Blue Dolphin Energy Company, a Delaware corporation formed in 1986, is a holding company and conducts substantially all of its operations through its subsidiaries. We conduct our business activities in two primary business segments: (i) pipeline transportation and related services for producer/shippers, and (ii) oil and gas exploration and production. Substantially all of our assets consist of equity interests in our subsidiaries. Our operating subsidiaries are:
- Blue Dolphin Pipe Line Company, a Delaware corporation;
- Blue Dolphin Petroleum Company, a Delaware corporation;
- Blue Dolphin Exploration Company, a Delaware corporation; and
- Blue Dolphin Services Co., a Texas corporation.
Our principal executive office is located at 801 Travis, Suite 2100, Houston, Texas, 77002, and our telephone number is (713) 227-7660. Our shore-based facilities are maintained in Freeport, Texas, and serve our Gulf of Mexico operations. We have 7 full-time employees. Our common stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") Small Cap
Market under the trading symbol "BDCO." Our home page address on the world wide web is http://www.blue-dolphin.com.
Certain terms that are commonly used in the oil and gas industry, including terms that define our rights and obligations with respect to our properties, are defined in the "Glossary of Certain Oil and Gas Terms" of this Form 10-KSB.
RECENT DEVELOPMENTS
In March 2006, we entered into a stock purchase agreement with certain accredited investors for the private placement of 1,171,432 shares of our common stock at a purchase price of $1.75 per share. The net proceeds from the offering after the payment of commissions and expenses were approximately $2,025,000. The Company expects to use the proceeds for possible acquisitions and planned expansions of its facilities, as well as for working capital needs and general corporate purposes. In addition, in connection with the terms of the placement agency agreement with Starlight Investments, LLC, we issued warrants to purchase an aggregate of 8,572 shares of common stock. The warrants vest immediately upon issuance and the exercise price per share varies based on the following conditions: (i) until the later of the registration of the warrants or one year from the issue date, 110% of the purchase price per share in the offering, (ii) from the later of (x) the registration of the warrants and (y) one year, until two years from the issue date, 120% of the purchase price per share in the offering and (iii) after the expiration of two years from the issue date of the warrants, 130% of the purchase price per share in the offering.
During the final two quarters of 2005, we entered into gas and condensate transportation and handling agreements with three new shippers on the Blue Dolphin Pipeline System. The first agreements were entered into with Manti Operating Company ("Manti") on July 12, 2005 to deliver production into the Blue Dolphin System in Galveston area state tract 348. We began providing transportation and handling services to Manti when it commenced production in August 2005. We entered into agreements with the second new shipper on September 28, 2005 to provide transportation and handling services for production delivered into the Blue Dolphin Pipeline System at our Galveston Block 288C platform. Agreements were signed with the third new shipper on October 12, 2005. The second and third new shippers are expected to commence production around mid-year 2006.
In September 2005, we began receiving payments for an approximate 2.8% contractual after-payout working interest realized in High Island Block 37. We received an initial payment of approximately $1.3 million on September 2, 2005, representing our share of net revenues from the estimated payout date of July 1, 2004 through May 2005. Through December 31, 2005, we received four payments totaling approximately $1,769,000 and recognized net revenues of $2,397,000 for our working interest in the sale of gas and oil from two producing wells in the block. The two wells are currently producing at a combined rate of approximately 23 MMcf per day.
Also in September 2005, High Island Block A-7 resumed production after the successful recompletion of two wells. Prior to the recompletions, the block was generating production from a single well. This well had generated significant revenues for us in 2003 when our back-in interest initially paid out, and to a lesser extent in 2004; however, production had declined naturally over time. The well had averaged less than 1 MMcf per day for the first and second quarters of 2005, prior to recompletion. The two wells initially produced at a combined rate of approximately 10 MMcf per day when production was resumed, however, the wells were shut-in when Hurricane Rita struck in mid-September. Production was delayed for a period of time while 3rd party transporters made repairs following Hurricane Rita. Production was re-established for one well in late October and in early November for the second well. Only one of the wells is currently producing. Production from that well is currently approximately 7 MMcf per day.
On February 28, 2005 (effective as of January 1, 2005), we entered into an amendment (the "Amendment") to the Asset Purchase Agreement dated February 1, 2002 (the "Purchase Agreement") with MCNIC Offshore Pipeline and Processing Company ("MCNIC"). Under the terms of the original
Purchase Agreement, we acquired MCNIC's one-third interests in both the Blue Dolphin System (as described below in "Pipeline Operations and Activities") and the inactive Omega Pipeline. Pursuant to the terms of the Amendment, the promissory note that we originally issued to MCNIC in the principal amount of $750,000 due December 31, 2006 (the "Original Promissory Note") was exchanged for a new non-interest bearing promissory note in the principal amount of $250,000 (the "New Promissory Note"), and all accrued interest on the Original Promissory Note, $132,368 at December 31, 2004, was forgiven. In addition to the New Promissory Note, MCNIC can receive additional payments of up to $500,000 from 50% of the net profits, if any, realized from the one-third interest in the Blue Dolphin System through December 31, 2006. We made a principal payment on the New Promissory Note of $30,000 upon the execution of the Amendment. Under the terms of the New Promissory Note we will make monthly principal payments of $10,000 through its maturity date of December 31, 2006. The principal amount of the New Promissory Note may be increased by up to $500,000 if we sell 50% or more of our 83% interest in the Blue Dolphin System before December 31, 2006. The maximum amount of additional payments MCNIC could receive over the $250,000 New Promissory Note is $500,000.
PIPELINE OPERATIONS AND ACTIVITIES
Our pipeline assets are held in, and operations conducted by, Blue Dolphin Pipe Line Company.
The economic return on our pipeline system investments is solely dependent upon the amounts of gas and condensate gathered and transported through our pipeline systems. Currently, the level of throughput on our pipeline systems is significantly below full capacity. Competition for provision of gathering and transportation services similar to ours is intense in the market areas we serve. See "Competition" below. Since contracts for gathering and transportation services with third party producer/shippers may be for specified time periods, 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 will be maintained in the future. We actively market our gathering and transportation services to producer/shippers operating in the vicinity of our pipeline systems. Future utilization of the pipelines and related facilities will depend upon the success of drilling programs around the pipelines, and the attraction, and retention, of producer/shippers to the systems.
Blue Dolphin Pipeline System. The Blue Dolphin Pipeline System includes the Blue Dolphin Pipeline, an offshore platform, the Buccaneer Pipeline, onshore facilities for condensate and gas separation and dehydration, 85,000 Bbls of above-ground tankage for storage of crude oil and condensate, a barge loading terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the pipeline system shore facilities, pipeline easements and rights-of-way are located (the "Blue Dolphin System"). We own an 83% undivided interest in the Blue Dolphin System. The Blue Dolphin System gathers and transports gas and condensate from various offshore fields in the Galveston Area in the Gulf of Mexico to shore facilities located in Freeport, Texas. After processing, the gas is transported to an end user and a major intrastate pipeline system with further downstream tie-ins to other intrastate and interstate pipeline systems and end users.
The Blue Dolphin Pipeline consists of two segments. The offshore segment transports both gas and liquids (crude oil and condensate) and is comprised of approximately 34 miles of 20-inch pipeline from a platform in Galveston Area Block 288 to shore. The offshore segment includes a platform and 5 field gathering lines totaling approximately 27 miles, connected to the main 20-inch line. An additional 4 miles of 20-inch pipeline onshore connects the offshore segment to the onshore facility at Freeport, Texas. The onshore segment consists of approximately 2 miles of 16-inch pipeline for transportation of gas from the shore facility to a sales point at a Freeport, Texas chemical plants' complex and intrastate pipeline system tie-in. The Buccaneer Pipeline, an 8-inch liquids pipeline, transports crude oil and condensate from the storage tanks to our barge-loading terminal on the Intracoastal Waterway near Freeport, Texas for sale to third parties.
Various fees are charged to producer/shippers for provision of transportation and shore facility services. The Blue Dolphin System has an aggregate capacity of approximately 160 MMcf per day of gas and 7,000 Bbls per day of crude oil and condensate. Gas throughput for the Blue Dolphin System averaged approximately 6% and 4% of capacity during 2005 and 2004, respectively. Currently, the Blue Dolphin System is transporting approximately 9 MMcf of gas per day. All gas and liquids volumes transported in 2005 and 2004 were attributable to production from third party producer/shippers. See Note 12 to the Consolidated Financial Statements included in Item 7.
During late 2004, due to operating losses incurred by us on the Blue Dolphin System, we renegotiated our gas transportation rates with our shippers, effective October 1, 2004. As a result, 2005 gas transportation revenues from the Blue Dolphin System totaled approximately $1,154,000. Without the increase in rates, gas transportation revenues for 2005 would have been 56% less; approximately $505,000.
Galveston Area Block 350 Pipeline. We own an 83% ownership interest in an 8-inch, 12.78 mile pipeline extending from Galveston Area Block 350 to an interconnect with a transmission pipeline in Galveston Area Block 391 (the "GA 350 Pipeline"), approximately 14 miles south of the Blue Dolphin Pipeline. Current system capacity on the GA 350 Pipeline is 65 MMcf of gas per day. Gas throughput for the GA 350 Pipeline averaged approximately 18% and 26% of capacity during 2005 and 2004, respectively. The pipeline currently transports approximately 9 MMcf of gas per day. All gas and liquids volumes transported were attributable to production from third party producer/ shippers.
Other. We also own an 83% undivided interest in the Omega Pipeline, which is currently inactive. The Omega Pipeline originates in the High Island Area, East Addition Block A-173 and extends to West Cameron Block 342 , where it was previously connected to the High Island Offshore System ("HIOS"). Reactivation of the Omega Pipeline will be dependent upon future drilling activity in the vicinity and successfully attracting producer/shippers to the system.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Although we sold substantially all of our producing oil and gas properties in 2002, we continue our oil and gas exploration and production activities, which include the exploration, acquisition, development, operation and, when appropriate, disposition of oil and gas properties. We focus our oil and gas activities in the western Gulf of Mexico, off the coast of Texas. We currently own seismic and other data that may be used to evaluate and develop prospects, including a non-exclusive license to approximately 200 blocks of 3-D seismic data covering 1,152,000 acres in the western Gulf of Mexico and a substantial inventory of close grid 2-D seismic data. Our oil and gas assets are held by Blue Dolphin Petroleum Company and Blue Dolphin Exploration Company.
The leasehold interests we hold in properties are subject to royalty, overriding royalty and interests of others. In the future, our properties may become subject to burdens and encumbrances typical to oil and gas operators, such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances.
The following is a description of our oil and gas exploration and production assets and activities:
High Island Block 37. High Island Block 37 is located 15 miles south of Sabine Pass, offshore Texas, in an average water depth of 36 feet. We own an approximate 2.8% contractual working interest in this lease that covers approximately 5,760 acres. The lease contains two producing wells which are operated by Seneca Resources Corporation. For the year ended December 31, 2005, we recorded gross revenues from sales of gas and oil in High Island Block 37 of approximately $2,414,000.
High Island Block A-7. High Island Block A-7 is located 33 miles southeast of Boliver Peninsula, offshore Texas, in an average water depth of 39 feet. We own an 8.9% working interest in this lease that
covers approximately 5,760 acres. The lease contains one currently producing well which is operated by Hydro Gulf of Mexico, LLC (formerly Spinnaker Exploration Company). During the years ended December 31, 2005 and 2004, we recorded gross revenues from gas and oil sales of approximately $722,000 and $332,000, respectively, from this field.
Unproved Leasehold Interests. Our prospect inventory consists of one prospect on the offshore lease for West Cameron Area Block 212. A prospect is a property in which we own an interest or have operating rights and have what we believe, based on available seismic and geological information, to be indications of oil or natural gas.
In December 2004, we placed our interest in Galveston Area Blocks 287 and 297 in the Gulf of Mexico with third parties. These blocks were part of a prospect we generated which also included Galveston Area Block 298. A well was drilled in Galveston Area Block 297, which was not successful. As a result of the placement of our working interest in Galveston Area Blocks 287 and 297, we received proceeds of approximately $160,000. The leases for Galveston Area Blocks 287 and 297 have now expired.
In November 2005, the leases covering our interests in Galveston Area Blocks 271 and 284 expired.
Abandonment of Buccaneer Field. We owned a 100% working interest in the Buccaneer Field. In November 2000, we elected to abandon the Buccaneer Field due to adverse developments in the field. In August 2001, we reached an agreement with Tetra Applied Technologies, Inc. ("Tetra") to remove the Buccaneer Field platforms for a cost of approximately $2.6 million on extended payment terms. To provide security for the extended payment terms, we provided Tetra with a first lien on a 50% interest in the Blue Dolphin System. Operations to remove the platforms commenced in August 2001 and were completed in August 2003. Before the removal operations were completed we commenced discussions with the Texas Parks and Wildlife Department ("TPW"), and were granted permission to leave the underwater portion of the platforms in place as artificial reefs. As a result of TPW's approval, the scope of the work to be performed by Tetra was changed to include reefing, instead of complete removal. Pursuant to the Deeds of Donation with TPW, we agreed to pay TPW $390,000, of which $350,000 represented half of the site clearance work that was eliminated and $40,000 represented the cost of buoys to mark the reef sites. While the scope of work with Tetra was changed, the contract price and payment terms remained unchanged. Our payments to Tetra began in September 2003. In August 2004, we negotiated an extension of the payment terms of our remaining indebtedness to Tetra in the amount of $668,000 originally due in September and October 2004. Under the new terms we agreed to pay the outstanding balance to Tetra in twelve monthly installments of $55,667 beginning September 1, 2004, plus interest on the outstanding balance at the rate of 6% per annum. On August 1, 2005, we made our final payment to Tetra.
Proved Oil and Gas Reserves. We have prepared estimates of proved reserves, future net revenues, and discounted present value of future net revenues to our net interest as of December 31, 2005.
The quantities of proved oil and gas reserves presented below include only those amounts which we reasonably expect 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 at prices and costs, and under regulatory practices and technology existing at the time of the estimate. Accordingly, changes in oil and gas prices, operation and development costs, regulations, technology, future production and other factors, many of which are beyond our control, could significantly affect the estimates of proved reserves and the discounted present value of future net revenues attributable thereto.
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 our proved reserves, changes in proved reserves, estimated future net revenues and costs incurred in our oil and gas activities and the
discounted present value of estimated future net revenues from our proved reserves, see Note 13, Supplemental Oil and Gas Information, to the Consolidated Financial Statements included in Item 7.
The following table presents the estimates of proved reserves, proved developed reserves, and proved undeveloped reserves (as hereinafter defined), future net revenues and the discounted present value of future net revenues from proved reserves after income taxes to our net interest in oil and gas properties as of December 31, 2005. The discounted present value of future net revenues and future net revenues are calculated using the SEC Method (defined below) and are not intended to represent the current market value of the oil and gas reserves we own.
PROVED RESERVES As of December 31, 2005 (1)(2)
---------- (1) The estimated present value of future net cash outflows after income taxes from our proved reserves has been determined by using prices of $56.00 per barrel of oil and $11.00 per Mcf of gas, representing the December 31, 2005 prices for oil and gas and discounted at a 10% annual rate in accordance with requirements for reporting oil and gas reserves pursuant to regulations promulgated by the United States Securities and Exchange Commission (the "SEC Method").
(2) As of December 31, 2005, we reported no proved undeveloped reserves.
Capital Expenditures for Proved Reserves. The following table presents information regarding the costs we expect to incur in development activities associated with our proved reserves. These expenditures include recompletion costs, workover costs and the cost of drilling additional wells required to recover proved reserves and the plugging and abandonment of wells. The information regarding proved reserves summarized in the preceding table assumes the following estimated undiscounted capital expenditures in the years indicated.
We will continue to evaluate our capital expenditure program based on, among other things, demand and prices obtainable for our production. The availability of capital resources and the willingness of other working interest owners to participate in development operations may affect the timing for further development, and there can be no assurance that the timing of the development of such reserves will be as currently planned.
Production, Price and Cost Data. The following table presents information regarding production volumes and revenues, average sales prices and costs (after deduction of royalties and interests of others) with respect to crude oil, condensate, and gas attributable to our interest for each of the periods indicated.
NET PRODUCTION, PRICE AND COST DATA
---------- (*) Average production is based on a 365 day year. However, 2005 average production per day contains 549 days of production from High Island Block 37 and 2003 contains 255 days of production.
(**) Production costs, exclusive of workover costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes.
Drilling Activity. During September 2005, two wells in High Island Block A-7 were successfully recompleted and resumed production at a significantly higher rate than the single well that produced through the first and second quarters of 2005. The single well averaged less than 1 MMcf per day during the first and second quarters. The two recompleted wells averaged 5.4 MMcf per day during the fourth quarter, including the period of time that the wells were shut in. Capital expenditures for the recompletions net to our interest totaled approximately $71,000.
EMPLOYEES
We maintain a professional staff of seven full-time employees and two consultants capable of supervising and coordinating the operation and administration of our oil and gas properties and pipeline and other
assets. From time to time, major maintenance, engineering and construction projects are contracted to third-party engineering and service companies.
CUSTOMERS
We generated revenues from both of our primary business segments. Hydro Gulf, LLC and Fidelity Exploration and Production Company accounted for approximately 16.0% and 53.5%, respectively, of our revenues in 2005. Revenues from customers exceeding 10% of revenues were as follows for 2005 and 2004:
COMPETITION
All segments of our business are highly competitive. Vigorous competition occurs among oil, gas and other energy sources, and between producers, transporters, and distributors of oil and gas. Our pipeline business faces competition from other pipelines in the markets that we serve. The principal elements of competition among pipelines are rates, terms of service, access to markets, flexibility and reliability of service. Our oil and natural gas business competes for the acquisition of oil and natural gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities, including major oil companies, independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours, which give them an advantage over us in evaluating and obtaining properties and prospects. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. There is also competition for the hiring of experienced personnel to manage and operate our assets. Several highly competitive alternative transportation and delivery options exist for current and potential customers of our traditional gas and oil gathering and transportation business. Competition also exists with other industries in supplying the energy and fuel needs of consumers.
MARKETS
The availability of a ready market for oil and gas, and the prices of such oil and gas, depends upon a number of factors, which are beyond our control. These include, among other things:
- the level of domestic production;
- actions taken by foreign oil and gas producing nations;
- the availability of pipelines with adequate capacity;
- the availability of vessels for direct shipment;
- lightering, transshipment and other means of transportation;
- the availability and marketing of other competitive fuels;
- fluctuating and seasonal demand for oil, gas and refined products; and
- the extent of governmental regulation and taxation (under both present and future legislation) of the production, importation, refining, transportation, pricing, use and allocation of oil, gas, refined products and alternative fuels.
In view of the many uncertainties affecting the supply and demand for crude oil, gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the gas and oil produced for sale or prices chargeable for transportation and storage services, which we provide. Our sale of natural gas is generally made at the market prices at the time of sale. Therefore, even though we sell natural gas to major purchasers, we believe other purchasers would be willing to buy our natural gas at comparable market prices.
GOVERNMENTAL REGULATION
The production, processing, marketing, and transportation of oil and gas by us are subject to federal, state and local regulations which can have a significant impact upon our overall operations.
Federal Regulation of Natural Gas Transportation. The transportation and resale of gas in interstate commerce have been regulated by the Natural Gas Act ("NGA"), the Natural Gas Policy Act ("NGPA"), and the rules and regulations promulgated by the Federal Energy Regulatory Commission ("FERC"). In the past, the federal government has regulated the prices at which gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting producer sales of gas, effective January 1, 1993. The Energy Policy Act of 2005 did not alter our non-FERC-jurisdictional status, but has greatly expanded FERC's authority, including enforcement authority against market manipulation "in connection with" FERC-jurisdictional transactions. The nature and extent of FERC's implementation of its new authorities is not yet known. Additionally, energy pricing has attracted renewed political interest. Thus Congress could reenact price controls in the future. The rates, terms and conditions applicable to interstate transportation of gas by pipelines are regulated by the FERC under the NGA, as well as under Section 311 of the NGPA. In the fall of 2005, FERC launched a Notice of Inquiry into potential additional regulation of offshore gathering operations that, unlike Blue Dolphin Pipe Line Company, are affiliated with interstate pipelines and have the potential to engage in anticompetitive behavior, conditioning access to interstate pipeline service upon use of the affiliated gathering line.
All of our pipelines located offshore in federal waters are subject to the requirements of the Outer Continental Shelf Lands Act ("OCSLA"). The FERC has stated that non-jurisdictional gathering lines, as well as interstate pipelines, are fully subject to the open access and nondiscrimination requirements of OCSLA's Section 5, which generally authorizes the FERC to insure that gas pipelines on the Outer Continental Shelf ("OCS") will transport for non-owner shippers in a nondiscriminatory manner and will be operated in accordance with certain pro-competitive principles.
Further FERC initiatives concerning possibly diminished Natural Gas Act regulation of pipelines on the OCS and/or broader regulation under the OCSLA remain possible and could cause increased regulatory compliance costs. Since all of our offshore pipelines fall within the exemption for feeder facilities and already operate on the basis required under OCSLA, we do not anticipate significant changes directly resulting from requirements concerning nondiscriminatory open access transportation.
Aside from the OCSLA requirements and federal safety and operational regulations, regulation of gas gathering activities is primarily a matter of state oversight. Regulation of gathering activities in Texas
includes various transportation, safety, environmental and non-discriminatory purchase/transport requirements.
Federal Regulation of Oil Pipelines. Our operation of the Buccaneer Pipeline has been subject to a variety of regulations promulgated by the FERC and imposed on all oil pipelines pursuant to federal law. Recently, however, oil pipelines have been granted permanent exemptions from certain FERC filing requirements because of rulings that oil pipeline transportation tariff movements of crude petroleum occurring solely on or across the OCS, or across the OCS to onshore points where transportation ends are not subject to FERC jurisdiction under the OCSLA or the Interstate Commerce Act.
Safety and Operational Regulations. Our operations are generally subject to safety and operational regulations administered primarily by the United States Minerals Management Service ("MMS"), the U.S. Department of Transportation, the U.S. Coast Guard, the FERC and/or various state agencies. In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to leases and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms and structures. Violations of lease conditions or regulations issued pursuant to the OCSLA 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 private prosecution. Currently, we believe that we are in material compliance with the various safety and operational regulations that we are subject to. However, as safety and operational regulations are frequently changed, we are unable to predict the future effect changes in these regulations will have on our operations, if any.
Federal Oil and Gas Leases. All of our exploration and production operations are currently located on federal oil and gas leases in the OCS, which are administered by the MMS. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA that are subject to interpretation and change by the MMS. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurance that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. We are currently in compliance with the bonding requirements of the MMS. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.
With respect to our operations conducted on offshore federal leases, liability may generally be imposed under OCSLA for costs of clean-up and damages caused by pollution resulting from such operations, other than damages caused by acts of war or the negligence of third parties. Under certain circumstances, including but not limited to conditions deemed a threat or harm to the environment, the MMS may also require any of our operations on federal leases to be suspended or terminated in the affected area. Furthermore, the MMS generally requires that offshore facilities be dismantled and removed within one year after production ceases or the lease expires.
Environmental Regulation. Our activities with respect to (1) exploration, development and production of oil and natural gas and (2) the operation and construction of pipelines, plants, and other facilities for the transportation and processing, and storage of oil and natural gas are subject to stringent environmental regulation by local, state and federal authorities, including the U.S. Environmental Protection Agency ("EPA"). Such regulation has increased the cost of planning, designing, drilling, operating and in some
instances, abandoning wells and related equipment. Similarly, such regulation has also increased the cost of design, construction, and operation of crude oil and natural gas pipelines and processing facilities. Although we believe that compliance with existing environmental regulations will not have a material adverse affect on operations or earnings, there can be no assurance that significant costs and liabilities, including civil and criminal penalties, will not be incurred. Moreover, future developments, such as stricter environmental laws and regulations or claims for personal injury or property damage resulting from our operations, could result in substantial costs and liabilities. It is not anticipated that, in response to such regulation, we will be required in the near future to expend amounts that are material relative to our total capital structure.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") imposes liability, without regard to fault or the legality of the original conduct, on responsible parties with respect to the release or threatened release of a "hazardous substance" into the environment. Responsible parties, which include the present owner or operator of a site where the release occurred, the owner or operator of the site at the time of disposal of the hazardous substance, and persons that disposed or arranged for the disposal of a hazardous substance at the site, are liable for response and remediation costs and for damages to natural resources. Petroleum and natural gas are excluded from the definition of "hazardous substances"; however, this exclusion does not apply to all materials used in our operations. At this time, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA.
The federal Resource Conservation and Recovery Act ("RCRA") and its state counterparts regulate solid and hazardous wastes and impose civil and criminal penalties for improper handling and disposal of such wastes. EPA and various state agencies have promulgated regulations that limit the disposal options for such wastes. Certain wastes generated by our oil and gas operations are currently exempt from regulation as "hazardous wastes," but in the future could be designated as "hazardous wastes" under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements.
We currently own or lease, or have in the past owned or leased, various properties used for the exploration and production of oil and gas or used to store and maintain equipment regularly used in these operations. Although our past operating and disposal practices at these properties were standard for the industry at the time, hydrocarbons or other substances may have been disposed of or released on or under these properties or on or under other locations. In addition, many of these properties have been operated by third parties whose waste handling activities were not under our control. These properties and any waste disposed thereon may be subject to CERCLA, RCRA, and state laws which could require us to remove or remediate wastes and other contamination or to perform remedial plugging operations to prevent future contamination.
The Oil Pollution Act of 1990 ("OPA") and regulations promulgated thereunder include a variety of requirements related to the prevention of oil spills and impose liability for damages resulting from such spills. OPA imposes liability on owners and operators of onshore and offshore facilities and pipelines for removal costs and certain public and private damages arising from a spill. OPA establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser liability limits for vessels depending upon their size. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction, or operating regulations. If a party fails to report a spill or cooperate in the cleanup, liability limits likewise do not apply. OPA imposes ongoing requirements on responsible parties, including proof of financial responsibility for potential spills. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges, worst-case spill potential and other factors. We believe we have established adequate financial responsibility. While the financial responsibility requirements under OPA may be amended to impose additional costs on us, the
impact of such a change is not expected to be any more burdensome on us than on others similarly situated.
The Clean Air Act and state air quality laws and regulations contain provisions that impose pollution control requirements on emissions to the air and require permits for construction and operation of certain emissions sources, including sources located offshore. We may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing emission-related issues, although we do not expect to be materially adversely affected by such expenditures.
The Clean Water Act ("CWA") regulates the discharge of pollutants to waters of the United States and imposes permit requirements on such discharges, including discharges to wetlands. Federal regulations under the CWA and OPA require certain owners or operators of facilities that store or otherwise handle oil, to prepare and implement spill prevention, control and countermeasure plans and facility response plans relating to the possible discharge of oil into surface waters. With respect to certain of our operations, we are required to prepare and comply with such plans and to obtain and comply with permits. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide varying civil and criminal penalties and liabilities for the spills to both surface and groundwaters. We believe we are in substantial compliance with the requirements of the CWA, OPA, and state laws, and that any non-compliance would not have a material adverse effect on us.
Various federal and state programs regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act was passed to preserve and, where possible, restore the natural resources of the coastal zone of the United States of America and to provide for federal grants for state management programs that regulate land use, water use and coastal development. Under the Louisiana Coastal Zone Management Program, coastal use permits are required for certain activities, even if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The Texas Coastal Coordination Act ("CCA") establishes the Texas Coastal Management Program that applies in the nineteen Texas counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. These coastal programs may affect agency permitting of our facilities.
Legislation and Rulemaking. In October 1996 the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the OPA to establish requirements for evidence of financial responsibility for certain offshore facilities. The amount required is $35 million for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. We currently maintain this statutory $35 million coverage.
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 our operations.
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 our 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, we will be required in the
near future to expend amounts that are material relative to our 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, we are unable to predict the ultimate cost of compliance.
RISK FACTORS
We are primarily dependent on revenues from our pipeline systems and our working interests in two oil and gas producing properties.
Although revenues from oil and gas sales accounted for approximately 69.5% of our total revenues in 2005, as a result of our sale of substantially all of our proved oil and gas reserves in 2002 and the limited amount of reserves on properties we own interests in, we expect that our future revenues will be primarily dependent on the level of use of our pipeline systems. Various factors will influence the level of use of our pipeline systems including the success of drilling programs in the areas near our pipelines and our ability to attract new producer/shippers. There are various pipelines in and around our pipeline systems that we vigorously compete with to attract new producer/shippers to our pipeline systems. There can be no assurance that we will be successful in attracting new producer/shippers to our pipeline systems.
Furthermore, the rate of production from oil and gas properties generally declines as reserves are depleted. Our working interests are in properties in the Gulf of Mexico where, generally, the rate of production declines more rapidly than in many other producing areas of the world. As the level of production from these properties declines our revenue from these interests will decrease. Unless we are able to replace this revenue, with revenue from interests in other oil and gas properties, increase the level of utilization of our pipelines or acquire other revenue generating assets at an acceptable cost, our revenues and cash flow from operations will decrease.
The geographic concentration of our assets may have a greater effect on us as compared to other companies.
All of our assets are located in the Gulf of Mexico and the onshore gulf coast of Texas. Because our assets are not as diversified geographically as many of our competitors, our business is subject to local conditions more than other, more geographically diversified companies. Any regional events, including price fluctuations, natural disasters, and restrictive regulations, that increase costs, impacts the exploration and development of oil and gas in the Gulf of Mexico, reduce availability of equipment or supplies, reduce demand for oil and gas production may impact our business more than if our assets were geographically diversified.
If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our operations.
We have historically needed substantial amounts of cash to fund our working capital requirements. Because we have experienced a negative working capital position in past years, we have been dependent on debt and equity financing to meet our working capital requirements that were not funded from operations.
Low commodity prices, production problems, declines in production, disappointing drilling results and other factors beyond our control could reduce our funds from operations. As a result we may have to seek debt and equity financing to meet our working capital requirements. Furthermore, we have incurred losses in the past that may affect our ability to obtain financing. In addition, financing may not be available to us
in the future on acceptable terms or at all. In the event additional capital is not available, we may be forced to sell some of our assets on an untimely or unfavorable basis.
We face strong competition from larger companies that may negatively affect our ability to carry on operations.
We operate in a highly competitive industry. Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which possess greater financial and other resources than we do. Our ability to successfully compete in the marketplace is affected by many factors including:
- most of our competitors have greater financial resources than we do, which gives them better access to capital to acquire assets; and
- we often establish a higher standard for the minimum projected rate of return on invested capital than some of our competitors since we cannot afford to absorb certain risks. We believe this puts us at a competitive disadvantage in acquiring pipelines and oil and gas properties.
Oil and gas prices are volatile and a substantial and extended decline in the price of oil and gas would have a material adverse effect on us.
The tightening of natural gas supply and demand fundamentals has resulted in higher, but extremely volatile, natural gas prices, and this volatility in natural gas prices is expected to continue. Our revenues, profitability, operating cash flow and our potential for growth are largely dependent on prevailing oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, uncertainties within the market and a variety of other factors beyond our control. These factors include:
- weather conditions in the United States;
- the condition of the United States economy;
- the actions of the Organization of Petroleum Exporting Countries;
- governmental regulation;
- political stability in the Middle East, South America and elsewhere;
- the foreign supply of oil and gas;
- the price of foreign imports; and
- the availability of alternate fuel sources.
In addition, low or declining oil and gas prices could have collateral effects that could adversely affect us, including the following:
- reducing the exploration for and development of oil and gas reserves held by third party companies around our pipeline systems;
- increasing our dependence on external sources of capital to meet our cash needs; and
- generally impairing our ability to obtain needed capital.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Estimating reserves of oil and gas is complex. The process relies on interpretations of available geologic, geophysics, engineering and production data. The extent, quality and reliability of this data can vary. The process also required certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
- the quality and quantity of available data;
- the interpretation of that data;
- the accuracy of various mandated economic assumptions; and
- the judgment of the persons preparing the estimate.
The proved reserve information set forth in this report is based on estimates we prepared. Estimates prepared by others might differ materially from our estimates.
Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, taxes, development expenditures and operating expenses most likely will vary from our estimates. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing oil and gas prices. Our reserves also may be susceptible to drainage by operators on adjacent properties.
The present value of future net cash flows will most likely not equate to the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs in effect at December 31. Actual future prices and costs may be materially higher or lower than the prices and costs we used.
We cannot control the activities on properties we do not operate.
Currently, other companies operate or control the development of the oil and gas properties in which we have an interest. As a result, we depend on the operator of the wells or leases to properly conduct lease acquisition, drilling, completion and production operations. The failure of an operator, or the drilling contractors and other service providers selected by the operator to properly perform services, or an operator's failure to act in ways that are in our best interest, could adversely affect us, including the amount and timing of revenues, if any, we receive from our interests.
We own and generally anticipate that we will typically continue to own substantially less than a 50% working interest in our prospects and will therefore engage in joint operations with other working interest owners. Since we own or control less than a majority of the working interest in a prospect, decisions affecting the prospect could be made by the owners of a majority of the working interest. For instance, if we are unwilling or unable to participate in the costs of operations approved by a majority of the working interests in a well, our working interest in the well (and possibly other wells on the prospect) will likely be subject to contractual "non-consent penalties." These penalties may include, for example, full or partial forfeiture of our interest in the well or a relinquishment of our interest in production from the well in favor of the participating working interest owners until the participating working interest owners have recovered
a multiple of the costs which would have been borne by us if we had elected to participate, which often ranges from 400% to 600% of such costs.
We have pursued, and intend to continue to pursue, acquisitions. Our business may be adversely affected if we cannot effectively integrate acquired operations.
One of our business strategies has been to acquire operations and assets that are complementary to our existing businesses. Acquiring operations and assets involves financial, operational and legal risks. These risks include:
- inadvertently becoming subject to liabilities of the acquired company that were unknown to us at the time of the acquisition, such as later asserted litigation matters or tax liabilities;
- the difficulty of assimilating operations, systems and personnel of the acquired businesses; and
- maintaining uniform standards, controls, procedures and policies.
Competition from other potential buyers could cause us to pay a higher price than we otherwise might have to pay and reduce our acquisition opportunities. We are often out-bid by larger, better capitalized companies for acquisition opportunities we pursue. Moreover, our past success in making acquisitions and in integrating acquired businesses does not necessarily mean we will be successful in making acquisitions and integrating businesses in the future.
Operating hazards, including those peculiar to the marine environment, may adversely affect our ability to conduct business.
Our operations are subject to inherent risks normally associated with those operations, such as:
- pipeline ruptures;
- sudden violent expulsions of oil, gas and mud while drilling a well, commonly referred to as a blowout;
- a cave in and collapse of the earth's structure surrounding a well, commonly referred to as cratering;
- explosions;
- fires;
- pollution; and
- other environmental risks.
If any of these events were to occur, we could suffer substantial losses from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Our offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.
Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and results of operations.
We maintain several types of insurance to cover our operations, including maritime employer's liability and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies with maximum limits of $25 million. We also maintain operator's extra expense coverage, which covers the control of drilled or producing wells as well as re-drilling expenses and pollution coverage for wells out of control.
We may not be able to maintain adequate insurance in the future at rates we consider reasonable or losses may exceed the maximum limits under our insurance policies. In 2004, in connection with the implementation of certain cost saving measures, we cancelled the property insurance coverage on our pipelines. In 2005, we did not obtain property insurance coverage on our pipelines since we were not able to acquire the coverage at what we believed to be reasonable terms. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.
Compliance with environmental and other government regulations could be costly and could negatively impact our operations.
Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:
- require the acquisition of a permit before operations can be commenced;
- restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;
- limit or prohibit drilling and pipeline activities on certain lands lying within wilderness, wetlands and other protected areas;
- require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and abandoning pipelines; and
- impose substantial liabilities for pollution resulting from our operations.
The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and gas industry in general.
Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, including limited coverage for sudden and accidental environmental damages, but we do not believe that insurance coverage for all environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.
The OPA imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the OPA, could have a material adverse impact on us.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry.
BACK-IN AFTER PAYOUT INTEREST. A contractual right of a non-participating partner to participate in a well or wells after the wells have produced enough for the participating partners to recover their capital costs of drilling, completing, and operating the wells.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
BCF. One billion cubic feet of gas.
BTU OR BRITISH THERMAL UNIT. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CONDENSATE. Liquid hydrocarbons associated with the production of a primarily gas reserve.
DEVELOPMENT WELL. A well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
EXPLORATORY WELL. A well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir or to extend a known reservoir.
FIELD. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
LEASEHOLD INTEREST. The interest of a lessee under an oil and gas lease.
MBBLS. One thousand barrels of oil or other liquid hydrocarbons.
MCF. One thousand cubic feet of gas.
MCFE. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or gas liquids.
MMBTU. One million British Thermal Units.
MMCF. One million cubic feet of gas.
MMCFE. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.
NET REVENUE INTEREST. The percentage of production to which the owner of a working interest is entitled.
NONOPERATING WORKING INTEREST. A working interest, or a fraction of a working interest, in a lease where the owner is not the operator of the lease.
OVERRIDING ROYALTY. An interest in oil and gas produced at the surface, free of the expense of production that is in addition to the usual royalty interest reserved to the lessor in an oil and gas lease.
PROSPECT. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of oil, gas or both.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved developed reserves are further categorized into two sub-categories, proved developed producing reserves and proved developed non-producing reserves.
PROVED DEVELOPED PRODUCING. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate.
PROVED DEVELOPED NON-PRODUCING. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of producing for mechanical reasons.
PROVED RESERVES. The estimated quantities of oil, gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required for recompletion.
REVERSIONARY INTEREST. A form of ownership interest in property that reverts back to the transferor after expiration of an intervening income interest or the occurrence of another triggering event.
ROYALTY INTEREST. An interest in a gas and oil property entitling the owner to a share of gas and oil production free of costs of production.
UNDIVIDED INTEREST. A form of ownership interest in which more than one person concurrently owns an interest in the same oil and gas lease or pipeline.
WORKING INTEREST. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
