets consist of an average 6% non-operated working interest in eight producing properties and one proved undeveloped property along with leasehold interests in 34 additional offshore tracts, all located in the Gulf of Mexico offshore Louisiana and Texas. The ARO properties represent 36% of the discounted present value of estimated future net revenues from Proved Reserves of the Company as of December 31, 1999. Sales of production from the ARO properties accounted for 52% of oil and gas sales revenues and 10% of total revenues of the Company for the year ended December 31, 1999.
ARO sells substantially all of its current oil and gas production through the operators of its properties. The price ARO is currently receiving is based on current market prices. Previously, forward sales contracts were utilized for a significant portion of its gas production to achieve more predictable cash flow and to reduce the effect of fluctuations in gas prices.
ARO has established a preliminary budget of $1.4 million for exploration and development in 2000; however, this budget is subject to revision during the year to reflect drilling results and new opportunities. ARO will evaluate each of the exploration and development opportunities and its' available capital resources to determine whether to participate, sell its' interest or sell a portion of its' interest and use the proceeds to participate at a reduced interest.
THE BUCCANEER FIELD. The Buccaneer Field is comprised of interests in parts of four lease blocks covering 14,660 acres located in the Gulf of Mexico approximately 36 miles south of Freeport, Texas. Operation of the field is conducted from two platforms located in waters averaging approximately 65 feet in depth.
The Company owns a 100% working interest in the Buccaneer Field (81.33% net revenue interest). The Buccaneer Field leasehold interests represent 64% of the discounted present value of
estimated future net revenues from Proved Reserves of the Company as of December 31, 1999. Production from the Buccaneer Field accounted for 48% of the total revenues from oil and gas sales of the Company for the year ended December 31, 1999 and 100% for the years ended December 31, 1998 and 1997. See "Proved Oil and Gas Reserves" below. Buccaneer Field condensate and natural gas production is delivered to the Blue Dolphin System.
Natural gas produced from the Buccaneer Field is sold under a gas purchase contract dated May 1, 1991. Currently, the contract has been extended through September 2000 at a variable monthly market price. In December 1999, the Company received a price of $2.04/MMBtu. Buccaneer Field gas sales represented 42% of oil and gas sales revenues and 8% of total revenues of the Company for the year ended December 31, 1999.
Buccaneer Field condensate sales are based on spot market monthly average prices. Sale of condensate from the Buccaneer Field represented 6% of oil and gas sales revenues and 1% of total revenues of the Company for the year ended December 31, 1999.
The U. S. Department of the Interior, Minerals Management Service ("MMS") requires that security be provided for the estimated future abandonment obligations associated with the Buccaneer Field. BDEX provides the MMS surety bonds in the amount of $1,300,000. Additionally, a sinking fund is provided wherein $250,000 annually is set aside until a total of approximately $2,400,000 has been accumulated to meet end of lease abandonment and site clearance obligations. As a result of BDEX removing an inactive satellite platform in the Buccaneer Field, no payment was made in 1999 to the sinking fund. As of December 31, 1999, the sinking fund totalled approximately $1,168,560. The Company estimates the remaining life of its major Buccaneer Field facilities to be in excess of ten years.
In addition to conducting traditional oil and gas production operations for itself, the Company operates and maintains oil and gas production facilities for third party producers who also utilize the Blue Dolphin System for gathering and transportation of their production. Currently, such contract operation and maintenance services are provided to one third party producer/shipper. During 1999, revenues attributable to provision of contract operation and maintenance services represented 11% of the Company's total revenues.
OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, BDEX initiated a program to develop oil and gas exploration prospects in the Gulf of Mexico for sale to third parties. The program utilizes 3-D seismic data. The Company owns a license to 150 blocks of 3-D seismic data covering 850,000 acres in the Western Gulf of Mexico and a substantial inventory of close grid 2-D seismic data. In addition to recovering prospect development costs, BDEX seeks to retain a reversionary working interest in each drillable prospect.
In September 1997, the Company entered into an agreement with industry participants, whereby in exchange for certain participation rights, the participants partially funded the costs associated with the Company's 1997/1998 offshore prospect generation program. In order to enhance the productivity of the prospect generation program, during 1998 the Company transitioned from the use of consulting geologists and geophysicists to a 100% in house effort. This program was terminated in August 1998, as a result of the withdrawal of a major partner.
In 1999 the Company placed a 50% interest in the program, whereby in exchange for certain participation rights, the participant funds $100,000 per month for the costs associated with the program. Program costs will be reimbursed to the Company as prospects are developed and leases acquired. A portion of the reimbursed costs will be paid to the Company's existing program participant based on the level of interest it retains in each prospect. The available 50% interest in the generated prospects is for sale on an individual prospect basis. The Company believes that it will reach a formal agreement with its
existing program participant to continue funding of the prospect generation program through at least December 2000.
The Company spent the first half of 1999 developing and marketing a prospect inventory in preparation for the Western Gulf of Mexico Federal Lease Sale held in August. Of the five prospects developed, one was sold in which the Company retained a reversionary interest. Partial interests were sold in all of the pre-existing inventory of leased prospects. The Company is continuing to market the remaining interests. The Company's leased prospect inventory consists of prospects on the following offshore leases:
o High Island Area Block A-8
o Galveston Area Block 285
o Galveston Area Block 295 (Buccaneer)
o Mustang Island Area Block 817
o Mustang Island Area Block 839
The Company has reversionary interests in the following offshore leases:
o High Island Area Block A-7
o Galveston Area Block 297
o Matagorda Island Area Block 713
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, 1999, by Netherland Sewell & Associates, Inc. (ARO), Ryder Scott Company (ARO) and the Company (Buccaneer Field). Both Netherland Sewell & Associates, Inc. and Ryder Scott Company are 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, 1999, using the SEC Method (defined below).
PROVED RESERVES INFORMATION AS OF DECEMBER 31, 1999
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"). See estimated future net revenues after deductions for income taxes in Note 11 to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries.
(4) The Company acquired a 75% ownership interest in ARO on December 2, 1999. The above reflects 100% of ARO's reserves and future net revenues, 25% of discounted future net revenues associated with total Proved Reserves and total Proved Developed Reserves of the ARO properties is $1,525,252 and $1,038,750, respectively.
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 summarized above reflect capital expenditures totaling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in the years ending December 31, 2000, 2001, 2002, 2003 and 2004, 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 the timing of the development of such reserves will be as currently planned.
The discounted present value of estimated future net revenues attributable to Proved Reserves has been prepared in accordance with the SEC Method after deduction of royalties and other third-party interests, lease operating expenses, and estimated production, development, workover and recompletion costs, but before deduction of income taxes, general and administrative costs, debt service and depletion and amortization. Estimated future net revenues are based on prices of oil and gas in effect at the end of the year without escalation except to the extent contractually committed. Lease operating expenses, and production and development costs, were estimated based on such costs in effect at the end of the year, assuming the continuation of existing economic conditions and without adjustment for inflation or other factors. The present value of estimated future net revenues is computed by discounting future net revenues at a rate of 10% per annum. Revenues from wells not currently producing are included at the time they are expected to be placed into production based upon estimates of future development;
workover and recompletion costs are included at the time they are expected to be incurred. Of the Company's total Proved Developed Reserves, 92% of its estimated gas reserves and 29% of its estimated oil reserves were being produced at December 31, 1999.
Estimates of production and future net revenues cannot be expected to represent accurately the actual production or revenues that may be recognized with respect to oil and gas properties or the actual present market value of such properties. For further information concerning the Company's Proved Reserves, changes in Proved Reserves, estimated future net revenues and costs incurred in the Company's oil and gas activities and the discounted present value of estimated future net revenues from the Company's Proved Reserves, see Note 11 - Supplemental Oil and Gas Information to Consolidated Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference.
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, 1999
ACREAGE AND WELLS
(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.
(2) The Company acquired a 75% ownership interest in ARO on December 2, 1999. The above reflects 100% of ARO's acreage and wells.
PRODUCTION, PRICE AND COST DATA. The following table sets forth the approximate production volumes and revenues, average sales prices and costs (after deduction of royalties and interests of others) with respect to crude oil, condensate, and 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, ----------------------------------------- 1999 1998 1997 ----------- ----------- -----------
Gas: Production (Mcf) .............. 169,329 177,260 176,986 Revenue ............ $ 393,125 $ 391,913 $ 393,444 Average Mcf per Day 463.9 485.6 484.9 Average Sales Price Per Mcf ......... $ 2.32 $ 2.21 $ 2.22
Oil: Production (Bbls) .. 6,338 1,628 1,156 Revenue ............ $ 151,974 $ 20,840 $ 21,636 Average Bbls per day 17.4 4.5 3.2 Average Sales Price Per Bbl ......... $ 23.98 $ 12.80 $ 18.72
Production Costs (1):
Per Equivalent Mcf (2): ............. $ 4.14 $ 3.30 $ 4.16
(1) Production costs, exclusive of workover costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes.
(2) Equivalent Mcf includes oil and condensate stated in terms of natural gas at the rate of one Bbl. of oil or condensate to six Mcf of natural gas.
DRILLING ACTIVITY. There was no drilling activity during 1999. There were two (.5 net) unsuccessful exploratory wells drilled in 1998, including one on a prospect generated and sold to third parties by the Company. There was no drilling activity during 1997.
The Company maintains a professional staff capable of supervising and coordinating the operation and administration of its oil and gas properties and pipeline and other assets. From time to time, major maintenance and engineering design and construction projects are contracted to third-party engineering and service companies.
MIDSTREAM DEVELOPMENT PROJECTS
PETROPORT PROJECT
The Company's investment in and development of an offshore crude oil terminal is through Petroport.
In October 1999 the Company announced that Equilon Enterprises, LLC (an alliance of two major oil companies, Shell and Texaco), agreed to jointly continue development of the Petroport deepwater port project with the Company. Development efforts are focusing on optimization of the facility design configuration, and determining the expected level of market support. Although the commercial evaluation, based upon the original facility design concept was favorable, alternative design configurations, which would result in significantly reduced capital costs and a more flexible, responsive, market driven, system fee structure have been developed. A decision to proceed with obtaining the requisite license and permits for the port facilities will be based on the results of the current development effort.
The cost of the offshore terminal complex, main oil pipeline to shore, its onshore support facilities and facility licensing is estimated to be $200 million. Fabrication, construction, installation and start-up are estimated to require 20-24 months, following a 12-15 month period to obtain the requisite license and regulatory permits, (See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations").
In March 1995, the Company acquired Petroport, L.C. The form of the transaction was a merger of Petroport, L.C. into Petroport. Petroport holds proprietary technology, represented by certain patents issued and or pending, associated with the development and operation of a deepwater crude oil and products port and offshore storage facility. The Petroport deepwater terminal will receive crude oil and refined products offshore with deliveries to shore by pipeline. Onshore the Petroport pipeline will connect with an existing onshore storage and distribution network, accessing Texas Gulf coast and Mid-Continent refining centers.
The facility will be located 40 miles off the Texas coast in approximately 115 feet of water. As currently planned, the terminal complex will consist of two single point mooring buoys connected to a central pumping platform, with a main export pipeline from the platform to shore facilities in the Freeport, Texas area. At its onshore terminus, the main oil pipeline will access existing onshore storage and a distribution network serving the greater Houston area refiners and the NYMEX crude oil futures settlement hub at Cushing, Oklahoma. The design capacity of the pipeline to shore will be in excess of 1.25 million barrels per day.
Petroport will offer an efficient and cost effective alternative for receipt of large volumes of imported crude oil. The Company believes Petroport's commercial success will be driven primarily by economies of scale derived from use of larger, fully loaded tankers discharging short haul Caribbean Basin cargoes into Petroport, and efficiencies gained by supertankers discharging intermediate and long haul West African, North Sea, and Persian Gulf crudes directly into Petroport versus current use of lightering operations.
Petroport will also be available to serve producers in the Gulf of Mexico ("GOM"). It can serve as a major gathering hub and trunk line to shore, with crude received from floating production storage and offloading systems serving deepwater GOM producers.
Petroport's future business environment is expected to be characterized by a continuing significant requirement by refiners for imports, with use of short haul Caribbean Basin crudes as a major source of foreign crude. Transportation savings afforded by Petroport, combined with the Texas Gulf coast and Mid-Continent market demand for imported crude will, the Company believes, provide a sound and strong outlook for Petroport.
AVOCA NATURAL GAS STORAGE PROJECT
In November 1999 the Company and WBI Holdings, Inc., formed New Avoca Gas Storage LLC ("New Avoca"), 25% owned and managed by the Company and 75% owned by WBI, and acquired the Avoca gas storage assets. The Company records its investment in New Avoca by using the equity method of accounting.
The Avoca natural gas salt cavern storage project was conceived as a 5 BCF working gas facility located south of Rochester near the town of Avoca, New York. Its design provides for 250 MMcf/d injection and 500 MMcf/d withdrawal capacities into the Tennessee Gas Pipeline HC400 24" line.
The original owner was Avoca Gas Storage, Inc., who filed for bankruptcy on July 7, 1997, after encountering technical difficulties during construction as well as project cost overruns. The assets were subsequently acquired out of bankruptcy by Northeastern Gas Caverns ("Northeastern").
New Avoca purchased the Avoca gas storage assets from Northeastern for $400,000 plus a contingent payment of $500,000 due on May 22, 2000. The contingent payment will be excused if Northeastern successfully settles a claim associated with the Avoca Gas Storage, Inc. bankruptcy. A pending settlement of the claim is expected to close before May 2000. New Avoca can elect to liquidate the project, before or after May 22, 2000, by selling the existing assets and settling all accrued obligations. Upon liquidation, the first $400,000 of proceeds if any, would go to New Avoca, the next $500,000 proceeds would go to Northeastern and anything over $900,000, subject to Northeastern successfully settling its claim in the Avoca Gas Storage, Inc. bankruptcy proceedings, to New Avoca.
The existing Avoca physical facilities include:
o 900+ acres of land
o Pumps and pipeline for fresh water
o Pump house containing 12 pumps (6,400 HP) for the solution mining operation
o 5 cavern wells - 4,000' deep
o 6 brine disposal wells - 9,000' deep
o Storage building with valves, fittings, and miscellaneous parts
o Electrical switch gear
o Solution mining equipment
o Compressor foundations
o Electrical Sub-Station
New Avoca is currently conducting a feasibility study to determine the technical and commercial viability of completing the construction of the Avoca Natural Gas Storage facility. Based upon the results of the study, New Avoca will either go forward with construction or liquidate the project. If liquidated, the Company believes that it can recover its investment in this project. It is currently estimated that it will take between 1 1/2 to 2 years to begin operations at partial capacity, with 3 to 4 years for the facility to operate at full capacity. The cost has not yet been determined.
COMPETITION, MARKETS AND REGULATION
COMPETITION
The oil and gas industry is highly competitive in all segments. Increasingly vigorous competition occurs among oil, gas and other energy sources, and between producers, transporters, and distributors of oil and gas. Competition is particularly intense with respect to the acquisition of desirable producing properties and the marketing of oil and gas production. There is also competition for the acquisition of
oil and gas leases suitable for exploration and for the hiring of experienced personnel to manage and operate the Company's assets. Several highly competitive alternative transportation and delivery options exist for current and potential customers of the Company's traditional gas and oil gathering and transportation business as well as for refiners, shippers, marketers and producers of crude oil whom the Company's proposed Petroport facility would serve. Gas storage customers who would use the proposed Avoca Gas Storage system have alternatives, including depleted reservoir and salt cavern storage. Competition also exists with other industries in supplying the energy and fuel needs of consumers.
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, actions taken by foreign oil and gas producing nations, the availability of pipelines with adequate capacity, the availability of vessels for lightering and transshipment and other means of transportation, the availability and marketing of other competitive fuels, fluctuating and seasonal demand for oil, gas and refined products, and the extent of governmental regulation and taxation (under both present and future legislation) of the production, importation, refining, transportation, pricing, use and allocation of oil, 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 produced for sale or prices chargeable for transportation, terminaling and storage services, which the Company provides or may provide in the future.
GOVERNMENTAL REGULATION
The production, processing, marketing, and transportation of oil and natural gas, and planned terminaling and storage of crude oil and natural gas storage by the Company are subject to federal, state and local regulations which can have a significant impact upon the Company's overall operations.
FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. Under the NGA and to a lesser extent the NGPA, the FERC has authority to regulate the transportation and resale of natural gas in interstate commerce. Although the FERC is increasingly employing "light-handed" regulation, regulation remains an important factor in the natural gas industry. In 2000, FERC issued Order 637, which contains changes that increase the trend toward market-based pricing of pipeline transportation services in certain circumstances.
As a regulated interstate pipeline, Black Marlin Pipeline is subject to Natural Gas Act requirements governing the pricing and nature of interstate transportation of natural gas. While FERC restructuring of the gas industry has not directly affected the activities of the Company's nonjurisdictional pipelines, it may have an indirect effect because of its broad scope. In particular, aspects of FERC rate regulation may be used to bolster the relative position of regulated pipelines competing to attract production in the vicinity of the Company's gas pipeline facilities.
The Company cannot predict accurately how such developments in the above-described laws and regulations, or future laws and regulations, will affect its operations or its competitive position.
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.
FEDERAL REGULATION OF NATURAL GAS PIPELINES. Of the natural gas pipelines owned by the Company, only Black Marlin is subject to Natural Gas Act regulation. As a result, its gas transportation service and pricing service are regulated by the Federal Energy Regulatory Commission. Although Black Marlin Pipeline successfully completed a FERC rate case in 1998 and thus can expect some rate stability, the trend toward greater competition among gas pipelines subject to Natural Gas Act regulation is continuing, making it infeasible for regulated pipelines to rely upon exclusive monopoly status. Additionally, requirements of the Gas Industry Standards Board ("GISB") continue to evolve, and, along with additional Order 637 reporting and operational requirements, may impose additional obligations and costs upon interstate pipelines subject to these requirements.
All of the Company's pipelines located in federal offshore waters, whether subject to Natural Gas Act jurisdiction or exempted as nonjurisdictional gathering, are subject to the requirements of the Outer Continental Shelf Lands Act ("OCSLA"). FERC has stated that nonjurisdictional gathering lines, as well as interstate pipelines, are fully subject to the open access and nondiscrimination requirements of OCSLA's Section 5, which generally authorizes the FERC to insure that 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. More recently, the FERC has undertaken several investigations into the nature and extent of its regulatory powers on the Outer Continental Shelf. It issued a policy statement on OCS pipelines reaffirming the requirement that all pipelines provide nondiscriminatory service. Additionally, currently pending complaints against nonjurisdictional gathering facilities under the OCSLA seek more stringent FERC regulation of service and pricing.
Further FERC initiatives concerning possibly diminished Natural Gas Act regulation of pipelines on the OCS and/or broader regulation under the OCSLA are under consideration. Since all of the Companies' offshore pipelines already operate on the basis required under OCSLA, the Company does not anticipate significant changes directly resulting from requirements concerning nondiscriminatory open access transportation. Moreover, if an offshore pipeline's throughput increases to the extent that the pipeline's capacity is completely utilized, under OCSLA, the FERC may be petitioned to direct capacity allocation on the pipeline. Accordingly, the Company cannot predict how application of the OCSLA to the Companies' pipelines 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 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, the FERC issued Order 561, which was intended to simplify oil pipeline ratemaking, largely through use of a ceiling based on an indexing system. Because Buccaneer Pipeline has not taken action to become subject to Order 561 or Order 572 concerning market-based rates for oil pipelines, the Company cannot predict whether or how an indexed or market-based rate system will affect the Buccaneer Pipeline's rates.
REGULATION OF DEEPWATER PORTS: PERMITTING AND LICENSING. The ownership, construction and operation of a deepwater crude oil terminal facility (a "Deepwater Port"), such as the Company's proposed Petroport facility, must conform to the requirements of a number of Federal, State and local laws. A license from the Department of Transportation ("DOT") is required under the Deepwater Port Act of 1974 ("DWPA"), as amended. Permits from the Environmental Protection Agency and the Federal Communication Commission are required, as well as permits from the U.S. Army Corps of
Engineers and the State of Texas to construct ancillary port facilities, such as pipelines and onshore facilities.
The DWPA empowers the Secretary of Transportation to license and regulate Deepwater Ports beyond the territorial sea of the United States. License applications must include sufficient information to allow the Secretary of Transportation to judge whether the Deepwater Port will comply with all technical, environmental, and economic criteria. The application and licensing process includes the preparation of an Environmental Impact Statement, development of detailed operations procedures, submission of extensive financial and ownership data and public hearings.
The Company was a principal participant in the development and passage of The Deepwater Port Modernization Act, successfully amending the DWPA. Among other changes to the 1974 Act, amendments to the DWPA adopted in 1996 provide: (1) upon written request of an applicant for a license, the Secretary may exempt the applicant from certain of the informational filing requirements if the Secretary determines such information is not necessary to facilitate his or her determination and such exemption will not limit public review; (2) the facility is explicitly permitted to receive domestic production from the United States Outer Continental Shelf; (3) simplification and streamlining of the regulatory process to which the facility would be subject during both the licensing process and when in operation; and (4) elimination of various facility use restrictions. Once a license is issued, the law states that it remains in effect unless suspended or revoked by the Secretary of Transportation or is surrendered by the licensee.
Regulations provide for extensive consultation among all interested Federal agencies, any potentially affected coastal State, and the general public. Adjacent coastal States are granted an effective veto power or reservation over proposed Deepwater Ports. Under the statute, if a Governor of an adjacent coastal State notifies the Secretary of Transportation that a proposal is inconsistent with the State programs relating to environmental protection, land and water use, and coastal zone management, then the Secretary of DOT shall grant the license on the condition that the proposal is made consistent with such State programs. Governors may also reject proposed Deepwater Ports on other grounds.
In addition, the DWPA requires all Deepwater Ports, including related storage facilities, be operated as common carriers, unless the licensee is subject to "effective competition".
Given the nature and complexity of obtaining the necessary license and permits, there can be no assurance that the Company will be issued a Deepwater Port license and other necessary permits.
FEDERAL OIL AND GAS LEASES. The Company's operations conducted on the Buccaneer Field leases and any other Company operations conducted on federal OCS 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 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 Field".
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 gross 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.
LEGISLATION AND RULEMAKING. In October 1996 the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the Oil Pollution Act of 1990 ("OPA `90") to establish requirements for evidence of financial responsibility for certain offshore facilities, other than Deepwater Ports. The amount required is $35,000,000 for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. The Company currently maintains this statutory $35,000,000 coverage.
In August 1995, the DOT issued a Rulemaking under OPA '90, providing that the Secretary of Transportation can set the liability limit and associated Certificate of Financial Responsibility requirement for Deepwater Ports from between $350,000,000 and $50,000,000 concurrent with the overall processing of the DWP license application. Development of the liability limit would be based upon engineering and environmental analysis provided during the licensing process.
Federal and state legislative rules and regulations are pending that, if enacted, could significantly affect the oil and gas industry. It is impossible to predict which of those federal and state proposals and rules, if any, will be adopted and what effect, if any, they would have on the operations of the Company.
In addition, various federal, state and local laws and regulations covering the discharge of materials into the environment, occupational health and safety issues, or otherwise relating to the protection of public health and the environment, may affect the Company's operations, expenses and costs. The trend in such regulation has been to place more restrictions and limitations on activities that may impact the general or work environment, such as emissions of pollutants, generation and disposal of wastes, and use and handling of chemical substances. It is not anticipated that, in response to such regulation, the Company will be required in the near future to expend amounts that are material relative to its total capital structure. However, it is possible that the costs of compliance with environmental and health and safety laws and regulations will continue to increase. Given the frequent changes made to environmental and health and safety regulations and laws, the Company is unable to predict the ultimate cost of compliance.
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 its corporate executive offices in Houston, Texas, under an operating lease expiring December 31, 2006. The Company also leases, under an operating lease expiring April 30, 2000, its division office in New Orleans, Louisiana.
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, 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Common Stock trades in the over-the-counter market and is quoted on the NASDAQ Small Cap Market under the symbol "BDCO". As of March 23, 2000, there were an estimated 325 stockholders of record and the Company estimates there are more than 1,000 beneficial owners 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 sales price for the Common Stock as reported on NASDAQ.
SALES HIGH LOW ------ ------ Quarter Ended March 31, 1998...... $ 4.50 $ 2.75 Quarter Ended June 30, 1998 ..... $ 3.69 $ 3.13 Quarter Ended September 30, 1998.. $ 3.56 $ 2.44 Quarter Ended December 31, 1998... $ 3.50 $ 2.63 Quarter Ended March 31, 1999...... $ 4.69 $ 3.13 Quarter Ended June 30, 1999....... $ 6.00 $ 4.00 Quarter Ended September 30, 1999.. $ 6.88 $ 5.00 Quarter Ended December 31, 1999... $ 7.94 $ 5.75
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. Furthermore, the Company is restricted, pursuant to its loan agreement with a commercial bank, from paying dividends on 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.
RECENT SALES OF UNREGISTERED SECURITIES During the year ended December 31, 1999, Directors, Officers and other employees exercised options to purchase 32,004 shares of Common Stock. The sale of shares was privately made to Directors, Officers and other employees pursuant to the Company's 1985 and 1996 Stock Option Plans, at exercise prices between $2.7885 and $4.383 per share. The Company relied on an exemption under Section 4(2) of the Securities Act of 1933 in effecting these transactions.
In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its' common stock, $.01 par value per share, at $5.00 per share. The proceeds were used to replenish working capital.
In order to provide funding for the acquisition of ARO in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately $4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data of the Company and its consolidated subsidiaries is presented for the five fiscal years ended December 31, 1999. 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 Blue Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated herein by reference, and Item 1, Business and Properties.
FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1999, the Company's working capital (current assets less current liabilities) was $93,231, representing a decrease in working capital of $11,312 as compared with working capital of $104,543 at December 31, 1998.
On December 2, 1999, the Company acquired a 75% ownership interest in ARO for approximately $4.5 million. See Item 1 "Business-Oil and Gas Exploration and Production Activities" for a description of ARO. Concurrently with the transaction, ARO sold an 80% interest in its Gulf of Mexico assets to Fidelity Oil Holdings, Inc., a subsidiary of MDU Resources Group, Inc. The proceeds received by ARO were used to retire certain indebtedness.
Pursuant to the terms of the investment agreement with ARO, the Company entered into an agreement with ARO to provide management services for a fee of $1,000,000 per year. Additionally, the Company entered into an agreement with Fidelity Oil Holdings, Inc. to manage their interest in the properties acquired from ARO for $40,000 per month. Both agreements are in effect through December 2000 and provide for continuation thereafter on a year to year basis unless terminated by either party.
In order to provide funding for the acquisition of ARO in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately $4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999. The Company also issued a $1,000,000 convertible promissory note to a director of the Company (See Note 7). The Company believes that if the $1,000,000 convertible promissory note is not converted, the amount due will be refinanced.
In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its common stock, $.01 par value per share, at $5.00 per share. The proceeds were used to replenish working capital.
The Company maintains a $10,000,000 reducing revolving credit facility with Bank One, Texas, N.A. ("Loan Agreement"). In January 2000, the Company paid the $80,000 outstanding balance on the credit facility and the borrowing base was adjusted to $0. The borrowing base is redetermined semi-annually and is next due to be redetermined in June 2000. The maturity date has been extended to December 31, 2000, when the then outstanding principal balance, if any, is due and payable. The facility is available for the acquisition of oil and gas reserve based assets and other working capital needs. The Loan Agreement includes certain restrictive covenants, including restrictions on the payment of dividends on capital stock, and the maintenance of certain financial coverage ratios.
On March 1, 1999 the Company acquired Black Marlin Pipeline Company from Enron Pipeline Company for $5,404,270 cash. BMPC is the owner of the 75 mile Black Marlin Pipeline System, see Item 1. "Business - Pipeline Operations and Activities" for a description of the Black Marlin Pipeline System. This acquisition was funded by selling a one-sixth (1/6) undivided interest in the Company's Blue Dolphin Pipeline System, the Black Marlin Pipeline System and the Omega Pipeline to WBI for $3,712,000 and selling a one-third (1/3) undivided interest in the Black Marlin Pipeline System to MCNIC for $1,801,423. MCNIC owns a one-third (1/3) undivided interest in the Blue Dolphin Pipeline System and the Omega Pipeline. The Company recognized a gain of $2,052,920 in connection with the sale of the one-sixth interest in the Blue Dolphin Pipeline System.
In June 1999, the Company removed an inactive satellite platform in the Buccaneer Field at a cost of approximately $345,000. The Company's annual abandonment escrow fund payment of $250,000 that was due in June 1999, was not made as a result of the removal of the inactive satellite platform.
The reserves and future net revenues presented in Item 1 "Business - Oil and Gas Exploration and Production Activities," reflect capital expenditures totalling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in the years ending December 31, 2000, 2001, 2002, 2003 and 2004, respectively. Management will continue to evaluate its capital expenditure program based on, among other things, field reservoir performance, availability and cost of drilling and workover equipment, and demand and prices obtainable for the Company's production, as well as availability of capital resources. There can be no assurance that reserves will be developed as currently planned.
In 1999 the Company placed a 50% interest in the prospect generation program, whereby in exchange for certain participation rights, the participant funds $100,000 per month for the costs associated with the program. Program costs will be reimbursed to the Company as prospects are developed and leases acquired. A portion of the reimbursed costs will be paid to the Company's existing program participant based on the level of interest it retains in each prospect. During 1999, the Company sold one prospect and retained a reversionary interest in the prospect. The available interests in the prospect inventory are for sale on an individual prospect basis. The Company believes that it will reach a formal agreement with its existing program participant to continue funding the prospect generation program through at least December 2000. A well is currently being drilled on a prospect the Company previously sold in which it has retained a reversionary interest. The Company had previously entered into a multi-year 3-D seismic data acquisition and licensing agreement, whereby a minimum of $1,500,000 was committed over a 5 year period that ended July 31, 1999 to acquire 3-D seismic data. The final commitment under the agreement, $450,000, was paid in July 1999.
In October 1999, the Company and Equilon Enterprises, LLC (an alliance of two major oil companies, Shell and Texaco), agreed to jointly continue development of the Petroport deepwater port project. Development efforts are focusing on optimization of the facility design configuration and determining the expected level of market support. It is expected that a decision to proceed with obtaining the requisite license and permits for the port facilities will be made following completion and evaluation of the results of the development effort. Although the commercial evaluation, based upon the original facility design concept was favorable, alternative design configurations, which would result in
significantly reduce capital costs and a more flexible, responsive, market driven, system fee structure have been developed.
Cost of the offshore terminal complex, the pipeline to shore, onshore facilities and facility licensing is estimated at $200 million. The Company expects that its' partner or partners in the Petroport project would be responsible for all licensing and permitting costs, currently estimated to be approximately $6 million. The Company would seek financing for the costs associated with facility construction which the Company believes it can obtain. If the Company decides to proceed with the project, it expects to submit the license application and associated permit requests in 2000, with operations commencing in the year 2003.
In November 1999, the Company and WBI Holdings, Inc. formed New Avoca, 25% owned and managed by the Company and 75% owned by WBI, and acquired the Avoca gas storage assets for $400,000 ($100,000 net to the Company's interest) from Northeastern (see Item 1 "Business - Avoca Natural Gas Storage Project"). Additionally, a contingent payment of $500,000 ($125,000 net to the Company's interest) is due to Northeastern on May 22, 2000. The contingent payment will be excused if Northeastern successfully settles a claim associated with the Avoca Gas Storage, Inc. (the original owner of the Avoca gas storage assets) bankruptcy proceedings. A pending settlement of the claim is expected to be completed by May 22, 2000, and the Company believes that the contingent payment will be excused. New Avoca can elect to liquidate the project before or after May 22, 2000. If liquidated, after settling all accrued obligations, the first $400,000 of proceeds, if any, goes to New Avoca, the next $500,000 goes to Northeastern and anything over $900,000, subject to Northeastern successfully settling its claim in the Avoca Gas Storage, Inc. bankruptcy proceedings, goes to New Avoca. New Avoca is currently evaluating whether or not to go forward with construction of the project or to liquidate the project. It is currently estimated that the Company's share of costs associated with these activities for 2000 will be $168,000. The Company's share of construction costs, should New Avoca decide to go forward with the project, and the timing of such costs have not been determined.
In general, the Company believes that it has or can obtain adequate capital resources and liquidity to continue to finance and otherwise meet its anticipated business requirements. The availability or cost of capital resources may, however, adversely affect the Company's timing for major pipeline expansions, further development of the Buccaneer Field, growth in oil and gas prospect generation activities and the Petroport and Avoca projects.
RESULTS OF OPERATIONS
For the year ended December 31, 1999 ("1999"), the Company reported a net loss of $2,086,511, compared to net loss of $9,059,979 reported for the year ended December 31, 1998 ("1998"), representing an improvement of $6,973,468. The improvement is primarily due to a non-cash impairment of oil and gas properties recorded at December 31, 1998 of $8,952,785, net of income tax benefit, offset in part by a non-cash valuation allowance on its deferred tax assets of $1,858,608 recorded at December 31, 1999.
For the year ended December 31, 1998 ("1998"), the Company reported a net loss of $9,059,979, compared to net income of $983,095 reported for the year ended December 31, 1997 ("1997"), representing a decrease of $10,043,074. The decrease is primarily due to the non-cash impairment of oil and gas properties recorded at December 31, 1998 of $8,952,785, net of income tax benefit.
1999 COMPARED TO 1998
REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by $913,228 or 33% in 1999 to $1,875,716 from 1998. The decrease was due to a decline in gas and oil volumes transported by the Blue Dolphin System of approximately $1,424,749, and the sale of a one-sixth interest in the Blue Dolphin System in March 1999, eliminating revenues of $189,623, offset in part by the acquisition of the Black Marlin System, providing revenues of $701,144.
REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Oil and gas sales and operating fees increased by $111,511 or 15% in 1999 to $881,340 from 1998. The acquisition of ARO in December 1999 provided revenues of $307,195, partially offset by a reduction in Buccaneer Field revenues of $195,684 or 25%. Although commodity prices in general increased during 1999, gas sales from the Buccaneer Field were based on a fixed price of $2.08 per MMBtu through September 1999. Since October 1999, the price received for Buccaneer Field gas production has been a current monthly market price.
PIPELINE OPERATING EXPENSES. Pipeline operating expenses increased $218,946 or 25% to $1,102,998 from 1998. The increase was due to the acquisition of the Black Marlin System in March 1999, with expenses of $393,696 in 1999, offset in part by the sale of a one-sixth interest in the Blue Dolphin System in March 1999, eliminating expenses of $108,205, and cost reductions from continuing operations of $66,545.
LEASE OPERATING EXPENSES. Lease operating expenses increased by $254,450 or 30% in 1999 to $1,100,549 from 1998. The increase was due primarily to costs of approximately $187,738 associated with repairs made to the offshore Buccaneer Field platforms in 1999 and approximately $66,712 associated with the ARO properties that were acquired in December 1999.
DEPLETION, DEPRECIATION AND AMORIZATION ("DD&A"). DD&A expense increased by $194,304 or 48% in 1999 to $595,286 from 1998. The increase was due to the acquisition of the Black Marlin System in March 1999, resulting in depreciation of approximately $199,017, and ARO in December 1999, resulting in depletion of approximately $124,562. These increases were partially offset by a reduction in depletion due to lower production volumes from the Buccaneer Field of approximately $92,475, and the sale of a one-sixth interest in the Blue Dolphin System in March 1999, resulting in a $36,800 reduction in depreciation.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased $595,067 or 41% to $2,061,805 from 1998. The increase was primarily due to increased staff costs associated with the Company's asset acquisitions during 1999.
GAIN ON SALE OF ASSETS. In March 1999, the Company reported a gain on the sale of a one-sixth interest in the Blue Dolphin System of approximately $2,052,920.
INCOME TAX EXPENSE. In 1999 the Company recorded a valuation allowance of its deferred tax assets in accordance with SFAS No. 109 Accounting for Income Taxes, whereby the deferred tax asset of $2,103,052 was reduced to $244,444, resulting in an increase in income tax expense of $1,858,608.
1998 COMPARED TO 1997
REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by $1,373,649 or 33% in 1998 to $2,788,944 from 1997. The decrease was due to a decrease in oil transportation revenues of $1,120,457, primarily due to the loss of a producer/shipper in October 1997.
REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Revenues from oil and gas sales and operating fees for 1998 decreased $50,184 or 6% to $769,829 from 1997. The reduction in oil and gas sales is attributable to normal production declines from the Company's Buccaneer Field.
INTEREST AND OTHER INCOME. Other income for 1998 decreased $157,432 or 40% to $105,994 from 1997. The reduction in other income is due to a refund of prior years franchise taxes of $152,370 received in 1997.
LEASE OPERATING EXPENSES. Lease operating expenses for 1998 decreased by $29,472 to $846,099 from 1997 due in part to repairs and modifications to the Buccaneer Field production platforms and facilities of approximately $68,000 incurred in 1997.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expense increased by $108,967 or 8% in 1998 from 1997 principally due to an increase in staff costs and consulting fees of approximately $95,472, associated with potential asset acquisitions.
IMPAIRMENT OF OIL AND GAS PROPERTIES. At December 31, 1998, the Company recorded a non-cash impairment charge of $12,011,544, reflecting the write down of its oil and gas properties and certain exploration activity costs, resulting from lower oil and gas prices and changes to the Company's development plans, whereby development of oil and gas properties have been delayed.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Statement of Financial Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"), was issued by the Financial Accounting Standards Board in June 1998. SFAS No. 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. In July 1999, SFAS NO. 137, "Deferral of the Effective Date of SFAS No. 133," was issued and delays the effective date for one year, to fiscal years beginning after June 15, 2000. The Company is evaluating the impact of the provisions of SFAS No. 133.
In April 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5 requires that costs of start-up activities be charged to expense as incurred and broadly defines such costs. The Company has capitalized certain costs incurred in connection with a new business segment, and SOP 98-5 requires that such costs be charged to results of operations upon its adoption. The Company adopted the requirements of SOP 98-5 as of January 1, 1999 resulting in a cumulative effect of a change in an accounting principle of $80,334, net of income tax benefit of $41,480.
YEAR 2000 ISSUE
The Company's computer software was made Year 2000 compliant prior to the end of 1999; and, therefore, the business, results of operations and financial condition of the Company were not affected by the millennium change.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including adverse changes in commodity prices and interest rates as discussed below.
COMMODITY PRICE RISK- The Company produces and sells natural gas, crude oil, and natural gas liquids. As a result, the Company's financial results can be significantly affected if these commodity prices fluctuate widely in response to changing market forces. The Company has not used derivative products in the past to manage commodity price risk. As a result of the additional oil and gas production for ARO, the Company may use derivative products in the future.
INTEREST RATE RISK- The Company's exposure to changes in interest rates primarily results from its short-term and long-term debt with floating interest rates. See Note 4 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: PAGE ----
Independent Auditors' Report...................... 25
Consolidated Balance Sheets, at December 31, 1999 and 1998 .................................... 26
Consolidated Statements of Operations, for the years ended December 31, 1999, 1998, and 1997 28
Consolidated Statements of Stockholders' Equity, for the years ended December 31, 1999, 1998, and 1997 .................................... 29
Consolidated Statements of Cash Flows, for the years ended December 31, 1999, 1998, and 1997 30
Notes to Consolidated Financial Statements........ 32
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, 1999 and 1998, 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, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the consolidated financial statements of American Resources Offshore, Inc., a 75 percent owned subsidiary, which statements reflect total assets constituting 6 percent and total revenues constituting 11 percent in 1999 of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for American Resources Offshore, Inc., is based solely on the report of the other auditors.
We conducted our audits in accordance with 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, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and subsidiaries as of December 31, 1999 and 1998, and the results of its their operations and their cash flows for each of the years in the three-year period ended December 31, 1999 in conformity with generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas March 28, 2000
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
ASSETS 1999 1998 ----------- ----------- Current assets: Cash and cash equivalents ................ $ 1,166,730 593,509 Trade accounts receivable ................ 1,542,328 771,268 Prepaid expenses and other assets ........ 318,139 157,588 ----------- -----------
Total current assets .............. 3,027,197 1,522,365 ----------- -----------
Property and equipment, at cost: Oil and gas properties (full-cost method) 26,474,957 21,210,806 Onshore separation and handling facilities 1,583,610 2,106,189 Land ..................................... 930,500 1,133,333 Pipelines ................................ 3,653,397 1,320,063 Other property and equipment ............. 431,294 343,220 ----------- -----------
33,073,758 26,113,611
Less accumulated depletion, depreciation, amortization and impairment ............. 17,412,195 17,172,057 ----------- -----------
15,661,563 8,941,554
Deferred federal income tax .................. 244,444 2,010,060 Acquisition and development costs - Petroport 1,741,823 1,576,391 Escrow fund .................................. 1,168,564 1,107,573 Other assets ................................. 161,613 23,867 ----------- -----------
$22,005,204 15,181,810 =========== ===========
See accompanying notes to consolidated financial statements.
(Continued)
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, CONTINUED
December 31, 1999 and 1998
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 1999, 1998 and 1997
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1999, 1998, and 1997
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1999, 1998, and 1997
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1999, 1998, and 1997
NON-CASH TRANSACTIONS:
During 1999, holders of $1,811,555 of notes payable along with accrued interst of $77,835 converted the notes payable into 314,898 shares of Common Stock.
See accompanying notes to consolidated financial statements.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998, and 1997
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company (the Company) was incorporated in Delaware in January 1986 to engage in oil and gas exploration, production and acquisition activities and oil and gas transportation and marketing. It was formed pursuant to a reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and majority owned subsidiary (ARO). All significant intercompany balances and transactions have been eliminated in consolidation.
ACCOUNTING ESTIMATES
Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and to the disclosure of contingent assets and liabilities including reserve information which affects the depletion calculation as well as the computation of the full cost ceiling limitation to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original maturity of three months or less.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a country-by-country cost center basis. Due to the difference in the expected life of the reserves of the properties, the Company uses two separate cost centers, one for its Buccaneer Field property and one for its ARO properties. Amortization of such costs and estimated future development costs is determined using the unit-of-production method. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred. Estimated proved oil and gas reserves are based upon reports of independent petroleum engineers (ARO properties) and the Company's in-house
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reserve engineers (Buccaneer property). The net carrying value of oil and gas properties, less related deferred income taxes, is limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% discount rate applied) of estimated future net revenues from proved reserves, after giving effect to income taxes, and the lower of cost or estimated fair value of unproved properties. Disposition of oil and gas properties are recorded as adjustments to capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.
At December 31, 1998, the Company recorded an impairment charge on oil and gas properties and certain exploration activity costs of $12,011,544, thereby adjusting the net carrying value of oil and gas properties to the cost center ceiling as described above. The impairment resulted from lower oil and gas prices and changes to the Company's development plans, whereby development of oil and gas properties have been deferred. Included in oil and gas properties at December 31, 1999 and 1998 are $145,101 and $198,486, respectively in expenditures directly associated with generation of additional oil and gas prospects, net of reimbursements.
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives of 10-25 years.
The Company in 1995 adopted Statement of Financial Accounting Standards (SFAS) No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, with no impact to the Company's consolidated financial statements. Assets are grouped and evaluated based on the ability to identify separate cash flows generated therefrom.
OTHER PROPERTY AND EQUIPMENT
Depreciation of furniture, fixtures and other equipment, including assets held under capital leases, is computed using the straight-line method over estimated useful lives of 2-5 years.
ABANDONMENT
A provision for the abandonment, dismantlement and site remediation of offshore production platforms and existing wells is made using the unit-of-production method
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
applied to estimates based on current costs. A provision for pipeline and pipeline facilities abandonment costs is also provided using the straight-line method over the estimated useful lives of the pipeline and pipeline facilities. These provisions are included in accumulated depletion, depreciation and amortization, and accrued abandonment costs, respectively, and are undiscounted. Aggregate abandonment liability is estimated to be approximately $3,960,000 at December 31, 1999 and 1998.
STOCK-BASED COMPENSATION
The Company applies SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, which allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. The Company has chosen to continue to account for stock-based compensation under the intrinsic value method and provides the pro forma effects of the fair value method as required.
RECOGNITION OF CRUDE OIL AND NATURAL GAS REVENUE
Revenue from crude oil and natural gas produced and sold from the Buccaneer Field and ARO properties is recognized in accordance with the entitlements method of accounting.
RECOGNITION OF PIPELINE TRANSPORTATION REVENUE
Revenue from the transportation of gas, condensate and crude oil is recognized on the accrual basis as products are transported.
OPERATION OF OIL AND GAS PROPERTIES
The Company operates, for a monthly fee, oil and gas properties in which it does not own an interest. Revenues and costs from these activities are included in oil and gas sales and operating fees and lease operating expenses, respectively.
INCOME TAXES
The Company provides for income taxes using the asset and liability method pursuant to SFAS No. 109, ACCOUNTING FOR INCOME TAXES (Statement 109). Under the
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
EARNINGS PER SHARE
The Company follows SFAS No. 128 (Statement 128), EARNINGS PER SHARE, for computing and presenting earnings per share and requires, among other things, dual presentation of basic and diluted earnings per share on the face of the statement of operations.
The following table provides a reconciliation between basic and diluted earnings (loss) per share:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING AND DILUTIVE PER NET POTENTIAL SHARE INCOME COMMON SHARES AMOUNT ----------- ------------- ------- Year ended December 31, 1999 Basic (loss) per share ....... $(2,086,511) 4,837,504 $(0.43) ----------- ------------- -------
Diluted (loss) per share ..... $(2,086,511) 4,837,504 $(0.43) =========== ============= =======
Year ended December 31, 1998
Basic (loss) per share ....... $(9,059,979) 4,492,344 $(2.02) ----------- ------------- -------
Diluted (loss) per share ..... $(9,059,979) 4,492,344 $(2.02) =========== ============= =======
Year ended December 31, 1997 Basic earnings per share ..... $ 983,095 4,462,072 $0.22 Effect of dilutive stock Options .................. -- 69,136 -- ----------- ------------- ------- Diluted earnings per share ... $ 983,095 4,531,208 $0.22 =========== ============= =======
The employee stock options at December 31, 1999 and 1998, were not included in the computation of diluted earnings per share because the effect of their assumed exercise and conversion would have an antidulitive effect on the computation of diluted loss per share.
The following unaudited pro forma information for the years ended December 31, 1999 and 1998, presents a summary of consolidated results of operations as if the acquisition of the 75% ownership interest in ARO made in 1999 had occurred on January 1, 1998 with pro forma adjustments to give effect to depreciation and certain other adjustments together with related income tax effects:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEAR ENDED DECEMBER 31, 1999 1998 -------------------------------
Revenues .............................. $ 5,725,592 $ 8,570,915
Net Earnings .......................... $(2,257,689) $(8,330,407)
Basic and diluted earnings per share .. $ (0.47) $ (1.85)
The above pro forma information is not necessarily indicative of the results of operations as they would have been had the acquisition been effected on January 1, 1998.
ENVIRONMENTAL
The Company is subject to extensive Federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable.
COSTS OF START-UP ACTIVITIES
In April 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5 requires that
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
costs of start-up activities be charged to expense as incurred and broadly defines such costs. The Company deferred certain costs incurred in connection with a new business segment, and SOP 98-5 requires that such deferred costs be charged to results of operations upon its adoption. The Company adopted the requirements of SOP 98-5 on January 1, 1999. The cumulative effect of the change in accounting principle for the adoption of SOP 98-5 resulted in a charge to results of operations in the financial statements for the year ended December 31, 1999 of $80,334, net of $41,480 of income taxes.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), was issued by the Financial Accounting Standards Board in June 1998. SFAS No. 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. In July 1999, SFAS NO. 137, "Deferral of the Effective Date of SFAS NO. 133," was issued and delays the effective date for one year, to fiscal years beginning after June 15, 2000. The Company believes that adoption of this financial accounting standard will not have a material effect on its financial condition or results of operations.
(2) FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, receivables and accounts payable approximate fair value due to the short-term maturities of these instruments. The carrying value of the notes payable approximates fair value at December 31, 1999 and 1998.
(3) INCOME TAXES
Income tax expense for 1999, 1998 and 1997 consists of:
1999 1998 1997 ----------- ---------- ------- Current: Federal ............... $ -- -- 25,466 State ................. -- 14,170 50,800 Deferred - Federal ....... 1,797,033 (3,113,980) 469,965 ----------- --------- ------- $ 1,797,033 (3,099,810) 546,231 =========== ========== =======
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1999 and 1998 are presented below.
1999 1998 ----------- ---------- Deferred tax assets: Accrued abandonment costs .............. $ 136,354 $ 84,541 Net operating loss carryforwards ....... 9,800,517 2,685,789
Alternative minimum tax credit ......... 244,444 244,444 Basis differences in property and equipment ....................... 1,425,746 29,295 ----------- ----------
Total gross deferred tax assets ..... 11,607,061 3,044,069
Deferred tax liabilities: State tax ........................... (34,009) (34,009) ----------- ---------- Total gross deferred tax liability ......................... (34,009) (34,009) ----------- ---------- Net deferred tax asset (liability) .. 11,573,052 3,010,060
Less valuation allowance ............ (11,328,608) (1,000,000) ----------- ----------
Deferred tax asset (liability) ...... $ 244,444 $2,010,060 =========== ==========
In 1999, the Company acquired ARO, which had deferred tax assets of approximately $8.5 million made up of basis differences in oil and gas properties and net operating losses. A full valuation allowance has been recorded to reduce the corresponding deferred assets, since it is more likely than not that they will not be realized, due to the limitation of the use of the net operating loss carryforwards resulting from the ownership change in December 1999.
In assessing the realizability of deferred tax assets, the Company applies SFAS No. 109 to determine whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. As a result, the Company recorded a valuation allowance at December 31, 1999 to reduce the deferred tax asset to $244,444.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's effective tax rate applicable to continuing operations in 1999, 1998 and 1997 differs from the expected tax rate of 34% due to the following:
1999 1998 1997 ---- ---- ---- Expected tax rate .......................... (34%) (34%) 34% State taxes, net of federal benefit ........ -- -- 1% Expenses not deductible for tax purposes ... 2% -- 1% Increase in valuation allowance recognized in earnings ............................ 893% 8% -- Other ...................................... 2% -- -- ---- ---- ---- 863% (26%) 36% ==== ==== ====
For federal tax purposes, the company had a net operating loss carryforward ("NOL") of approximately $28.8 million and $7.9 million for the years ended December 31, 1999 and 1998. These NOLs must be utilized prior to their expiration, which is between 2000 and 2018. Of the $28.8 million of NOLs for the year ended December 31, 1999, $21.0 million relates to ARO.
The Company has an alternative minimum tax credit carry forward of $244,444 that does not expire and may be applied to reduce regular tax to an amount not less than the alternative minimum tax payable in any one year.
(4) LONG-TERM DEBT
The Company maintains a reducing revolving credit facility (Loan Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of $10,000,000. At December 31, 1999, the borrowing base under the Loan Agreement was $80,000 and reduced to $0 in January 2000. The borrowing base is redetermined semi-annually. On the first day of each month interest is due and payable on the outstanding loan balance at the rate of 1.25% 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, the Shore Facilities and the Black Marlin Pipeline. The maturity date under the Loan Agreement is December 31, 2000.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
In December 1996, the Company issued $2,050,600 in promissory notes to the holders of the Preferred Stock as full payment of the cumulative preferred stock dividends. The promissory notes are unsecured and bear interest at the rate of 10.25% per annum. Interest only is payable semi-annually with the principal due on December 31, 2000. The Company may prepay all or a portion of the principal at any time prior to maturity with no penalty. On December 1, 1999, the holders of promissory notes totaling $1,811,555 tendered their promissory notes, along with accrued interest of $77,835 for common stock pursuant to the Company's private placement of shares. Additionally, the Company retired $20,634 principal amount of promissory notes in January 2000.
Long-term debt at December 31, 1999 and 1998 is as follows:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, ----------------------- 1999 1998 ---------- ---------- Note payable - related party, interest at 10% per annum, principal due June 1, 2000, convertible into common stock at $6.60 per share ........ $1,000,000 --
$10,000,000 bank credit facility, $80,000 borrowing base, interest payable monthly at prime rate (8. 5% at December 31, 1999) plus 1.25%. Borrowing availability and reducing base amount are redetermined semiannually .............. 80,000 $210,000
Notes payable, interest at 10.25% per annum payable semi-annually, principal due December 31, 2000 ..................... 239,045 2,050,600 ---------- ---------- 1,319,045 2,260,600
Less current maturities, including note payable-related party .................. 1,319,045 200,000 ---------- ---------- $ -- $2,060,600 ========== ========== (5) STOCKHOLDERS' EQUITY
In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its' common stock, $.01 par value per share, at $5.00 per share. The proceeds were used to replenish working capital previously used for planned investments in longer term, high potential projects and for general working capital.
In order to provide funding for the acquisition of ARO in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively and a $1,000,000 convertible promissory note, see notes 4 and 7. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately $4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999.
(6) STOCK OPTIONS
The Company adopted a new stock option plan in 1996 (the Plan). The stock subject to the options and other provisions of the Plan are shares of the Company's Common Stock, $.01 par value (the Stock). The total amount of the Stock with respect to which options may be granted shall not exceed in the aggregate 10% of the number of issued and outstanding shares of Common Stock of the Company. The stock options become exercisable from time to time in part or as a whole, as the Compensation Committee (the Committee), appointed by the Board of Directors, or the Board of Directors in their discretion may provide. However, the Committee shall not grant options which may become exercisable in any one calendar year to purchase more than one-third of the maximum amount granted. All options expire five years after the date of grant. The price of options granted may not be less than eighty-five percent of the fair market value of the Stock on the date the option is granted. Optionees must continue their association with the Company for six months after exercising the options, or the underlying stock reverts to the Company. All shares issued for options exercised in the current year are restricted at December 31, 1999. The Company's previous stock option plan, with terms and conditions essentially the same as those of the Plan, expired in 1995.
At December 31, 1999 the Company has reserved a total of 519,229 shares of Common Stock for issuance under the above mentioned stock option plans, of which 85,324 shares relate to options granted prior to 1996, under the previous 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:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EXERCISE PRICE PER SHARE --------------- SHARES FROM TO -------- ----- ----- Balance, December 31, 1997 ......... 196,016 2.391 4.383 ======== ===== =====
Expired ........................ (32,005) 4.383 2.789 Exercised ...................... (12,780) 2.789 2.789 -------- ----- ----- Balance, December 31, 1998 ......... 151,231 2.789 4.383 ======== ===== ===== Granted ........................ 72,100 3.125 5.000 Expired ........................ (14,223) 4.383 2.789 Exercised ...................... (32,004) 2.789 4.383 -------- ----- ----- Balance, December 31, 1999 ......... 177,104 2.789 5.000 ======== ===== =====
The weighted average exercise price per share was $3.606 and $2.789 in 1999 and 1998, respectively.
As of December 31, 1999, options for 81,478 shares of stock were immediately exercisable. There were 72,100 options granted in 1999. Pursuant to the requirements of FASB No. 123, the weighted average fair market value of options granted during 1999 and 1997 are $1.57 and $2.66, respectively. The weighted average closing bid prices for the Company's stock at the date the options were granted during 1999 and 1997 are $3.34 and $4.50, respectively. The fair market value pursuant to FASB No. 123 of each option granted is estimated on the date of grant using the Black-Scholes options-pricing model. The model assumed expected volatility of 61% and 80% and risk-free interest rates of 3.75% for grants in 1999 and 1997, and an expected life of 3 years. As the Company has not declared dividends since it became a public entity, no dividend yield was used. Actual value realized, if any, is dependent on the future performance of the Company's Common Stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Black-Scholes model.
As discussed in Note 1, no compensation expense has been recorded in 1999, 1998, and 1997 for stock options granted. Had compensation cost for the Company's stock option plans been determined based on the fair market value at the grant dates for awards made after December 31, 1996 under those plans, the Company's net income
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(loss) and earnings (loss) per share would have been reduced to the pro forma amounts indicated below:
YEAR ENDED DECEMBER 31, ----------------------------------- 1999 1998 1997 ---------- ---------- -------- Net income (loss) As reported $(2,086,511) $(9,059,979) $983,095 Pro forma (2,190,033) (9,172,801) 801,555 Basic earnings (loss) As reported (0.43) (2.02) 0.22 per share Pro forma (0.45) (2.04) 0.18 Diluted earnings As reported (0.43) (2.02) 0.22 (loss) per share Pro forma (0.45) (2.04) 0.18
Outstanding options at December 31, 1999 expire between August 18, 2000 and January 14, 2004.
Under the provisions of SFAS No. 123, the pro forma disclosures above include only the effects of stock options granted by the Company subsequent to December 31, 1994. During this initial phase-in period, the pro forma disclosures as required by SFAS No. 123 are not representative of the effects on reported net income for future years as options vest over several years and additional awards are generally made each year and there is a risk of forfeiture.
(7) RELATED PARTY TRANSACTIONS
Related party transactions which are not disclosed elsewhere in these consolidated financial statements are discussed in the following paragraph.
In June 1999, the Company received $1,960,000 through a private placement of 392,000 shares of its' common stock, $.01 par value per share, at $5.00 per share. A director of the Company participated in the private placement, purchasing 100,000 shares.
In order to provide funding for the acquisition of ARO in December 1999, the Company arranged a private placement and conversion of principal and accrued interest on promissory notes into common stock, $.01 par value per share, of 701,820 shares and 314,898 shares, respectively. The shares were issued at a price of $6.00 per share. Consideration for the common stock sold consisted of approximately
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$4,210,919 cash and the surrender of approximately $1,811,555 of the Company's promissory notes due December 31, 2000, along with accrued interest of $77,835 through December 1, 1999. Three directors of the Company participated in this private placement; one director paid $100,002 for 16,667 shares and tendered a note in the amount of $95,761 plus accrued interest of $4,114 and cash $325 for 16,700 shares, another director tendered a note in the amount of $179,921 plus accrued interest of $7,730 and cash $149 for 31,300 shares and a third director tendered a note in the amount of $26,769 plus accrued interest of $1,150 and cash $281 for 4,700 shares.
On December 1, 1999, the Company issued a $1,000,000 promissory note to a director of the Company. The note is due June 1, 2000 bears interest at 10% per annum, and is convertible into common stock at $6.60 per share.
In 1992, the Company entered into a contract with a company, in which a director of the Company is a principal, for business development consulting services. The Company paid $71,250 and $90,000 under the contract in 1998 and 1997, respectively. The contract was terminated October 15, 1998.
(8) LEASES
The Company has various noncancelable operating leases which continue through 2006.
The following is a schedule of future minimum lease payments required under noncancelable operating leases at December 31, 1999:
YEARS ENDING DECEMBER 31, ------------ 2000 $173,113 2001 180,473 2002 180,473 2003 180,473 Thereafter 541,419 ---------- $1,255,951 ==========
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rental expense under operating leases for the years indicated are as follows:
YEARS ENDED DECEMBER 31, ------------ 1999 $136,310 1998 119,490 1997 222,838
(9) COMMITMENTS AND CONTINGENCIES
In 1993, the United States Department of the Interior, Minerals Management Service (MMS) required the Company's wholly-owned subsidiary, Blue Dolphin Exploration Company (BDEX), to provide additional security to ensure it could meet the future abandonment and site clearance obligations associated with the Buccaneer Field. In February 1994, BDEX 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 and site clearance obligations, in February 1994, BDEX provided the MMS with a $700,000 supplemental surety bond. In October 1996, BDEX provided the MMS with an additional $600,000 supplemental surety bond. The Company's annual abandonment escrow fund payment of $250,000 that was due in June 1999 was not made as a result of the removal of the inactive satellite platform in 1999 at a cost of approximately $345,000.
Additionally, a sinking fund was established in 1994 wherein $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. The Company estimates the remaining useful life of its major Buccaneer Field facilities to be in excess of ten years.
The Company is involved in various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material effect on the Company's financial position, results of operations or cash flows.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(10) BUSINESS SEGMENT INFORMATION
The Company's income producing operations are conducted in two principal business segments: oil and gas exploration and production, and pipeline operations. Intersegment revenues consist of transportation, general processing and storage fees charged by certain subsidiaries to another for natural gas and crude oil transported through the Blue Dolphin Pipeline System. The intercompany revenues and expenses are eliminated in consolidation. Information concerning these segments for the years ended December 31, 1999, 1998, and 1997 is as follow:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Consolidated income from operations includes $602,845, $564,584 and $373,040 in unallocated general and administrative expenses, and unallocated depletion, depreciation and amortization of $37,245, $28,512 and $27,391 for the years ended December 31, 1999, 1998 and 1997, respectively.
(2) Pipeline depletion, depreciation and amortization includes a provision for pipeline abandonment of $20,840, $26,340 and $26,340, for the years ended December 31, 1999, 1998 and 1997 respectfully. Oil and gas depletion, depreciation and amortization includes a provision for abandonment costs of platforms and wells of $17,656, $30,378 and $28,466 for the years ended December 31, 1999, 1998 and 1997, 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 $3,028,216 were incurred for pipeline operations for the year ended December 31, 1999.
The Company's primary market area is the Texas Gulf Coast region of the United States. The Company has a concentration of credit risk with customers in the energy and petro 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. Revenues from major customers exceeding 10% of segment revenues were as follows for the periods indicated:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS SALES AND PIPELINE OPERATING FEES OPERATIONS TOTAL -------------- ---------- ---------
Year ended December 31,1999: Apache Corporation ........... $295,525 723,437 1,018,962 The Dow Chemical Company 227,778 22,512 250,290
Year ended December 31, 1998 Apache Corporation ........... $333,787 1,504,375 1,838,162 The Dow Chemical Company 391,913 46,119 438,032 Burlington Resources ......... -- 429,186 429,186
Year ended December 31, 1997 Apache Corporation ........... $359,376 1,466,621 1,825,997 The Coastal Corporation ...... 39,905 1,111,885 1,151,790 Burlington Resources ......... -- 642,492 642,492 The Dow Chemical Company ..... 393,443 114,381 507,824
(11) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding the oil and gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission (SEC) and SFAS No. 69 DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Statement 69).
At December 31, 1999, the Buccaneer Field accounted for 83% of the Company's future net cash flows from proved reserves.
The timing and amount of estimated future development costs may significantly increase or decrease the Company's total proved and proved developed reserve volumes, the Standardized Measure of Discounted Future Net Cash Flows, and the components and changes therein.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated quantities of the Company's crude oil and condensate, and natural gas reserves for the periods
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
indicated, as estimated by the Company (Buccaneer Field), Netherland Sewell & Associates Inc. (ARO) and Ryder Scott Company (ARO). 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 method.
OIL GAS QUANTITY OF OIL AND GAS RESERVES (BBLS) (MCF) -------------------------------- ------- ---------- Total proved reserves at December 31, 1995 ....... 202,166 33,097,136 ------- ---------- Revisions to previous estimates .................. (6,477) (201,823) Production ....................................... (1,887) (180,269) ------- ---------- Total proved reserves at December 31, 1996 ....... 193,802 32,715,044 ------- ---------- Revisions to previous estimates .................. (8,500) (1,125,504) Production ....................................... (1,156) (176,986) ------- ---------- Total proved reserves at December 31, 1997 ....... 184,146 31,412,554 ======= ========== Revisions to previous estimates .................. 6,743 (40,387) Production ....................................... (1,628) (177,260) ------- ---------- Total proved reserves at December 31, 1998 ....... 189,261 31,194,907 ======= ========== Acquisitions ..................................... 150,012 4,419,130 Revisions to previous estimates .................. (637) (102,873) Production ....................................... (6,338) (169,329) ------- ---------- Total proved reserves at December 31, 1999 . 332,298 35,341,835 ======= ==========
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Proved developed reserves:
December 31, 1999 205,525 20,400,120 December 31, 1998 113,183 18,070,961 December 31, 1997 108,068 18,288,608
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, ------------------------------ 1999 1998 ------------ ------------ Unproved properties and prospect generation costs not being amortized ........ $ 837,745 2,823,357 Proved properties being amortized ........................ 25,018,089 18,387,449 Less accumulated depletion, depreciation, amortization and impairment ................... (16,129,385) (15,957,436) ------------ ------------ Net capitalized costs ...... $ 9,726,449 5,253,370 ============ ============ Accrued offshore platform and well abandonment costs ........... $ (619,123) (292,081)
At December 31, 1998 the Company recorded an impairment charge on its oil and gas properties and certain exploration activity costs of $12,011,544, resulting from lower oil and gas prices and changes to its development plans, whereby development of oil and gas properties have been deferred.
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas property acquisition, exploration and development activities during the periods indicated:
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- Property acquisition costs ... $4,538,939 -- 471,861 Exploration costs ............ -- 277,501 -- Development costs ............ -- -- 23,685 ---------- ---------- ---------- $4,538,939 277,501 495,546 ========== ========== ========== Depletion expense per Mcf equivalent produced $0.57 1.03 0.95 ========== ========== ==========
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, --------------------------- 1999 1998 ------------ ----------- Future cash inflows ................... $84,435,405 60,296,555 Future development costs .............. (12,317,244) (9,782,601) Future production costs ............... (26,935,544) (25,093,865) ------------ ----------- Future net cash inflows before income taxes ................ 45,182,617 25,420,089 Future income taxes ................... (887,386) (213,271) ------------ ----------- Future net cash flows ................. 44,295,231 25,206,818 10% discount factor ................... (28,156,875) (19,235,787) ------------ ----------- Standardized measure of discounted future net cash inflow ......... $16,138,356 5,971,031 ============ ===========
Future net cash flows at each year end, as reported in the above schedule, were determined by summing the estimated annual net cash flows computed by: (1) multiplying estimated quantities of proved reserves to be produced during each year
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
by current prices (at December 31, 1999, such prices were $24.66 per barrel of oil and $2.16 per Mcf of gas) and (2) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on current costs).
Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and available net operating loss carryforwards. The annual future net cash flows were discounted, using a prescribed 10% rate, and summed to determine the standardized measure of discounted future net cash flow.
The Company cautions readers that the standardized measure information which places a value on proved reserves is not indicative of either fair market value or present value of future cash flows. Other logical assumptions could have been used for this computation 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.
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Principal changes in the STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS attributable to the Company's proved oil and gas reserves for the periods indicated are as follows:
DECEMBER 31, ------------------------------------------ 1999 1998 1997 ----------- ------------ ------------ Sales and transfers, net of production costs* . $ 555,450 433,346 489,564 Acquisitions of reserves .... 4,897,819 -- -- Net change in estimated future development costs . (1,579,537) 18,918 165,389 Net change in income taxes .. (674,115) 5,322,055 267,388 Revisions in previous quantity estimates ....... (86,430) 34 (996,557) Net changes in sales and transfer prices, net of production costs ...... 8,752,455 (10,944,737) (548,223) Accretion of discount ....... 618,430 2,277,393 2,432,226 Change in production rates (timing) and other ........ (2,316,747) (7,835,514) (3,090,710) ----------- ------------ ------------ Net change ........... $10,167,325 (10,728,505) (1,280,923) =========== ============ ============
*18% of the Company's estimated proved oil reserves and 5% of its estimated proved gas reserves were being produced at December 31, 1999
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 is incorporated by reference to the Company's definitive proxy statement relating to its 2000 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference to the Company's definitive proxy statement relating to its 2000 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated by reference to the Company's definitive proxy statement relating to its 2000 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is incorporated by reference to the Company's definitive proxy statement relating to its 2000 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
The following financial statements and the Report of Independent Public Accountants are filed as a part of this report on the pages indicated:
PAGE
Consolidated Balance Sheets, at December 31, 1999 and 1998...................................................... 26
Consolidated Statements of Operations, for the years ended December 31, 1999, 1998, and 1997................... 28
Consolidated Statements of Stockholders' Equity, for the years ended December 31, 1999, 1998, and 1997......... 29
Consolidated Statements of Cash Flows, for the years ended December 31, 1999, 1998, and 1997................... 30
Notes to Consolidated Financial Statements.................. 32
(a) 2. Exhibits
NO. DESCRIPTION ---- -----------
3.1 (1) Certificate of Incorporation of the Company.
3.2 (2) Certificate of Correction to the Certificate of Incorporation of the Company dated June 30, 1987.
3.3 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated June 30, 1987.
3.4 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 11, 1989.
3.5 (2) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 14, 1989.
3.6 (2) Bylaws of the Company.
3.7 (6) Certificate of Amendment to the Certificate of Incorporation of the Company dated December 8, 1997.
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock.
* 10.1 (1) Blue Dolphin Energy Company 1985 Employee Stock Option Plan.
* 10.2 (4) Blue Dolphin Energy Company 1996 Employee Stock Option Plan.
10.4 (3) Loan Agreement by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. dba MEI Mission
Energy, Inc., Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated January 14, 1994.
10.6 (4) First Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N.A., dated February 7, 1995.
10.7 (4) Second Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue Dolphin Exploration Company, previously known as Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated December 22, 1995.
10.8 (5) Third Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue Dolphin Exploration Company, previously known as Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated November 5, 1996.
10.9 Fourth Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue Dolphin Exploration Company, previously known as Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated August 18, 1998.
10.10 Fifth Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue Dolphin Exploration Company, previously known as Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated December 17, 1999.
10.11 Sixth Amendment to Loan Agreement dated January 14, 1994 by and among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc., Blue Dolphin Exploration Company, previously known as Ivory Production Co., Blue Dolphin Services Co., and Bank One, Texas, N. A., dated January 12, 2000.
10.12 (7) Asset Purchase Agreement between WBI Southern, Inc., Blue Dolphin Pipeline Company, Buccaneer Pipe Line Co. and Mission Energy, Inc.
10.13 (7) Purchase and Sale Agreement between Enron Pipeline Company, Black Marlin Energy Company and Blue Dolphin Energy Company.
10.14 (7) Asset Purchase Agreement between WBI Southern, Inc., Black Marlin Pipeline Company and Black Marlin Energy Company.
10.15 (7) Asset Purchase Agreement between MCNIC Offshore Pipeline & Processing Company, Black Marlin Pipeline Company and Black Marlin Energy Company.
10.16 (8) Investment Agreement, as amended, by and between American Resources Offshore, Inc. and Blue Dolphin Exploration Company.
10.17 Management Services Agreement by and between Fidelity Oil Holdings, Inc. and Blue Dolphin Exploration Company.
21.1 List of Subsidiaries of the Company.
23.1 Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
23.2 Consent of Ryder Scott Company, 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 (Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1993 under the Securities and Exchange Act of 1934, dated March 30, 1994 (Commission File No. 000-15905).
(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, 1995 under the Securities and Exchange Act of 1934, dated March 29, 1996 (Commission File No. 000-15905).
(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, 1996 under the Securities and Exchange Act of 1934, dated March 31, 1997 (Commission File No. 000-15905).
(6) Incorporated herein by reference to Exhibits filed in connection with the definitive Information Statement on Schedule 14C of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated November 18, 1997 (Commission File No. 000-15905).
(7) Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated March 1, 1999 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with Schedule 13D of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated October 22, 1999 (commissions File No. 000-15905).
* Management Compensation Plan.
(b) Reports on Form 8-K
On December 7, 1999, the Company filed a current report on Form 8-K dated December 2, 1999 that it closed the purchase of 39,509,457 shares of common stock of American Resources Offshore, Inc. The items reported in such current report were Item 2 (Acquisitions or Dispositions of Assets) and Item 7 (Financial Statement and Exhibits).
On December 17, 1999, the Company filed a current report on Form 8-KA dated December 17, 1999, with respect to the acquisition of American Resources Offshore, Inc. The items reported in such current report were Item 2 (Acquisitions or Dispositions of Assets) and Item 7 (Financial Statement and Exhibits).
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: April 13, 2000
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 April 13, 2000 - ------------------------- executive officer) Michael J. Jacobson
/s/ G. BRIAN LLOYD Vice President, Treasurer April 13, 2000 - ------------------------- (principal accounting G. Brian Lloyd officer)
/s/ IVAR SIEM Chairman April 13, 2000 - ------------------------- Ivar Siem
/s/ HARRIS A. KAFFIE Director April 13, 2000 - ------------------------- Harris A. Kaffie
/s/ DANIEL B. PORTER Director April 13, 2000 - ------------------------- Daniel B. Porter
/s/ MICHAEL S. CHADWICK Director April 13, 2000 - ------------------------- Michael S. Chadwick